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Combined Management's Discussion and Analysis of Financial Condition and Results of Operations Overview II- 3 Results of Operations II- 8Southern Company II- 8Alabama Power II- 18Georgia Power II- 22Mississippi Power II- 27Southern Power II- 31Southern Company Gas II- 34 Future Earnings Potential II- 39 Accounting Policies II- 47 Financial Condition and Liquidity II- 55 This section generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K can be found in Item 7 of each Registrant's Annual Report on Form 10-K for the year endedDecember 31, 2020 , which was filed with theSEC onFebruary 17, 2021 . The following Management's Discussion and Analysis of Financial Condition and Results of Operations is a combined presentation; however, information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf and each Registrant makes no representation as to information related to the other Registrants.
Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See MANAGEMENT'S DISCUSSION AND ANALYSIS - FINANCIAL CONDITION AND LIQUIDITY -
"Market Price Risk" in Item 7 herein and Note 1 to the financial statements
under "Financial Instruments" in Item 8 herein. Also see Notes 13 and 14 to the
financial statements in Item 8 herein.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS Southern Company and Subsidiary Companies 2021 Annual Report OVERVIEW
Business Activities
Southern Company is a holding company that owns all of the common stock of three traditional electric operating companies,Southern Power , andSouthern Company Gas and owns other direct and indirect subsidiaries. The primary businesses ofthe Southern Company system are electricity sales by the traditional electric operating companies andSouthern Power and the distribution of natural gas bySouthern Company Gas .Southern Company's reportable segments are the sale of electricity by the traditional electric operating companies, the sale of electricity in the competitive wholesale market bySouthern Power , and the sale of natural gas and other complementary products and services bySouthern Company Gas . See Note 16 to the financial statements for additional information. •The traditional electric operating companies -Alabama Power ,Georgia Power , andMississippi Power - are vertically integrated utilities providing electric service to retail customers in three Southeastern states in addition to wholesale customers in the Southeast. •Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market.Southern Power continually seeks opportunities to execute its strategy to create value through various transactions including acquisitions, dispositions, and sales of partnership interests, development and construction of new generating facilities, and entry into PPAs primarily with investor-owned utilities, IPPs, municipalities, electric cooperatives, and other load-serving entities, as well as commercial and industrial customers. In general,Southern Power commits to the construction or acquisition of new generating capacity only after entering into or assuming long-term PPAs for the new facilities. •Southern Company Gas is an energy services holding company whose primary business is the distribution of natural gas.Southern Company Gas owns natural gas distribution utilities in four states -Illinois ,Georgia ,Virginia , andTennessee - and is also involved in several other complementary businesses.Southern Company Gas manages its business through three reportable segments - gas distribution operations, gas pipeline investments, and gas marketing services, which includes SouthStar, a Marketer and provider of energy-related products and services to natural gas markets - and one non-reportable segment, all other. Prior to the sale of Sequent onJuly 1, 2021 ,Southern Company Gas' reportable segments also included wholesale gas services. See Notes 7, 15, and 16 to the financial statements for additional information.Southern Company's other business activities include providing distributed energy and resilience solutions and deploying microgrids for commercial, industrial, governmental, and utility customers, as well as investments in telecommunications and gas storage facilities. Management continues to evaluate the contribution of each of these activities to total shareholder return and may pursue acquisitions, dispositions, and other strategic ventures or investments accordingly. See FUTURE EARNINGS POTENTIAL herein for a discussion of the many factors that could impact the Registrants' future results of operations, financial condition, and liquidity. Recent DevelopmentsSouthern Company OnOctober 29, 2021 ,Southern Company completed the sale of assets subject to a domestic leveraged lease to the lessee for$45 million . No gain or loss was recognized on the sale. OnDecember 13, 2021 ,Southern Company completed the termination of its leasehold interest in assets associated with its two international leveraged lease projects and received cash proceeds of approximately$673 million after the accelerated exercise of the lessee's purchase options. The pre-tax gain associated with the transaction was approximately$93 million ($99 million gain after tax). See Note 15 to the financial statements under "Southern Company " for additional information.
OnSeptember 23, 2021 ,Alabama Power entered into an agreement to acquire all of the equity interests inCalhoun Power Company, LLC , which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility inCalhoun County, Alabama (Calhoun Generating Station ). The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and theFERC . OnOctober 28, 2021 ,Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through this acquisition. The ultimate outcome of this matter cannot be determined at this time. II-3 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
During 2021,
For the year endedDecember 31, 2021 ,Alabama Power's weighted common equity return exceeded 6.15%, resulting inAlabama Power establishing a current regulatory liability of$181 million . In accordance with an Alabama PSC order issued onFebruary 1, 2022 ,Alabama Power will apply$126 million to reduce the Rate ECR under recovered balance and the remaining$55 million will be refunded to customers through bill credits inJuly 2022 .
See Note 2 to the financial statements under "
Plant Vogtle Units 3 and 4 Construction and Start-Up Status
Construction continues on Plant Vogtle Units 3 and 4 (with electric generating capacity of approximately 1,100 MWs each), in whichGeorgia Power holds a 45.7% ownership interest.Georgia Power's share of the total project capital cost forecast to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is$10.4 billion .Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. The continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4. During 2021, Southern Nuclear performed additional construction remediation work necessary to ensure quality and design standards are met and support system turnovers necessary for Unit 3 hot functional testing, which was completed inJuly 2021 , and fuel load. As a result of Unit 3 challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional and other testing, at the end of each of the second and third quarters 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established inJanuary 2021 . Through the fourth quarter 2021, the project continued to face these and other challenges related to the completion of documentation, including inspection records, necessary to submit the remaining ITAACs and begin fuel load. As a result, at the end of the fourth quarter 2021, Southern Nuclear further extended certain milestone dates, including fuel load for Unit 3, from those established at the end of the third quarter 2021. The site work plan currently targets fuel load for Unit 3 in the second quarter 2022 and an in-service date during the third quarter 2022 and primarily depends on significant improvements in overall construction productivity and production levels, the volume of construction remediation work, the pace of system and area turnovers, and the progression of startup and other testing. As the site work plan includes minimal margin to these milestone dates, an in-service date during the fourth quarter 2022 or the first quarter 2023 for Unit 3 is projected, although any further delays could result in a later in-service date. As the result of productivity challenges and temporarily diverting some Unit 4 craft and support resources to Unit 3 construction efforts, at the end of each of the second and third quarters 2021, Southern Nuclear also further extended milestone dates for Unit 4 from those established inJanuary 2021 . The temporary diversion of Unit 4 resources to support Unit 3 has continued into the first quarter 2022; therefore, at the end of the fourth quarter 2021, Southern Nuclear further extended milestone dates for Unit 4 from those established at the end of the third quarter 2021. The site work plan targets an in-service date during the first quarter 2023 for Unit 4 and primarily depends on overall construction productivity and production levels significantly improving as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As the site work plan includes minimal margin to the milestone dates, an in-service date during the third or fourth quarter 2023 for Unit 4 is projected, although any further delays could result in a later in-service date. The latest schedule extension triggers the requirement that the holders of at least 90% of the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue construction byMarch 8, 2022 .Georgia Power has voted to continue construction. In addition, if the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 do not vote to continue construction, theDOE may requireGeorgia Power to prepay all outstanding borrowings under the FFB Credit Facilities over a period of five years. See Note 8 to the financial statements under "Long-term Debt - DOE Loan Guarantee Borrowings" for additional information. During 2021, established construction contingency and additional costs totaling$1.3 billion were assigned to the base capital cost forecast for costs primarily associated with schedule extensions, construction productivity, the pace of system turnovers, and support resources for Units 3 and 4.Georgia Power also increased its total capital cost forecast as ofDecember 31, 2021 by$99 million to replenish construction contingency. II-4 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings,Georgia Power recorded pre-tax charges to income in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021 of$48 million ($36 million after tax),$460 million ($343 million after tax),$264 million ($197 million after tax), and$480 million ($358 million after tax), respectively, for the increases in the total project capital cost forecast.Georgia Power may request the Georgia PSC to evaluate those expenditures for rate recovery during the prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM stipulation described in Note 2 to the financial statements under "Georgia Power -Nuclear Construction - Regulatory Matters." In addition,Georgia Power recorded a pre-tax charge to income in the fourth quarter 2021 of approximately$440 million ($328 million after tax), and may be required to record additional pre-tax charges to income of up to$460 million , associated with the cost-sharing and tender provisions of the joint ownership agreements based on the current project capital cost forecast. The incremental costs associated with these provisions will not be recovered from retail customers. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction - Joint Owner Contracts" for additional information.
The ultimate impact of the COVID-19 pandemic and other factors on the
construction schedule and budget for Plant Vogtle Units 3 and 4 cannot be
determined at this time. See Note 2 to the financial statements under "
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
OnNovember 2, 2021 , the Georgia PSC approvedGeorgia Power's application to adjust retail base rates to include a portion of costs related to its investment in Plant Vogtle Unit 3 and the common facilities shared betweenPlant Vogtle Units 3 and 4 (Common Facilities), as well as the related costs of operation, as modified pursuant to a stipulated agreement betweenGeorgia Power and the staff of the Georgia PSC. The related increase in annual retail base rates of approximately$302 million includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase is partially offset by a decrease in the NCCR tariff of approximately$78 million that became effectiveJanuary 1, 2022 . See Note 2 to the financial statements under "Georgia Power - Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" for additional information.
Rate Plans
OnNovember 18, 2021 , in accordance with the terms of the 2019 ARP, theGeorgia PSC approved tariff adjustments effectiveJanuary 1, 2022 resulting in a net increase in annual retail base rates of$157 million .Georgia Power is required to file its next general base rate case byJuly 1, 2022 . See Note 2 to the financial statements under "Georgia Power - Rate Plans - 2019 ARP" for additional information.
Integrated Resource Plan
OnJanuary 31, 2022 ,Georgia Power filed its triennial IRP (2022 IRP), including a request to decertify and retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership) byAugust 31, 2022 ; Plant Bowen Units 1 and 2 (1,400 MWs) byDecember 31, 2027 ; and Plant Scherer Unit 3 (614 MWs based on 75% ownership) and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership through SEGCO) byDecember 31, 2028 . In the 2022 IRP,Georgia Power requested approval to reclassify the remaining net book value of Plant Wansley Units 1 and 2 (approximately$611 million atDecember 31, 2021 ), Plant Bowen Units 1 and 2 (approximately$937 million atDecember 31, 2021 ), and Plant Scherer Unit 3 (approximately$612 million atDecember 31, 2021 ) and any remaining unusable materials and supplies inventories upon each unit's respective retirement dates to a regulatory asset, with recovery periods to be determined in future base rate cases. The 2022 IRP also included a request for approval of the capital, operations and maintenance, and CCR ARO costs associated with ash pond and landfill closures and post-closure care. The recovery of these costs is expected to be determined in future base rate cases. A decision from the Georgia PSC on the 2022 IRP is expected inJuly 2022 . The ultimate outcome of these matters cannot be determined at this time. See Note 2 to the financial statements under "Georgia Power - Integrated Resource Plan" for additional information. II-5 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
During the first half of 2021, the Mississippi PSC approved the following
non-fuel rate changes related to
•an increase in revenues related to the ad valorem tax adjustment factor of
approximately
•an increase in revenues related to PEP of approximately$16 million annually, which became effective with the first billing cycle ofApril 2021 in accordance with the PEP rate schedule, and
•a decrease in revenues related to the
OnSeptember 9, 2021 , the Mississippi PSC issued an order confirming the conclusion of its review ofMississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) andMississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) inDecember 2023 , 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement ofMississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. In accordance with an accounting order issued by the Mississippi PSC onOctober 14, 2021 ,Mississippi Power reclassified$49 million of retail costs associated with Hurricanes Zeta and Ida to a regulatory asset to be recovered through PEP over a period to be determined inMississippi Power's 2022 PEP proceeding. In addition, onDecember 7, 2021 , the Mississippi PSC approvedMississippi Power's annual SRR filing, which requested an increase in retail revenues of approximately$9 million annually effective with the first billing cycle ofMarch 2022 to restore the property damage reserve. OnJanuary 18, 2022 , the Mississippi PSC approvedMississippi Power's retail fuel cost recovery filing, which requested an increase in revenues of approximately$43 million annually effective with the first billing cycle ofFebruary 2022 .
See Note 2 to the financial statements under "
Southern Power During 2021,Southern Power completed construction of and placed in service the 118-MW Glass Sands wind facility, 73 MWs of the 88-MW Garland battery energy storage facility, and 32 MWs of the 72-MW Tranquillity battery energy storage facility.Southern Power continues construction of the remainder of the Garland and Tranquillity battery energy storage facilities. OnMarch 26, 2021 ,Southern Power purchased a controlling membership interest in the 300-MW Deuel Harvest wind facility located inDeuel County, South Dakota fromInvenergy Renewables LLC .Southern Power calculates an investment coverage ratio for its generating assets, including those owned with various partners, based on the ratio of investment under contract to total investment using the respective facilities' net book value (or expected in-service value for facilities under construction) as the investment amount. With the inclusion of investments associated with the facilities currently under construction, as well as other capacity and energy contracts,Southern Power's average investment coverage ratio atDecember 31, 2021 was 95% through 2026 and 92% through 2031, with an average remaining contract duration of approximately 13 years.
See Note 15 to the financial statements under "
Southern Company Gas OnApril 28, 2021 ,Atlanta Gas Light filed its first Integrated Capacity and Delivery Plan (i-CDP) with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years, as well as the required capital investments and related costs to implement the programs. OnNovember 18, 2021 , the Georgia PSC approved anOctober 14, 2021 joint stipulation agreement betweenAtlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024,Atlanta Gas Light will incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% throughAtlanta Gas Light's GRAM mechanism, or$5 million for 2022. The stipulation agreement also provides for$1.7 billion of total capital investment for the years 2022 through 2024. Also onNovember 18, 2021 , the Georgia PSC approvedAtlanta Gas Light's amended annual GRAM filing, which resulted in an annual rate increase of$43 million effectiveJanuary 1, 2022 . II-6 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
OnSeptember 14, 2021 , theVirginia Commission approved a stipulation agreement related toVirginia Natural Gas' June 2020 general rate case filing, which allows for a$43 million increase in annual base rate revenues, including$14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as ofNovember 1, 2020 , subject to refund, based onVirginia Natural Gas' original request for an increase of approximately$50 million . Refunds to customers related to the difference between the approved rates and the interim rates were completed during the fourth quarter 2021. OnNovember 18, 2021 , theIllinois Commission approved a$240 million annual base rate increase forNicor Gas effectiveNovember 24, 2021 . The base rate increase included$94 million related to the recovery of program costs under the Investing inIllinois program and was based on a ROE of 9.75% and an equity ratio of 54.5%.
See Note 2 to the financial statements under "
OnJuly 1, 2021 ,Southern Company Gas affiliates completed the sale of Sequent toWilliams Field Services Group for a total cash purchase price of$159 million , including final working capital adjustments. The pre-tax gain associated with the transaction was approximately$121 million ($92 million after tax). As a result of the sale, changes in state apportionment rates resulted in$85 million of additional tax expense. See Note 15 to the financial statements under "Southern Company Gas " for additional information. During the second and third quarters of 2021,Southern Company Gas recorded pre-tax impairment charges totaling$84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. OnSeptember 27, 2021 , PennEast Pipeline announced that further development of the project is no longer supported, and, as a result, all further development of the project has ceased. See Note 7 to the financial statements under "Southern Company Gas " for additional information. Key Performance Indicators In striving to achieve attractive risk-adjusted returns while providing cost-effective energy to approximately 8.7 million electric and gas utility customers collectively, the traditional electric operating companies andSouthern Company Gas continue to focus on several key performance indicators. These indicators include, but are not limited to, customer satisfaction, plant availability, electric and natural gas system reliability, and execution of major construction projects. In addition,Southern Company and the Subsidiary Registrants focus on earnings per share (EPS) and net income, respectively, as a key performance indicator. See RESULTS OF OPERATIONS herein for information on the Registrants' financial performance. See RESULTS OF OPERATIONS - "Southern Company Gas - Operating Metrics" for additional information onSouthern Company Gas' operating metrics, including Heating Degree Days, customer count, and volumes of natural gas sold. The financial success of the traditional electric operating companies andSouthern Company Gas is directly tied to customer satisfaction. Key elements of ensuring customer satisfaction include outstanding service, high reliability, and competitive prices. The traditional electric operating companies use customer satisfaction surveys to evaluate their results and generally target the top quartile of these surveys in measuring performance. Reliability indicators are also used to evaluate results. See Note 2 to the financial statements under "Alabama Power - Rate RSE" and "Mississippi Power - Performance Evaluation Plan" for additional information onAlabama Power's Rate RSE and Mississippi Power's PEP rate plan, respectively, both of which contain mechanisms that directly tie customer service indicators to the allowed equity return.Southern Power continues to focus on several key performance indicators, including, but not limited to, the equivalent forced outage rate and contract availability to evaluate operating results and help ensure its ability to meet its contractual commitments to customers. II-7 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
RESULTS OF OPERATIONS
Consolidated net income attributable toSouthern Company was$2.4 billion in 2021, a decrease of$726 million , or 23.3%, from 2020. The decrease was primarily due to a$1.0 billion increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4 and higher non-fuel operations and maintenance costs, partially offset by an increase in natural gas revenues associated with colder weather in the first quarter 2021 as compared to the corresponding period in 2020 and infrastructure replacement programs and base rate changes, higher retail electric revenues primarily associated with rates and pricing and sales growth, a decrease in impairment charges and a gain on termination related to leveraged leases atSouthern Holdings , and higher wholesale electric capacity revenues. See Notes 2, 9, and 15 to the financial statements under "Georgia Power -Nuclear Construction ," "Southern Company Leveraged Lease," and "Southern Company ," respectively, for additional information. Basic EPS was$2.26 in 2021 and$2.95 in 2020. Diluted EPS, which factors in additional shares related to stock-based compensation, was$2.24 in 2021 and$2.93 in 2020. EPS for 2021 and 2020 was negatively impacted by$0.01 and$0.03 per share, respectively, as a result of increases in the average shares outstanding. See Note 8 to the financial statements under "Outstanding Classes of Capital Stock -Southern Company " for additional information. Dividends paid per share of common stock were$2.62 in 2021 and$2.54 in 2020. InJanuary 2022 ,Southern Company declared a quarterly dividend of66 cents per share. For 2021, the dividend payout ratio was 116% compared to 86% for 2020. Discussion ofSouthern Company's results of operations is divided into three parts -the Southern Company system's primary business of electricity sales, its gas business, and its other business activities. 2021 2020 (in millions) Electricity business$ 2,247 $ 3,115 Gas business 539 590 Other business activities (393) (586) Net Income$ 2,393 $ 3,119 II-8
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Electricity Business
Southern Company's electric utilities generate and sell electricity to retail and wholesale customers. A condensed statement of income for the electricity business follows: Increase (Decrease) from 2021 2020 (in millions) Electric operating revenues$ 18,300 $ 1,803 Fuel 4,010 1,043 Purchased power 978 179 Cost of other sales 109 15 Other operations and maintenance 4,809 559 Depreciation and amortization 2,953 12 Taxes other than income taxes 1,062 38 Estimated loss on Plant Vogtle Units 3 and 4 1,692 1,367 Impairment charges 2 2 Gain on dispositions, net (59) (17) Total electric operating expenses 15,556 3,198 Operating income 2,744 (1,395) Allowance for equity funds used during construction 179 41 Interest expense, net of amounts capitalized 968 (8) Other income (expense), net 427 112 Income taxes 219 (298) Net income 2,163 (936) Less: Dividends on preferred stock of subsidiaries 15 - Net loss attributable to noncontrolling interests (99) (68) Net Income Attributable to Southern Company$ 2,247 $ (868)
Electric Operating Revenues
Electric operating revenues for 2021 were$18.3 billion , reflecting a$1.8 billion , or 10.9%, increase from 2020. Details of electric operating revenues were as follows: 2021 2020 (in millions) Retail electric - prior year$ 13,643 Estimated change resulting from - Rates and pricing 209 Sales growth 208 Weather (74) Fuel and other cost recovery 866 Retail electric - current year$ 14,852 $ 13,643 Wholesale electric revenues 2,455 1,945 Other electric revenues 718 672 Other revenues 275 237 Electric operating revenues$ 18,300 $ 16,497 II-9
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Retail electric revenues increased$1.2 billion , or 8.9%, in 2021 as compared to 2020. The significant factors driving this change are shown in the preceding table. The increase in rates and pricing in 2021 was primarily due to an increase effectiveJanuary 1, 2021 inAlabama Power's Rate RSE, net of a related customer refund, and increases atGeorgia Power resulting from higher contributions by commercial and industrial customers with variable demand-driven pricing, fixed residential customer bill programs, the effects of higher KWH sales on ECCR tariff revenues, and base tariff increases in accordance with the 2019 ARP, partially offset by a decrease inGeorgia Power's NCCR tariff, both effectiveJanuary 1, 2021 . Electric rates for the traditional electric operating companies include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of PPA costs, and do not affect net income. The traditional electric operating companies each have one or more regulatory mechanisms to recover other costs such as environmental and other compliance costs, storm damage, new plants, and PPA capacity costs. See Note 2 to the financial statements under "Alabama Power " and "Georgia Power " for additional information. Also see "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales growth (decline) and weather. Wholesale electric revenues consist of revenues from PPAs and short-term opportunity sales. Wholesale electric revenues from PPAs (other than solar and wind PPAs) have both capacity and energy components. Capacity revenues generally represent the greatest contribution to net income and are designed to provide recovery of fixed costs plus a return on investment. Energy revenues will vary depending on fuel prices, the market prices of wholesale energy compared tothe Southern Company system's generation, demand for energy withinthe Southern Company system's electric service territory, and the availability ofthe Southern Company system's generation. Increases and decreases in energy revenues that are driven by fuel prices are accompanied by an increase or decrease in fuel costs and do not have a significant impact on net income. Energy sales from solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or through a fixed price related to the energy. As a result, the ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Wholesale electric revenues atMississippi Power includeFERC -regulated MRA sales under cost-based tariffs as well as market-based sales. Short-term opportunity sales are made at market-based rates that generally provide a margin abovethe Southern Company system's variable cost to produce the energy.
Wholesale electric revenues from power sales were as follows:
2021 2020
(in millions)
Capacity and other $ 550 $ 476
Energy 1,905 1,469
Total $ 2,455 $ 1,945
In 2021, wholesale electric revenues increased $510 million , or 26.2%, as
compared to 2020 due to increases of $436 million in energy revenues and $74
million in capacity revenues. Energy revenues increased $292 million at Southern
Power primarily from a $247 million net increase in the price of energy and a
$45 million increase in the volume of KWHs sold. Energy revenues increased $144
million at the traditional electric operating companies primarily due to higher
energy prices. The increase in capacity revenues primarily resulted from a power
sales agreement at Alabama Power that began in September 2020 and a net increase
in natural gas PPAs at Southern Power .
Other Electric Revenues
Other electric revenues increased$46 million , or 6.8%, in 2021 as compared to 2020. The increase was primarily due to increases of$28 million in transmission revenues primarily related to new PPAs atSouthern Power and increased open access transmission tariff sales atAlabama Power ,$27 million in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020 for the traditional electric operating companies,$11 million from outdoor lighting sales atGeorgia Power , and$10 million in cogeneration steam revenue associated with higher natural gas prices atAlabama Power , partially offset by a$26 million decrease in pole attachment revenues atGeorgia Power . II-10 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2021 and the percent change from 2020 were
as follows:
2021
Total Total KWH Weather-Adjusted
KWHs Percent Change Percent Change(*)
(in billions)
Residential 47.4 (0.2) % 0.5 %
Commercial 46.7 2.7 3.2
Industrial 48.7 3.7 3.7
Other 0.6 (5.1) (5.1)
Total retail 143.4 2.0 2.4 %
Wholesale 50.0 9.5
Total energy sales 193.4 3.8 %
(*)Weather-adjusted KWH sales are estimated using statistical models of the
historical relationship between temperatures and energy sales, and then removing
the estimated effect of deviations from normal temperature conditions. Normal
temperature conditions are defined as those experienced in the applicable
service territory over a specified historical period. This metric is useful
because it allows trends in historical operations to be evaluated apart from the
influence of weather conditions. Management also considers this metric in
developing long-term capital and financial plans.
Changes in retail energy sales are generally the result of changes in
electricity usage by customers, weather, and the number of customers.
Weather-adjusted retail energy sales increased 3.4 billion KWHs in 2021 as
compared to 2020. Weather-adjusted residential usage increased primarily due to
customer growth, largely offset by decreased customer usage resulting from
shelter-in-place orders in effect during 2020. Weather-adjusted commercial and
industrial usage increased primarily due to the negative impacts of the COVID-19
pandemic on energy sales being more severe in 2020.
See "Electric Operating Revenues" above for a discussion of significant changes in wholesale revenues related to changes in price and KWH sales.
Other Revenues
Other revenues increased$38 million , or 16.0%, in 2021 as compared to 2020. The increase was primarily due to increases in unregulated sales of products and services of$29 million atAlabama Power and$9 million atGeorgia Power .
Fuel and Purchased Power Expenses
The mix of fuel sources for the generation of electricity is determined
primarily by demand, the unit cost of fuel consumed, and the availability of
generating units. Additionally, the electric utilities purchase a portion of
their electricity needs from the wholesale market.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Details ofthe Southern Company system's generation and purchased power were as follows: 2021 2020 Total generation (in billions of KWHs)(a) 179
174
Total purchased power (in billions of KWHs) 18
18
Sources of generation (percent) - Gas 48 52 Coal 22 18 Nuclear 18 18 Hydro 4 4 Wind, Solar, and Other 8 8 Cost of fuel, generated (in cents per net KWH) - Gas(a) 3.07 2.03 Coal 2.85 2.91 Nuclear 0.75 0.78
Average cost of fuel, generated (in cents per net KWH)(a) 2.55 1.96 Average cost of purchased power (in cents per net KWH)(b) 5.85 4.65
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power " for additional information.
(b)Average cost of purchased power includes fuel purchased by
In 2021, total fuel and purchased power expenses were$5.0 billion , an increase of$1.2 billion , or 32.4%, as compared to 2020. The increase was primarily the result of a$1.1 billion increase in the average cost of fuel generated and purchased and a$170 million increase in the volume of KWHs generated and purchased. Fuel and purchased power energy transactions at the traditional electric operating companies are generally offset by fuel revenues and do not have a significant impact on net income. See Note 2 to the financial statements for additional information. Fuel expenses incurred underSouthern Power's PPAs are generally the responsibility of the counterparties and do not significantly impact net income.
Fuel
In 2021, fuel expense was$4.0 billion , an increase of$1.0 billion , or 35.2%, as compared to 2020. The increase was primarily due to a 51.2% increase in the average cost of natural gas per KWH generated, a 25.7% increase in the volume of KWHs generated by coal, and a 12.2% decrease in the volume of KWHs generated by hydro, partially offset by a 4.9% decrease in the volume of KWHs generated by natural gas.Purchased Power In 2021, purchased power expense was$978 million , an increase of$179 million , or 22.4%, as compared to 2020. The increase was primarily due to a 25.8% increase in the average cost per KWH purchased primarily due to higher natural gas prices. Energy purchases will vary depending on demand for energy withinthe Southern Company system's electric service territory, the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, and the availability ofthe Southern Company system's generation.
Cost of Other Sales
Cost of other sales increased
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased$559 million , or 13.2%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily associated with increases of$174 million in transmission and distribution expenses, including$37 million of reliability NDR credits applied in 2020 atAlabama II-12 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Power,$133 million in scheduled generation outage and maintenance expenses, and$63 million in compensation and benefit expenses, as well as a$40 million loss on sales-type leases associated with PPAs atSouthern Power's Garland and Tranquillity battery energy storage facilities. Also contributing to the increase was a$19 million increase in compliance and environmental expenses at the traditional electric operating companies and an$18 million decrease in nuclear property insurance refunds atAlabama Power andGeorgia Power . See Notes 2 and 9 to the financial statements under "Alabama Power - Rate NDR" and "Lessor," respectively, for additional information.
Depreciation and Amortization
Depreciation and amortization increased$12 million , or 0.4%, in 2021 as compared to 2020. The increase was due to an increase of$111 million in depreciation associated with additional plant in service, partially offset by a net decrease of$90 million in amortization of regulatory assets primarily associated with CCR AROs under the terms ofGeorgia Power's 2019 ARP. See Note 2 to the financial statements under "Georgia Power - Rate Plans" for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes increased$38 million , or 3.7%, in 2021 as compared to 2020. The increase primarily reflects a$25 million increase in municipal franchise fees atGeorgia Power and a$21 million increase in property taxes primarily resulting from higher assessed values, partially offset by a$14 million decrease in utility license taxes atAlabama Power .
Estimated Loss on Plant Vogtle Units 3 and 4
Estimated probable loss on Plant Vogtle Units 3 and 4 increased$1.4 billion in 2021 as compared to 2020. The losses in each year were recorded to reflectGeorgia Power's revised total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information. Gain on Dispositions,Net Gain on dispositions, net increased$17 million , or 40.5%, in 2021 as compared to 2020. The increase primarily reflects$41 million in gains atSouthern Power primarily due to contributions of wind turbine equipment to various equity method investments in the first quarter 2021 and$14 million in gains atAlabama Power primarily from property sales, partially offset by a$39 million gain atSouthern Power related to the sale of Plant Mankato in the first quarter 2020. See Notes 7 and 15 to the financial statements under "Southern Power " for additional information.
Allowance for
Allowance for equity funds used during construction increased$41 million , or 29.7%, in 2021 as compared to 2020. The increase was primarily associated withGeorgia Power's construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction - Regulatory Matters" for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased$8 million , or 0.8%, in 2021 as compared to 2020 primarily due to a decrease of approximately$30 million due to lower interest rates at the traditional electric operating companies and an$11 million net increase in capitalized interest, partially offset by an increase of approximately$33 million due to an increase in average outstanding long-term borrowings. See Note 8 to the financial statements for additional information. Other Income (Expense), Net Other income (expense), net increased$112 million , or 35.6%, in 2021 as compared to 2020 primarily related to a$135 million increase in non-service cost-related retirement benefits income, partially offset by a$12 million gain recorded bySouthern Power in the third quarter 2020 associated with the Roserock solar facility litigation and an$8 million decrease in interest income. See Note 11 to the financial statements for additional information.
Income Taxes
Income taxes decreased$298 million , or 57.6%, in 2021 as compared to 2020. The decrease was primarily due to lower pre-tax earnings primarily resulting from higher charges in 2021 associated with the construction of Plant Vogtle Units 3 and 4 atGeorgia Power and changes in state apportionment methodology resulting from tax legislation enacted by theState of Alabama inFebruary 2021 atSouthern Power , partially offset by an increase in a valuation allowance on certain state tax credit carryforwards II-13 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
atGeorgia Power . See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " and Note 10 to the financial statements for additional information.
Net Loss Attributable to Noncontrolling Interests
Substantially all noncontrolling interests relate to renewable projects atSouthern Power . Net loss attributable to noncontrolling interests increased$68 million in 2021 as compared to 2020. The increased loss was primarily due to loss allocations toSouthern Power's partners in the Garland and Tranquillity battery energy storage facilities, including$26 million allocated from the loss on sales-type leases. In addition, the increased loss was due to higher HLBV loss allocations toSouthern Power's wind tax equity partners, including new partnerships entered into during 2020 and 2021, and lower income allocations toSouthern Power's solar equity partners, totaling$29 million . See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power ," respectively, for additional information. Gas BusinessSouthern Company Gas distributes natural gas through utilities in four states and is involved in several other complementary businesses including gas pipeline investments, wholesale gas services (until the sale of Sequent onJuly 1, 2021 ), and gas marketing services.
A condensed statement of income for the gas business follows:
Increase
(Decrease) from
2021 2020
(in millions)
Operating revenues $ 4,380 $ 946
Cost of natural gas 1,619 647
Other operations and maintenance 1,072 106
Depreciation and amortization 536 36
Taxes other than income taxes 225 19
Gain on dispositions, net (127) (105)
Total operating expenses 3,325 703
Operating income 1,055 243
Earnings from equity method investments 50 (91)
Interest expense, net of amounts capitalized 238 7
Other income (expense), net (53) (94)
Income taxes 275 102
Net income $ 539 $ (51)
Seasonality of Results
During the period from November through March when natural gas usage and
operating revenues are generally higher (Heating Season), more customers are
connected to Southern Company Gas' distribution systems and natural gas usage is
higher in periods of colder weather. Prior to the sale of Sequent, wholesale gas
services' operating revenues were occasionally impacted due to peak usage by
power generators in response to summer energy demands. Southern Company Gas'
base operating expenses, excluding cost of natural gas, bad debt expense, and
certain incentive compensation costs, are incurred relatively equally over any
given year. Thus, operating results can vary significantly from quarter to
quarter as a result of seasonality. For 2021, the percentage of operating
revenues and net income generated during the Heating Season (January through
March and November through December) were 70% and 102%, respectively. For 2020,
the percentage of operating revenues and net income generated during the Heating
Season were 68% and 86%, respectively.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues
Operating revenues in 2021 were
2021
(in millions)
Operating revenues - prior year $ 3,434
Estimated change resulting from -
Infrastructure replacement programs and base rate changes 146
Gas costs and other cost recovery 675
Wholesale gas services 114
Other 11
Operating revenues - current year $ 4,380
Revenues at the natural gas distribution utilities increased in 2021 compared to
2020 due to rate increases and continued investment in infrastructure
replacement. See Note 2 to the financial statements under "Southern Company Gas "
for additional information.
Revenues associated with gas costs and other cost recovery increased in 2021
compared to 2020 primarily due to higher natural gas cost recovery as a result
of higher volumes of natural gas sold and an increase in natural gas prices. The
natural gas distribution utilities have weather or revenue normalization
mechanisms that mitigate revenue fluctuations from customer consumption changes.
Natural gas distribution rates include provisions to adjust billings for
fluctuations in natural gas costs. Therefore, gas costs recovered through
natural gas revenues generally equal the amount expensed in cost of natural gas
and do not affect net income from the natural gas distribution utilities. See
"Cost of Natural Gas" herein for additional information.
Revenues from wholesale gas services increased in 2021 primarily due to higher
volumes of natural gas sold and higher commercial activities as a result of
Winter Storm Uri, partially offset by derivative losses, all prior to the sale
of Sequent. See Note 15 to the financial statements under "Southern Company Gas "
for additional information.
Cost of Natural Gas
ExcludingAtlanta Gas Light , which does not sell natural gas to end-use customers, the natural gas distribution utilities charge their utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The natural gas distribution utilities defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from the natural gas distribution utilities. Cost of natural gas at the natural gas distribution utilities represented 86.3% of the total cost of natural gas for 2021. Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, if applicable, and gains and losses associated with certain derivatives.
Cost of natural gas was
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased$106 million , or 11.0%, in 2021 compared to 2020. The increase was primarily due to increases of$60 million in compensation expenses,$30 million of which was at Sequent,$10 million in facility costs, and$10 million in bad debt expense, which is passed through directly to customers and has no impact on net income. II-15 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Depreciation and Amortization
Depreciation and amortization increased$36 million , or 7.2%, in 2021 compared to 2020. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes increased$19 million , or 9.2%, in 2021 compared to 2020. The increase was primarily due to a$15 million increase in revenue tax expenses as a result of higher natural gas revenues atNicor Gas , which are passed through directly to customers and have no impact on net income.
Gain on Dispositions, Net
Gain on dispositions, net increased$105 million in 2021 compared to 2020. In 2021,Southern Company Gas recorded a$121 million gain on the sale of Sequent, as well as an additional$5 million gain from the sale of Pivotal LNG. In 2020,Southern Company Gas recorded a$22 million gain on the sale ofJefferson Island . See Note 15 to the financial statements under "Southern Company Gas " for additional information.
Earnings from Equity Method Investments
Earnings from equity method investments decreased$91 million , or 64.5%, in 2021 compared to 2020. The decrease was primarily due to impairment charges in 2021 totaling$84 million related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas " for additional information.
Other Income (Expense), Net
Other income (expense), net decreased$94 million in 2021 compared to 2020. The decrease was largely due to$101 million in charitable contributions by Sequent prior to its sale. Income Taxes Income taxes increased$102 million , or 59.0%, in 2021 compared to 2020. The increase was primarily due to$114 million in additional tax expense resulting from the sale of Sequent, including changes in state tax apportionment rates, and higher pre-tax earnings at the natural gas distribution utilities, partially offset by$18 million of tax benefit resulting from the PennEast Pipeline project impairment charges in the second and third quarters of 2021. See Notes 7 and 15 to the financial statements under "Southern Company Gas " and Note 10 to the financial statements for additional information.
Other Business Activities
Southern Company's other business activities primarily include the parent company (which does not allocate operating expenses to business units); PowerSecure, which provides distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers;Southern Holdings , which invests in various projects; and Southern Linc, which provides digital wireless communications for use bythe Southern Company system and also markets these services to the public and provides fiber optics services within the Southeast. II-16 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
A condensed statement of operations forSouthern Company's other business activities follows: 2021 Increase (Decrease) from 2020 (in millions) Operating revenues$ 433 $ (11) Cost of other sales 249 15 Other operations and maintenance 207 11 Depreciation and amortization 75 (2) Taxes other than income taxes 4 - Gain on dispositions, net - 1 Total operating expenses 535 25 Operating income (loss) (102) (36) Earnings from equity method investments 26
14
Interest expense 631
17
Impairment of leveraged leases 7
(199)
Other income (expense), net 94 103 Income taxes (benefit) (227) 70 Net loss$ (393) $ 193 Operating RevenuesSouthern Company's operating revenues for these other business activities decreased$11 million , or 2.5%, in 2021 as compared to 2020 primarily due to a decrease at Southern Linc related to a contract for the design and construction of a fiber optic system completed in 2020.
Cost of Other Sales
Cost of other sales for these other business activities increased$15 million , or 6.4%, in 2021 as compared to 2020 primarily due to distributed infrastructure projects at PowerSecure.
Other Operations and Maintenance Expenses
Other operations and maintenance expenses for these other business activities increased$11 million , or 5.6%, in 2021 as compared to 2020. The increase was primarily due to a$16 million increase at the parent company primarily related to director compensation expenses and an$11 million increase at PowerSecure primarily associated with higher bad debt expense, partially offset by a$17 million decrease at Southern Linc primarily related to the design and construction of a fiber optic system completed in 2020.
Earnings from Equity Method Investments
Earnings from equity method investments for these other business activities
increased
Interest Expense
Interest expense for these other business activities increased$17 million , or 2.8%, in 2021 as compared to 2020 primarily due to an increase of approximately$64 million related to higher average outstanding long-term borrowings, partially offset by decreases of approximately$34 million due to lower interest rates and$6 million due to a reduction in losses associated with the extinguishment of debt at the parent company. See Note 8 to the financial statements for additional information.
Impairment of Leveraged Leases
Impairment charges related to leveraged lease investments atSouthern Holdings decreased$199 million , or 96.6%, in 2021 as compared to 2020. See Notes 9 and 15 to the financial statements under "Southern Company Leveraged Lease" and "Southern Company ," respectively, for additional information. II-17 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Other Income (Expense), Net
Other income (expense), net for these other business activities increased$103 million in 2021 as compared to 2020 primarily due to a$93 million pre-tax gain ($99 million gain after tax) recorded atSouthern Holdings in 2021 related to the termination of leveraged leases and a$12 million decrease in charitable donations at the parent company. See Note 15 to the financial statements under "Southern Company " for additional information.
Income Taxes (Benefit)
The income tax benefit for these other business activities decreased$70 million , or 23.6%, in 2021 as compared to 2020 primarily due to the tax impacts related to the 2020 charges associated with leveraged lease investments and the 2021 leveraged lease dispositions atSouthern Holdings , partially offset by lower pre-tax earnings at the parent company. See Notes 9, 10, and 15 to the financial statements under "Southern Company Leveraged Lease," "Effective Tax Rate," and "Southern Company ," respectively, for additional information.
Alabama Power's 2021 net income after dividends on preferred stock was$1.24 billion , representing an$88 million , or 7.7%, increase from 2020. The increase was primarily due to an increase in retail revenues associated with an adjustment effective inJanuary 2021 to Rate RSE, net of a related customer refund, and higher customer usage. Also contributing to the increase were additional wholesale capacity revenues related to a power sales agreement that began inSeptember 2020 and increased sales of unregulated products and services. These increases to income were partially offset by increases in operations and maintenance expenses and depreciation. See Note 2 to the financial statements under "Alabama Power - Rate RSE" for additional information.
A condensed income statement for
Increase
(Decrease)
2021 from 2020
(in millions)
Operating revenues $ 6,413 $ 583
Fuel 1,235 265
Purchased power 368 49
Other operations and maintenance 1,735 116
Depreciation and amortization 859 47
Taxes other than income taxes 410 (6)
Total operating expenses 4,607 471
Operating income 1,806 112
Allowance for equity funds used during construction 52 6
Interest expense, net of amounts capitalized 340 2
Other income (expense), net 107 7
Income taxes 372 35
Net income 1,253 88
Dividends on preferred stock 15 -
Net income after dividends on preferred stock
II-18
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues
Operating revenues for 2021 were
2021 2020
(in millions)
Retail - prior year $ 5,213
Estimated change resulting from -
Rates and pricing 115
Sales growth 50
Weather (15)
Fuel and other cost recovery 136
Retail - current year $ 5,499 $ 5,213
Wholesale revenues -
Non-affiliates 377 269
Affiliates 171 46
Total wholesale revenues 548 315
Other operating revenues 366 302
Total operating revenues $ 6,413 $ 5,830
Retail revenues increased $286 million , or 5.5%, in 2021 as compared to 2020.
The significant factors driving this change are shown in the preceding table.
The increase was primarily due to a Rate RSE increase effective January 1, 2021 ,
increases in fuel and other cost recovery, and increases in commercial and
industrial sales primarily due to the negative impacts of the COVID-19 pandemic
on energy demand being more severe in 2020. These increases were offset by an
increase in the accrual for a Rate RSE customer refund and milder weather in
2021 when compared to 2020. See Note 2 to the financial statements under
"Alabama Power - Rate RSE" for additional information.
See "Energy Sales" herein for a discussion of changes in the volume of energy sold, including changes related to sales growth and weather.
Electric rates include provisions to recognize the recovery of fuel costs, purchased power costs, PPAs certificated by the Alabama PSC, and costs associated with the NDR. Under these provisions, fuel and other cost recovery revenues generally equal fuel and other cost recovery expenses and do not affect net income. See Note 2 to the financial statements under "Alabama Power " for additional information.
Wholesale revenues from sales to non-affiliated utilities were as follows:
2021 2020
(in millions)
Capacity and other $ 173 $ 127
Energy 204 142
Total non-affiliated $ 377 $ 269
In 2021, wholesale revenues from sales to non-affiliates increased $108 million ,
or 40.1%, as compared to 2020 due to a $46 million increase in capacity revenues
primarily related to a power sales agreement that began in September 2020 and a
$62 million increase in energy revenues primarily due to higher natural gas
prices. See Notes 2 and 15 to the financial statements under "Alabama Power -
Certificates of Convenience and Necessity" and "Alabama Power ," respectively,
for additional information.
Wholesale revenues from sales to non-affiliates will vary depending on fuel
prices, the market prices of wholesale energy compared to the cost of Alabama
Power's and the Southern Company system's generation, demand for energy within
the Southern Company system's electric service territory, and availability of
the Southern Company system's generation. Increases and decreases in energy
revenues that are driven by fuel prices are accompanied by an increase or
decrease in fuel costs and do not affect net income. Short-term opportunity
energy sales are also included in wholesale energy sales to non-affiliates.
These
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
opportunity sales are made at market-based rates that generally provide a margin
above
In 2021, wholesale revenues from sales to affiliates increased$125 million , or 271.7%, as compared to 2020. The revenue increase reflects a 110.0% increase in 2021 KWH sales due to higher demand forAlabama Power's available lower cost generation and a 75.8% increase in the price of energy, primarily natural gas. Wholesale revenues from sales to affiliated companies will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales and purchases are made in accordance with the IIC, as approved by theFERC . These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost and energy purchases are generally offset by energy revenues throughAlabama Power's energy cost recovery clause. In 2021, other operating revenues increased$64 million , or 21.2%, as compared to 2020 primarily due to a$29 million increase in unregulated sales of products and services, a$13 million increase in customer fees largely resulting from the COVID-19 pandemic-related temporary suspensions of disconnections and late fees in 2020, a$10 million increase in cogeneration steam revenue associated with higher natural gas prices, and an$8 million increase in transmission revenues primarily related to open access transmission tariff sales.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2021 and the percent change from 2020 were
as follows:
2021
Total Total KWH Weather-Adjusted
KWHs Percent Change Percent Change(*)
(in billions)
Residential 17.5 (0.9) % (0.7) %
Commercial 12.7 2.3 2.9
Industrial 20.8 2.2 2.2
Other 0.1 (13.8) (13.8)
Total retail 51.1 1.1 1.3 %
Wholesale
Non-affiliates 9.8 53.8
Affiliates 5.2 110.0
Total wholesale 15.0 69.6
Total energy sales 66.1 11.3 %
(*)Weather-adjusted KWH sales are estimated using statistical models of the
historical relationship between temperatures and energy sales, and then removing
the estimated effect of deviations from the normal temperature conditions.
Normal temperature conditions are defined as those experienced in Alabama
Power's service territory over a specified historical period. This metric is
useful because it allows trends in historical operations to be evaluated apart
from the influence of weather conditions. Management also considers this metric
in developing long-term capital and financial plans.
Changes in retail energy sales are generally the result of changes in
electricity usage by customers, weather, and the number of customers. Revenues
attributable to changes in sales increased in 2021 when compared to 2020. In
2021, weather-adjusted residential KWH sales decreased 0.7% primarily due to
safer-at-home guidelines in effect during 2020. Weather-adjusted commercial KWH
sales increased 2.9% and industrial KWH sales increased 2.2% primarily due to
the negative impacts of the COVID-19 pandemic on energy sales being more severe
in 2020.
See "Operating Revenues" above for a discussion of significant changes in wholesale revenues from sales to non-affiliates and wholesale revenues from sales to affiliated companies related to changes in price and KWH sales.
Fuel and Purchased Power Expenses
The mix of fuel sources for generation of electricity is determined primarily by the unit cost of fuel consumed, demand, and the availability of generating units. Additionally,Alabama Power purchases a portion of its electricity needs from the wholesale market. II-20 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2021 2020
Total generation (in billions of KWHs)(a) 58.5
53.8
Total purchased power (in billions of KWHs) 6.4
6.9
Sources of generation (percent)(a) - Coal 46 40 Nuclear 26 28 Gas 19 22 Hydro 9 10 Cost of fuel, generated (in cents per net KWH) - Coal 2.77 2.74 Nuclear 0.70 0.75 Gas(a) 2.89 2.13
Average cost of fuel, generated (in cents per net KWH)(a) 2.22 1.98 Average cost of purchased power (in cents per net KWH)(b) 6.52 4.82
(a)Excludes Central Alabama Generating Station KWHs and associated cost of fuel as its fuel is provided by the purchaser under a power sales agreement. See Note 15 to the financial statements under "Alabama Power " for additional information.
(b)Average cost of purchased power includes fuel, energy, and transmission
purchased by
Fuel and purchased power expenses were$1.6 billion in 2021, an increase of$314 million , or 24.4%, compared to 2020. The increase was primarily due to a$196 million increase in the average cost of fuel and purchased power and a$117 million net increase related to the volume of KWHs generated and purchased. Fuel and purchased power energy transactions do not have a significant impact on earnings, since energy expenses are generally offset by energy revenues throughAlabama Power's energy cost recovery clause.Alabama Power , along with the Alabama PSC, continuously monitors the under/over recovered balance to determine whether adjustments to billing rates are required. See Note 2 to the financial statements under "Alabama Power - Rate ECR" for additional information.
Fuel
Fuel expense was$1.2 billion in 2021, an increase of$265 million , or 27.3%, compared to 2020. The increase was primarily due to a 35.7% increase in the average cost of natural gas per KWH generated, which excludes tolling agreements, a 25.1% increase in the volume of KWHs generated by coal, and an 8.8% decrease in the volume of KWHs generated by hydro, partially offset by a 6.7% decrease in the average cost of nuclear fuel per KWH generated and a 3.6% decrease in the volume of KWHs generated by natural gas.
Purchased power expense from non-affiliates was$221 million in 2021, an increase of$30 million , or 15.7%, compared to 2020. The increase was primarily due to a 19.4% increase in the amount of energy purchased due to a new PPA that began inSeptember 2020 and a 10.6% increase in the average cost of purchased power per KWH as a result of higher natural gas prices.
Energy purchases from non-affiliates will vary depending on the market prices of
wholesale energy as compared to the cost of
Purchased power expense from affiliates was$147 million in 2021, an increase of$19 million , or 14.8%, compared to 2020. The increase was primarily due to an 87.4% increase in the average cost of purchased power per KWH as a result of higher natural gas prices, partially offset by a 38.8% decrease in the volume of KWH purchased asAlabama Power's units generally dispatched at a lower cost than other availableSouthern Company system resources. II-21 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Energy purchases from affiliates will vary depending on demand for energy and the availability and cost of generating resources at each company withinthe Southern Company system. These purchases are made in accordance with the IIC or other contractual agreements, as approved by theFERC .
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased$116 million , or 7.2%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to a$59 million increase in generation expenses associated with scheduled outages and Rate CNP Compliance-related expenses primarily related to the addition of new environmental systems in 2021. Also contributing to the increase were increases of$55 million in transmission and distribution line maintenance expenses related to reliability NDR credits applied in 2020 and vegetation management expenses,$22 million in compensation and benefit expenses, and$11 million related to unregulated products and services, as well as a$10 million decrease in nuclear property insurance refunds. The increase was partially offset by a$36 million decrease in bad debt expense and a net decrease of$35 million to the NDR accrual in 2021 when compared to 2020. See Note 2 to the financial statements under "Alabama Power - Rate NDR" and " - Rate CNP Compliance" for additional information.
Depreciation and Amortization
Depreciation and amortization increased$47 million , or 5.8%, in 2021 as compared to 2020 primarily due to additional plant in service, including the purchase of theCentral Alabama Generating Station inAugust 2020 . See Notes 5 and 15 to the financial statements for additional information.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized increased$2 million , or 0.6%, in 2021 as compared to 2020 primarily due to an increase of approximately$17 million associated with higher average outstanding borrowings, largely offset by a decrease of approximately$16 million related to lower interest rates. See Note 8 to the financial statements for additional information.
Other Income (Expense), Net
Other income (expense), net increased
Income Taxes
Income taxes increased
Georgia Power's 2021 net income was$584 million , representing a$991 million , or 62.9%, decrease from the previous year. The decrease was primarily due to a$1.0 billion increase in after-tax charges related to the construction of Plant Vogtle Units 3 and 4. Also contributing to the decrease were higher non-fuel operations and maintenance costs, partially offset by higher retail revenues associated with sales growth. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information on the construction of Plant Vogtle Units 3 and 4. II-22 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
A condensed income statement for
Increase
(Decrease)
2021 from 2020
(in millions)
Operating revenues $ 9,260 $ 951
Fuel 1,449 308
Purchased power 1,491 442
Other operations and maintenance 2,213 260
Depreciation and amortization 1,371
(54)
Taxes other than income taxes 476
32
Estimated loss on Plant Vogtle Units 3 and 4 1,692 1,367 Total operating expenses 8,692 2,355 Operating income 568 (1,404) Allowance for equity funds used during construction 127
36
Interest expense, net of amounts capitalized 421 (4) Other income (expense), net 142 53 Income taxes (benefit) (168) (320) Net income$ 584 $ (991) Operating Revenues
Operating revenues for 2021 were
2021 2020
(in millions)
Retail - prior year $ 7,609
Estimated change resulting from -
Rates and pricing 80
Sales growth 152
Weather (59)
Fuel cost recovery 696
Retail - current year 8,478 $ 7,609
Wholesale revenues 197 115
Other operating revenues 585 585
Total operating revenues $ 9,260 $ 8,309
Retail revenues increased $869 million , or 11.4%, in 2021 as compared to 2020.
The significant factors driving this change are shown in the preceding table.
The increase in rates and pricing was primarily due to higher contributions from
commercial and industrial customers with variable demand-driven pricing, fixed
residential customer bill programs, the effects of higher KWH sales on ECCR
tariff revenues, and base tariff increases in accordance with the 2019 ARP,
partially offset by a decrease in the NCCR tariff, both effective January 1,
2021 . See Note 2 to the financial statements under "Georgia Power - Rate Plans"
for additional information.
See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to the sales growth in 2021.
Electric rates include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these fuel cost recovery provisions, fuel revenues generally equal fuel expenses and do not affect net income. See Note 2 to the financial statements under "Georgia Power - Fuel Cost Recovery" for additional information. II-23 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Wholesale revenues from power sales were as follows:
2021 2020
(in millions)
Capacity and other $ 63 $ 51
Energy 134 64
Total $ 197 $ 115
In 2021, wholesale revenues increased $82 million , or 71.3%, as compared to 2020
largely due to increases of $52 million related to the average cost of fuel
primarily due to higher natural gas prices, $12 million in capacity revenues
primarily from shared Southern Company power pool sales in accordance with the
IIC, and $10 million in KWH sales associated with higher market demand.
Wholesale capacity revenues from PPAs are recognized in amounts billable under
the contract terms and provide for recovery of fixed costs and a return on
investment. Wholesale revenues from sales to non-affiliates will vary depending
on fuel prices, the market prices of wholesale energy compared to the cost of
Georgia Power's and the Southern Company system's generation, demand for energy
within the Southern Company system's electric service territory, and the
availability of the Southern Company system's generation. Increases and
decreases in energy revenues that are driven by fuel prices are accompanied by
an increase or decrease in fuel costs and do not have a significant impact on
net income. Short-term opportunity sales are made at market-based rates that
generally provide a margin above Georgia Power's variable cost of energy.
Wholesale revenues from sales to affiliated companies will vary depending on
demand and the availability and cost of generating resources at each company.
These affiliate sales are made in accordance with the IIC, as approved by the
FERC . These transactions do not have a significant impact on earnings since this
energy is generally sold at marginal cost.
Other operating revenues were flat in 2021 compared to 2020. Increases of $33
million in unregulated sales associated with power delivery construction and
maintenance projects and outdoor lighting and $13 million in customer fees,
largely resulting from the COVID-19 pandemic-related temporary suspension of
disconnections and late fees in 2020, were largely offset by decreases of $26
million in pole attachment revenues, $9 million associated with the timing of
certain unregulated energy conservation projects, and $5 million from retail
solar programs.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2021 and the percent change from 2020 were
as follows:
2021
Total Total KWH Weather-Adjusted
KWHs Percent Change Percent Change(*)
(in billions)
Residential 27.8 0.1 % 1.3 %
Commercial 31.3 2.9 3.4
Industrial 23.3 5.6 5.7
Other 0.5 (2.3) (2.4)
Total retail 82.9 2.6 3.3 %
Wholesale 3.2 18.1
Total energy sales 86.1 3.1 %
(*)Weather-adjusted KWH sales are estimated using statistical models of the
historical relationship between temperatures and energy sales, and then removing
the estimated effect of deviations from normal temperature conditions. Normal
temperature conditions are defined as those experienced in Georgia Power's
service territory over a specified historical period. This metric is useful
because it allows trends in historical operations to be evaluated apart from the
influence of weather conditions. Management also considers this metric in
developing long-term capital and financial plans.
Changes in retail energy sales are generally the result of changes in
electricity usage by customers, weather, and the number of customers. Revenues
attributable to changes in sales increased in 2021 when compared to 2020. In
2021, weather-adjusted residential KWH sales increased 1.3% compared to 2020
primarily due to customer growth, partially offset by decreased customer usage
largely due to shelter-in-place orders in effect during 2020. Weather-adjusted
commercial KWH sales increased 3.4% and
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
weather-adjusted industrial KWH sales increased 5.7% primarily due to the negative impacts of the COVID-19 pandemic on energy sales being more severe in 2020.
See "Operating Revenues" above for a discussion of significant changes in wholesale sales to non-affiliates and affiliated companies.
Fuel and Purchased Power Expenses
Fuel costs constitute one of the largest expenses forGeorgia Power . The mix of fuel sources for the generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally,Georgia Power purchases a portion of its electricity needs from the wholesale market.
2021 2020
Total generation (in billions of KWHs) 58.1
56.8
Total purchased power (in billions of KWHs) 31.7
30.5
Sources of generation (percent) - Gas 48 52 Nuclear 28 27 Coal 20 16 Hydro and other 4 5 Cost of fuel, generated (in cents per net KWH) - Gas 3.05 2.19 Nuclear 0.79 0.80 Coal 2.99 3.23
Average cost of fuel, generated (in cents per net KWH) 2.39 1.96 Average cost of purchased power (in cents per net KWH)(*) 5.07 3.69
(*) Average cost of purchased power includes fuel purchased by
Fuel and purchased power expenses were$2.9 billion in 2021, an increase of$750 million , or 34.2%, compared to 2020. The increase was due to an increase of$651 million related to the average cost of fuel and purchased power and an increase of$99 million related to the volume of KWHs generated and purchased. Fuel and purchased power energy transactions do not have a significant impact on earnings since these fuel expenses are generally offset by fuel revenues throughGeorgia Power's fuel cost recovery mechanism. See Note 2 to the financial statements under "Georgia Power - Fuel Cost Recovery" for additional information.
Fuel
Fuel expense was$1.4 billion in 2021, an increase of$308 million , or 27.0%, compared to 2020. The increase was primarily due to a 39.3% increase in the average cost of natural gas per KWH generated and a 27.8% increase in the volume of KWHs generated by coal, partially offset by a 7.4% decrease in the average cost of coal per KWH generated and a decrease of 5.2% in the volume of KWHs generated by natural gas.
Purchased power expense from non-affiliates was$632 million in 2021, an increase of$92 million , or 17.0%, compared to 2020. The increase was primarily due to an increase of 23.4% in the average cost per KWH purchased primarily due to higher natural gas prices, partially offset by a decrease of 3.5% in the volume of KWHs purchased asGeorgia Power units andSouthern Company system resources generally dispatched at a lower cost than available market resources.
Energy purchases from non-affiliates will vary depending on the market prices of
wholesale energy as compared to the cost of
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Purchased power expense from affiliates was$859 million in 2021, an increase of$350 million , or 68.8%, compared to 2020. The increase was primarily due to an increase of 53.4% in the average cost per KWH purchased primarily due to higher natural gas prices and an increase of 8.4% in the volume of KWHs purchased due to lower costSouthern Company system resources as compared to availableGeorgia Power -owned generation and market resources.
Energy purchases from affiliates will vary depending on the demand and the
availability and cost of generating resources at each company within
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased$260 million , or 13.3%, in 2021 as compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to increases of$104 million in transmission and distribution expenses associated with vegetation and asset management activities,$63 million in generation expenses associated with outage and non-outage maintenance costs and environmental projects,$28 million in certain compensation and benefit expenses, and$8 million in maintenance costs at corporate and field support facilities, as well as an$8 million decrease in nuclear property insurance refunds.
Depreciation and Amortization
Depreciation and amortization decreased$54 million , or 3.8%, in 2021 as compared to 2020 primarily due to an$88 million decrease in amortization of regulatory assets related to CCR AROs under the terms of the 2019 ARP, partially offset by a$39 million increase in depreciation associated with additional plant in service. See Note 2 to the financial statements under "Georgia Power - Rate Plans - 2019 ARP" for additional information.
Taxes Other Than Income Taxes
Taxes other than income taxes increased$32 million , or 7.2%, in 2021 as compared to 2020 primarily due to a$25 million increase in municipal franchise fees largely related to higher retail revenues and a$9 million increase in property taxes primarily resulting from an increase in the assessed value of property.
Estimated Loss on Plant Vogtle Units 3 and 4
Estimated probable loss on Plant Vogtle Units 3 and 4 increased$1.4 billion in 2021 as compared to 2020. The losses in each year were recorded to reflect revisions to the total project capital cost forecast to complete construction and start-up of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information.
Allowance for
Allowance for equity funds used during construction increased$36 million , or 39.6%, in 2021 as compared to 2020 primarily due to a higher AFUDC base largely associated with the construction of Plant Vogtle Units 3 and 4. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information regarding Plant Vogtle Units 3 and 4.
Interest Expense, Net of Amounts Capitalized
Interest expense, net of amounts capitalized decreased$4 million , or 0.9%, in 2021 as compared to 2020 primarily due to an increase of$16 million in amounts capitalized largely associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an$11 million increase in interest expense primarily associated with higher average outstanding borrowings. See FINANCIAL CONDITION AND LIQUIDITY - "Sources of Capital" and "Financing Activities" herein and Note 8 to the financial statements for additional information on borrowings and Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information regarding Plant Vogtle Units 3 and 4.
Other Income (Expense), Net
Other income (expense), net increased
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Income Taxes (Benefit)
In 2021, income tax benefit was$168 million compared to income tax expense of$152 million for 2020, a change of$320 million . The change was primarily due to lower pre-tax earnings resulting from higher charges in 2021 associated with the construction of Plant Vogtle Units 3 and 4, partially offset by an increase in a valuation allowance on certain state tax credit carryforwards. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " and Note 10 to the financial statements for additional information.
Mississippi Power's net income was$159 million in 2021 compared to$152 million in 2020. The increase was primarily due to revenues resulting from an increase in base rates that became effective for the first billing cycle ofApril 2021 and higher customer usage, as well as an increase in other income (expense), net, partially offset by an increase in operations and maintenance expenses.
A condensed income statement for
Increase
(Decrease)
2021 from 2020
(in millions)
Operating revenues $ 1,322 $ 150
Fuel 470 120
Purchased power 26 4
Other operations and maintenance 313 29
Depreciation and amortization 180 (3)
Taxes other than income taxes 128 4
Total operating expenses 1,117 154
Operating income 205 (4)
Interest expense, net of amounts capitalized 60 -
Other income (expense), net 35 18
Income taxes 21 7
Net income $ 159 $ 7
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Revenues
Operating revenues for 2021 were
2021 2020
(in millions)
Retail - prior year $ 821
Estimated change resulting from -
Rates and pricing 14
Sales growth 7
Weather (1)
Fuel and other cost recovery 34
Retail - current year 875 $ 821
Wholesale revenues -
Non-affiliates 230 215
Affiliates 188 111
Total wholesale revenues 418 326
Other operating revenues 29 25
Total operating revenues $ 1,322 $ 1,172
Total retail revenues for 2021 increased $54 million , or 6.6%, compared to 2020
primarily due to an increase in fuel and other cost recovery revenues primarily
as a result of higher recoverable fuel costs, an increase in revenues in
accordance with new PEP rates that became effective for the first billing cycle
of April 2021 , and an increase in customer usage. See Note 2 to the financial
statements under "Mississippi Power " for additional information.
See "Energy Sales" below for a discussion of changes in the volume of energy sold, including changes related to sales and weather.
Electric rates forMississippi Power include provisions to adjust billings for fluctuations in fuel costs, including the energy component of purchased power costs. Under these provisions, fuel revenues generally equal fuel expenses, including the energy component of purchased power costs, and do not affect net income. Recoverable fuel costs include fuel and purchased power expenses reduced by the fuel and emissions portion of wholesale revenues from energy sold to customers outsideMississippi Power's service territory. See Note 2 to the financial statements under "Mississippi Power - Fuel Cost Recovery" for additional information.
Wholesale revenues from power sales to non-affiliated utilities, including
2021 2020
(in millions)
Capacity and other $ 3 $ 3
Energy 227 212
Total non-affiliated $ 230 $ 215
Wholesale revenues from sales to non-affiliates increased $15 million , or 7.0%,
compared to 2020. The increase was primarily associated with higher natural gas
prices.
Wholesale revenues from sales to non-affiliates will vary depending on fuel
prices, the market prices of wholesale energy compared to the cost of
Mississippi Power's and the Southern Company system's generation, demand for
energy within the Southern Company system's electric service territory, and the
availability of the Southern Company system's generation. Increases and
decreases in energy revenues that are driven by fuel prices are accompanied by
an increase or decrease in fuel costs and do not have a significant impact on
net income. In addition, Mississippi Power provides service under long-term
contracts with rural electric cooperative associations and a municipality
located in southeastern Mississippi under full requirements cost-based electric
tariffs which are subject to regulation by the FERC . The contracts with these
wholesale customers represented 14.3% of
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Mississippi Power's total operating revenues in 2021 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. Short-term opportunity energy sales are also included in sales for resale to non-affiliates. These opportunity sales are made at market-based rates that generally provide a margin aboveMississippi Power's variable cost to produce the energy. Wholesale revenues from sales to affiliates increased$77 million , or 69.4%, in 2021 compared to 2020. The increase was primarily due to an$86 million increase associated with higher natural gas prices, partially offset by a$10 million decrease associated with lower KWH sales. Wholesale revenues from sales to affiliates will vary depending on demand and the availability and cost of generating resources at each company. These affiliate sales are made in accordance with the IIC, as approved by theFERC . These transactions do not have a significant impact on earnings since this energy is generally sold at marginal cost.
Energy Sales
Changes in revenues are influenced heavily by the change in the volume of energy
sold from year to year. KWH sales for 2021 and the percent change from 2020 were
as follows:
2021
Total Total KWH
KWHs Percent Change Weather-Adjusted Percent Change(*)
(in millions)
Residential 2,047 1.2 % 0.2 %
Commercial 2,559 1.8 2.7
Industrial 4,615 1.3 1.3
Other 34 (3.3) % (3.3)
Total retail 9,255 1.4 % 1.4 %
Wholesale
Non-affiliated 3,611 (4.6)
Affiliated 4,742 (9.3)
Total wholesale 8,353 (7.3)
Total energy sales 17,608 (2.9) %
(*)Weather-adjusted KWH sales are estimated using statistical models of the
historical relationship between temperatures and energy sales, and then removing
the estimated effect of deviations from normal temperature conditions. Normal
temperature conditions are defined as those experienced in Mississippi Power's
service territory over a specified historical period. This metric is useful
because it allows trends in historical operations to be evaluated apart from the
influence of weather conditions. Management also considers this metric in
developing long-term capital and financial plans.
Changes in retail energy sales are generally the result of changes in
electricity usage by customers, weather, and the number of customers. Revenues
attributable to changes in sales increased in 2021 when compared to 2020.
Weather-adjusted residential KWH sales increased 0.2% compared to 2020 due to
increased customer growth, partially offset by decreased customer usage.
Weather-adjusted commercial KWH sales increased 2.7% and industrial KWH sales
increased 1.3% primarily due to the negative impacts of the COVID-19 pandemic on
energy sales being more severe in 2020.
See "Operating Revenues" above for a discussion of significant changes in wholesale revenues to affiliated companies.
Fuel and Purchased Power Expenses
The mix of fuel sources for generation of electricity is determined primarily by demand, the unit cost of fuel consumed, and the availability of generating units. Additionally,Mississippi Power purchases a portion of its electricity needs from the wholesale market. II-29 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2021 2020
Total generation (in millions of KWHs) 17,377
17,833
Total purchased power (in millions of KWHs) 675
688
Sources of generation (percent) - Gas 92
94
Coal 8
6
Cost of fuel, generated (in cents per net KWH) - Gas 2.85
1.97
Coal 3.24
3.62
Average cost of fuel, generated (in cents per net KWH) 2.88 2.08 Average cost of purchased power (in cents per net KWH) 3.90 3.27
Fuel and purchased power expenses were$496 million in 2021, an increase of$124 million , or 33.3%, as compared to 2020. The increase was primarily due to an increase in the average cost of natural gas. Fuel and purchased power energy transactions do not have a significant impact on earnings since energy expenses are generally offset by energy revenues throughMississippi Power's fuel cost recovery clauses. See Note 2 to the financial statements under "Mississippi Power - Fuel Cost Recovery" and Note 1 to the financial statements under "Fuel Costs" for additional information. Fuel expense increased$120 million , or 34.3%, in 2021 compared to 2020 primarily due to a 44.7% increase in the average cost of natural gas per KWH generated, partially offset by a 4.8% decrease in the volume of KWHs generated by natural gas. Energy purchases will vary depending on the market prices of wholesale energy as compared to the cost ofthe Southern Company system's generation, demand for energy withinthe Southern Company system's service territory, and the availability ofthe Southern Company system's generation. These purchases are made in accordance with the IIC or other contractual agreements, as approved by theFERC .
Other Operations and Maintenance Expenses
Other operations and maintenance expenses increased$29 million , or 10.2%, in 2021 compared to 2020. A portion of the increase in 2021 compared to 2020 reflects cost containment activities implemented to help offset the effects of the recessionary economy resulting from the beginning of the COVID-19 pandemic. The increase was primarily due to increases of$7 million associated with theKemper County energy facility (primarily related to increases in dismantlement activities and less salvage proceeds in 2021),$7 million in generation expenses associated with outage and non-outage maintenance,$6 million in distribution operations and maintenance, and$6 million in compensation and benefit expenses.
Other Income (Expense), Net
Other income (expense), net increased$18 million , or 105.9%, in 2021 compared to 2020. The increase was primarily due to a$9 million decrease in charitable donations and increases of$6 million in non-service cost-related retirement benefits income and$3 million in interest associated with a sales-type lease. See Notes 9 and 11 to the financial statements for additional information.
Income Taxes
Income taxes increased$7 million , or 50.0%, in 2021 compared to 2020 due to higher pre-tax earnings and an increase associated with lower flowback of excess deferred income taxes associated with new PEP rates that became effective for the first billing cycle ofApril 2021 . See Note 2 to the financial statements under "Mississippi Power - Performance Evaluation Plan" and Note 10 to the financial statements for additional information. II-30 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Net income attributable toSouthern Power for 2021 was$266 million , a$28 million increase from 2020. The increase was primarily due to a net increase in revenues associated with new PPAs and a tax benefit due to changes in state apportionment methodology resulting from tax legislation enacted by theState of Alabama inFebruary 2021 , partially offset by an increase in other operations and maintenance expenses primarily associated with scheduled outages and maintenance and a gain recorded in 2020 associated with the Roserock solar facility litigation. See Note 10 to the financial statements for additional information.
A condensed statement of income follows:
Increase
(Decrease)
2021 from 2020
(in millions)
Operating revenues $ 2,216 $ 483
Fuel 802 332
Purchased power 139 65
Other operations and maintenance 423 70
Depreciation and amortization 517 23
Taxes other than income taxes 45 6
Loss on sales-type leases 40 40
Gain on dispositions, net (41) (2)
Total operating expenses 1,925 534
Operating income 291 (51)
Interest expense, net of amounts capitalized 147 (4)
Other income (expense), net 10 (9)
Income taxes (benefit) (13) (16)
Net income 167 (40)
Net loss attributable to noncontrolling interests (99) (68)
Net income attributable to Southern Power$ 266 $ 28
Operating Revenues
Total operating revenues include PPA capacity revenues, which are derived primarily from long-term contracts involving natural gas facilities, and PPA energy revenues fromSouthern Power's generation facilities. To the extentSouthern Power has capacity not contracted under a PPA, it may sell power into an accessible wholesale market, or, to the extent those generation assets are part of theFERC -approved IIC, it may sell power intothe Southern Company power pool.
Natural Gas Capacity and Energy Revenue
Capacity revenues generally represent the greatest contribution to operating income and are designed to provide recovery of fixed costs plus a return on investment.
Energy is generally sold at variable cost or is indexed to published natural gas indices. Energy revenues will vary depending on the energy demand ofSouthern Power's customers and their generation capacity, as well as the market prices of wholesale energy compared to the cost ofSouthern Power's energy. Energy revenues also include fees for support services, fuel storage, and unit start charges. Increases and decreases in energy revenues under PPAs that are driven by fuel or purchased power prices are accompanied by an increase or decrease in fuel and purchased power costs and do not have a significant impact on net income.
Solar and Wind Energy Revenue
Southern Power's energy sales from solar and wind generating facilities are predominantly through long-term PPAs that do not have capacity revenue. Customers either purchase the energy output of a dedicated renewable facility through an energy charge or pay a fixed price related to the energy generated from the respective facility and sold to the grid. As a result,Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. II-31 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
See FUTURE EARNINGS POTENTIAL - "
Operating Revenues Details
Details of
2021 2020
(in millions)
PPA capacity revenues $ 408 $ 384
PPA energy revenues 1,311 1,019
Total PPA revenues 1,719 1,403
Non-PPA revenues 467 316
Other revenues 30 14
Total operating revenues $ 2,216 $ 1,733 Operating revenues for 2021 were
•PPA capacity revenues increased$24 million , or 6%, primarily due to a net increase in sales associated with new natural gas PPAs and increased capacity sales under existing natural gas PPAs. •PPA energy revenues increased$292 million , or 29%, primarily due to an increase in sales under existing natural gas PPAs resulting from a$206 million increase in the price of fuel and purchased power and a$79 million net increase in sales associated with new natural gas PPAs. Also contributing to the increase was$15 million related to new wind PPAs which began during 2020 and 2021, partially offset by an$11 million decrease in sales under existing wind PPAs. •Non-PPA revenues increased$151 million , or 48%, due to a$197 million increase in the market price of energy, partially offset by a$46 million decrease in the volume of KWHs sold through short-term sales.
•Other revenues increased
Fuel and Purchased Power Expenses
Details of
Total Total
KWHs Total KWH % Change KWHs
2021 2020
(in billions of KWHs)
Generation 44 44
Purchased power 3 3
Total generation and purchased power 47 -% 47
Total generation and purchased power (excluding solar, wind, fuel cells, and tolling agreements)
28 -% 28
Southern Power's PPAs for natural gas generation generally provide that the
purchasers are responsible for either procuring the fuel (tolling agreements) or
reimbursing Southern Power for substantially all of the cost of fuel relating to
the energy delivered under such PPAs. Consequently, changes in such fuel costs
are generally accompanied by a corresponding change in related fuel revenues and
do not have a significant impact on net income. Southern Power is responsible
for the cost of fuel for generating units that are not covered under PPAs. Power
from these generating units is sold into the wholesale market or into the
Southern Company power pool for capacity owned directly by Southern Power .
Purchased power expenses will vary depending on demand, availability, and the
cost of generating resources throughout the Southern Company system and other
contract resources. Load requirements are submitted to the Southern Company
power pool on an hourly basis and are fulfilled with the lowest cost
alternative, whether that is generation owned by Southern Power , an affiliate
company, or external parties. Such purchased power costs are generally recovered
through PPA revenues.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Details ofSouthern Power's fuel and purchased power expenses were as follows: 2021 2020 (in millions) Fuel$ 802 $ 470 Purchased power 139 74
Total fuel and purchased power expenses
In 2021, total fuel and purchased power expenses increased$397 million , or 73%, compared to 2020. Fuel expense increased$332 million , or 71%, primarily due to an increase in the average cost of fuel. Purchased power expense increased$65 million , or 88%, due to an increase associated with the average cost of purchased power.
Other Operations and Maintenance Expenses
In 2021, other operations and maintenance expenses increased$70 million , or 20%, compared to 2020. The increase was primarily due to increases of$21 million in scheduled outage and maintenance expenses,$15 million in transmission expenses primarily related to new PPAs,$10 million in compensation and benefit expenses,$8 million in expenses associated with new wind facilities placed in service during 2020 and 2021, and$5 million related to the allocation of uncollected settlements by theEnergy Reliability Council of Texas market as a result of Winter Storm Uri.
Depreciation and Amortization
In 2021, depreciation and amortization increased
Loss on Sales-Type Leases
In 2021, a$40 million loss on sales-type leases was recorded upon commencement of the Garland and Tranquillity battery energy storage facilities' PPAs,$26 million of which was allocated through noncontrolling interests toSouthern Power's partners in the projects. The loss was due to ITCs retained and expected to be realized bySouthern Power and its partners. See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power ," respectively, for additional information.
Gain on Dispositions, Net
In 2021, gain on dispositions, net increased$2 million , or 5%, compared to 2020. Gains on dispositions totaled$41 million in 2021 primarily due to contributions of wind turbine equipment to various equity method investments in the first quarter 2021. A$39 million gain was also recorded in the first quarter 2020 related to the sale of Plant Mankato. See Notes 7 and 15 to the financial statements under "Southern Power " and "Southern Power - Sales of Natural Gas and Biomass Plants," respectively, for additional information.
Other Income (Expense), Net
In 2021, other income (expense), net decreased
Income Taxes (Benefit)
In 2021, income tax benefit was$13 million compared to income tax expense of$3 million for 2020, a change of$16 million . The change was primarily due to changes in state apportionment methodology resulting from tax legislation enacted by theState of Alabama inFebruary 2021 and the tax impact from the sale of Plant Mankato inJanuary 2020 . See Notes 1, 10, and 15 to the financial statements under "Income Taxes," "Effective Tax Rate," and "Southern Power ," respectively, for additional information.
Net Loss Attributable to Noncontrolling Interests
In 2021, net loss attributable to noncontrolling interests increased$68 million compared to 2020. The increased loss was primarily due to loss allocations to the partners in the Garland and Tranquillity battery energy storage facilities, including$26 million allocated from the loss on sales-type leases. In addition, the increased loss was due to higher HLBV loss allocations to wind tax equity partners, including new partnerships entered into during 2020 and 2021, and lower income allocations to solar equity partners, totaling$29 million . See Notes 9 and 15 to the financial statements under "Lessor" and "Southern Power ," respectively, for additional information. II-33 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Operating Metrics
Southern Company Gas measures weather and the effect on its business using Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas onSouthern Company Gas' distribution system.Southern Company Gas has various regulatory mechanisms, such as weather and revenue normalization and straight-fixed-variable rate design, which limit its exposure to weather changes within typical ranges in each of its utility's respective service territory.Southern Company Gas also utilizes weather hedges to limit the negative income impacts in the event of warmer-than-normal weather.
The number of customers served by gas distribution operations and gas marketing
services can be impacted by natural gas prices, economic conditions, and
competition from alternative fuels. Gas distribution operations and gas
marketing services' customers are primarily located in
Southern Company Gas' natural gas volume metrics for gas distribution operations and gas marketing services illustrate the effects of weather and customer demand for natural gas. Wholesale gas services' physical sales volumes represent the daily average natural gas volumes sold to its customers.
Seasonality of Results
During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to the gas distribution systems and natural gas usage is higher in periods of colder weather. Prior to the sale of Sequent onJuly 1, 2021 , wholesale gas services' operating revenues occasionally were impacted due to peak usage by power generators in response to summer energy demands.Southern Company Gas' base operating expenses, excluding cost of natural gas, bad debt expense, and certain incentive compensation costs, are incurred relatively evenly throughout the year. Seasonality also affects the comparison of certain balance sheet items across quarters, including receivables, unbilled revenues, natural gas for sale, and notes payable. However, these items are comparable when reviewingSouthern Company Gas' annual results. Thus,Southern Company Gas' operating results can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below. Percent Generated During Heating Season Net Operating Revenues Income 2021 70 % 102 % 2020 68 % 86 % Net Income Net income attributable toSouthern Company Gas in 2021 was$539 million , a decrease of$51 million , or 8.6%, compared to 2020. The decrease was primarily due to$85 million of deferred income taxes and an$80 million decrease at gas pipeline investments primarily due to impairment charges related to the PennEast Pipeline project, partially offset by a$93 million increase at wholesale gas services primarily due to the gain on the sale of Sequent and a$22 million increase at gas distribution operations primarily due to base rate increases and continued investment in infrastructure replacement. See Note 7 to the financial statements under "Southern Company Gas " for additional information on the PennEast Pipeline project and Note 15 to the financial statements under "Southern Company Gas " for additional information on the sale of Sequent. II-34 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
A condensed income statement for
Increase
(Decrease) from
2021 2020
(in millions)
Operating revenues $ 4,380 $ 946
Cost of natural gas 1,619 647
Other operations and maintenance 1,072 106
Depreciation and amortization 536 36
Taxes other than income taxes 225 19
Gain on dispositions, net (127) (105)
Total operating expenses 3,325 703
Operating income 1,055 243
Earnings from equity method investments 50 (91)
Interest expense, net of amounts capitalized 238 7
Other income (expense), net (53) (94)
Income taxes 275 102
Net Income $ 539 $ (51)
Operating Revenues
Operating revenues in 2021 were $4.4 billion , reflecting a $946 million , or
27.5%, increase compared to 2020. Details of operating revenues were as follows:
2021
(in millions)
Operating revenues - prior year $ 3,434
Estimated change resulting from -
Infrastructure replacement programs and base rate changes 146
Gas costs and other cost recovery 675
Wholesale gas services 114
Other 11
Operating revenues - current year $ 4,380
Revenues at the natural gas distribution utilities increased in 2021 due to rate increases and continued investment in infrastructure replacement. See Note 2 to the financial statements under "Southern Company Gas " for additional information. Revenues associated with gas costs and other cost recovery increased in 2021 primarily due to higher natural gas cost recovery as a result of higher volumes of natural gas sold and an increase in natural gas prices. The natural gas distribution utilities have weather or revenue normalization mechanisms that mitigate revenue fluctuations from customer consumption changes. Natural gas distribution rates include provisions to adjust billings for fluctuations in natural gas costs. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. See "Cost of Natural Gas" herein for additional information. Revenues from wholesale gas services increased in 2021 primarily due to higher volumes of natural gas sold and higher commercial activities as a result of Winter Storm Uri, partially offset by derivative losses, all prior to the sale of Sequent. See "Segment Information - Wholesale Gas Services" herein and Note 15 to the financial statements under "Southern Company Gas " for additional information.
Heating Degree Days
Southern Company Gas' natural gas distribution utilities have various regulatory mechanisms that limit their exposure to weather changes.Southern Company Gas also uses hedges for any remaining exposure to warmer-than-normal weather inIllinois for gas II-35 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
distribution operations and inIllinois andGeorgia for gas marketing services; therefore, weather typically does not have a significant net income impact. The following table presents Heating Degree Days information forIllinois andGeorgia , the primary locations whereSouthern Company Gas' operations are impacted by weather. Years EndedDecember 31 ,
2021 vs. normal 2021 vs. 2020
Normal(*) 2021 2020 (warmer) (warmer)
(in thousands)
Illinois 5,747 5,326 5,477 (7.3) % (2.8) %
Georgia 2,371 2,113 2,122 (10.9) % (0.4) %
(*)Normal represents the 10-year average from January 1, 2011 through December
31, 2020 for Illinois at Chicago Midway International Airport and for Georgia at
Atlanta Hartsfield-Jackson International Airport , based on information obtained
from the National Oceanic and Atmospheric Administration , National Climatic Data
Center .
Customer Count
The following table provides the number of customers served by
2021 2020
(in thousands, except market share %)
Gas distribution operations 4,337 4,308
Gas marketing services
Energy customers(*) 603 666
Market share of energy customers in Georgia 28.7 % 28.9 %
(*)Gas marketing services' customers are primarily located in Georgia and
Illinois . December 31, 2020 also includes approximately 50,000 customers in Ohio
contracted through an annual auction process to serve for 12 months beginning
April 1, 2020 .
Cost of Natural Gas
ExcludingAtlanta Gas Light , which does not sell natural gas to end-use customers, gas distribution operations charges its utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the applicable state regulatory agencies. Under these mechanisms, all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. Gas distribution operations defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Therefore, gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas and do not affect net income from gas distribution operations. Cost of natural gas at gas distribution operations represented 86.3% of the total cost of natural gas for 2021. Gas marketing services customers are charged for actual and estimated natural gas consumed. Cost of natural gas includes the cost of fuel and associated transportation costs, lost and unaccounted for gas, adjustments to reduce the value of inventories to market value, if applicable, and gains and losses associated with certain derivatives. In 2021, cost of natural gas was$1.6 billion , an increase of$647 million , or 66.6%, compared to 2020, which reflects higher gas cost recovery in 2021 as a result of higher volumes sold and a 91.2% increase in natural gas prices compared to 2020. II-36 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Volumes of Natural Gas Sold
The following table details the volumes of natural gas sold during all periods
presented.
2021 vs. 2020
2021 2020 % Change
Gas distribution operations (mmBtu in millions)
Firm 656 623 5.3 %
Interruptible 98 92 6.5
Total 754 715 5.5 %
Wholesale gas services (mmBtu in millions/day)
Daily physical sales(*) 6.6 6.9 (4.3) %
Gas marketing services (mmBtu in millions)
Firm:
Georgia 34 33 3.0 %
Illinois 7 9 (22.2)
Other 11 13 (15.4)
Interruptible large commercial and industrial 14 14
-
Total 66 69 (4.3) %
(*) Daily physical sales for 2021 reflect amounts through the sale of Sequent on
Other Operations and Maintenance Expenses
In 2021, other operations and maintenance expenses increased$106 million , or 11.0%, compared to 2020. The increase was primarily due to increases of$60 million in compensation expenses,$30 million of which was at Sequent,$10 million in facility costs, and$10 million in bad debt expense, which is passed through directly to customers and has no impact on net income.
Depreciation and Amortization
In 2021, depreciation and amortization increased$36 million , or 7.2%, compared to 2020. The increase was primarily due to continued infrastructure investments at the natural gas distribution utilities. See Note 2 to the financial statements under "Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information.
Taxes Other Than Income Taxes
In 2021, taxes other than income taxes increased$19 million , or 9.2%, compared to 2020. The increase was primarily due to a$15 million increase in revenue tax expenses as a result of higher natural gas revenues atNicor Gas , which are passed through directly to customers and have no impact on net income.
Gain on Dispositions, Net
In 2021, gain on dispositions, net increased$105 million compared to 2020. In 2021,Southern Company Gas recorded a$121 million gain on the sale of Sequent, as well as an additional$5 million gain from the sale of Pivotal LNG. In 2020,Southern Company Gas recorded a$22 million gain on the sale ofJefferson Island . See Note 15 to the financial statements under "Southern Company Gas " for additional information.
Earnings from Equity Method Investments
In 2021, earnings from equity method investments decreased$91 million , or 64.5%, compared to 2020. The decrease was primarily due to impairment charges in 2021 totaling$84 million related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas " for additional information.
Other Income (Expense), Net
In 2021, other income (expense), net decreased$94 million compared to 2020. The decrease was largely due to$101 million in charitable contributions by Sequent prior to its sale. II-37 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Income Taxes
In 2021, income taxes increased$102 million , or 59.0%, compared to 2020. The increase was primarily due to$114 million in additional tax expense resulting from the sale of Sequent, including changes in state tax apportionment rates, and higher pre-tax earnings at gas distribution operations, partially offset by$18 million of tax benefit resulting from the PennEast Pipeline project impairment charges in the second and third quarters of 2021 at gas pipeline investments. See Notes 7 and 15 to the financial statements under "Southern Company Gas " and Note 10 to the financial statements for additional information. Segment Information 2021 2020 Operating Operating Net Income Operating Operating Net Income Revenues Expenses (Loss) Revenues Expenses (Loss) (in millions) (in millions) Gas distribution operations$ 3,679 $ 2,971 $ 412 $ 2,952 $ 2,297 $ 390 Gas pipeline investments 32 11 19 32 12 99 Wholesale gas services 188 (53) 107 74 54 14 Gas marketing services 475 350 88 408 289 89 All other 38 78 (87) 36 43 (2) Intercompany eliminations (32) (32) - (68) (73) - Consolidated$ 4,380 $ 3,325 $ 539 $ 3,434 $ 2,622 $ 590
Gas Distribution Operations
Gas distribution operations is the largest component ofSouthern Company Gas' business and is subject to regulation and oversight by regulatory agencies in each of the states it serves. These agencies approve natural gas rates designed to provideSouthern Company Gas with the opportunity to generate revenues to recover the cost of natural gas delivered to its customers and its fixed and variable costs, including depreciation, interest expense, operations and maintenance, taxes, and overhead costs, and to earn a reasonable return on its investments. With the exception ofAtlanta Gas Light ,Southern Company Gas' second largest utility that operates in a deregulated natural gas market and has a straight-fixed-variable rate design that minimizes the variability of its revenues based on consumption, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas, and general economic conditions that may impact customers' ability to pay for natural gas consumed.Southern Company Gas has various regulatory and other mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit its exposure to changes in customer consumption, including weather changes within typical ranges in its natural gas distribution utilities' service territories. In 2021, net income increased$22 million , or 5.6%, compared to 2020. Operating revenues increased$727 million primarily due to higher gas cost recovery, rate increases, and continued investment in infrastructure replacement. Gas costs recovered through natural gas revenues generally equal the amount expensed in cost of natural gas. Operating expenses increased$674 million primarily due to a$540 million increase in cost of gas as a result of higher natural gas prices and higher volumes sold, largely as a result of colder weather in the first quarter 2021 compared to 2020, higher depreciation resulting from additional assets placed in service, higher taxes other than income taxes due to higher pass through taxes, and higher compensation expenses. Other income and expense decreased$10 million primarily due to a decrease in non-service cost-related retirement benefits income. Interest expense, net of amounts capitalized increased$15 million primarily due to additional debt issued to finance continued investments. Income taxes increased$6 million primarily due to higher pre-tax earnings. See Note 2 to the financial statements under "Southern Company Gas - Rate Proceedings" and " - Infrastructure Replacement Programs and Capital Projects" for additional information. Also see Note 11 to the financial statements for additional information on retirement benefits. II-38 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Gas Pipeline Investments
Gas pipeline investments consists primarily of joint ventures in natural gas pipeline investments including SNG, PennEast Pipeline, Dalton Pipeline, and Atlantic Coast Pipeline (until its sale onMarch 24, 2020 ). In 2021, net income decreased$80 million , or 80.8%, compared to 2020. The decrease was primarily due to impairment charges totaling$84 million ($67 million after tax) related to the PennEast Pipeline project. See Note 7 to the financial statements under "Southern Company Gas " for information regarding theSeptember 2021 cancellation of the PennEast Pipeline project.
Wholesale Gas Services
Prior to the sale of Sequent, wholesale gas services was involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services, and wholesale gas marketing.Southern Company Gas positioned the business to generate positive economic earnings on an annual basis even under low volatility market conditions that can result from a number of factors. When market price volatility increased, wholesale gas services was positioned to capture significant value and generate stronger results. Operating expenses primarily reflected employee compensation and benefits. See Note 15 to the financial statements under "Southern Company Gas " for information regarding the sale of Sequent. In 2021, net income increased$93 million compared to 2020. The increase was primarily due to a$114 million increase in operating revenues due to higher commercial activity driven by natural gas price volatility that was generated by cold weather, partially offset by unfavorable storage and transportation derivatives due to widening transportation spreads, as well as a$121 million gain on the sale of Sequent, partially offset by a$14 million increase in other operating expenses primarily related to an increase in variable compensation, a$101 million decrease in other income and (expense) related to higher charitable contributions, and a$29 million increase in income tax expense due to higher pre-tax earnings. Gas Marketing Services Gas marketing services provides energy-related products and services to natural gas markets and participants in customer choice programs that were approved in various states to increase competition. These programs allow customers to choose their natural gas supplier while the local distribution utility continues to provide distribution and transportation services. Gas marketing services is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts.
In 2021, net income decreased
All Other
All other includes natural gas storage businesses, includingJefferson Island through its sale onDecember 1, 2020 , fuels operations through the sale ofSouthern Company Gas' interest in Pivotal LNG onMarch 24, 2020 ,AGL Services Company , andSouthern Company Gas Capital , as well as various corporate operating expenses that are not allocated to the reportable segments and interest income (expense) associated with affiliate financing arrangements. In 2021, net loss increased$85 million compared to 2020. The increase was primarily due to additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent. See Note 10 to the financial statements and Note 15 to the financial statements under "Southern Company Gas " for additional information.
FUTURE EARNINGS POTENTIAL
General
Prices for electric service provided by the traditional electric operating companies and natural gas distributed by the natural gas distribution utilities to retail customers are set by state PSCs or other applicable state regulatory agencies under cost-based regulatory principles. Retail rates and earnings are reviewed through various regulatory mechanisms and/or processes and may be adjusted periodically within certain limitations. Effectively operating pursuant to these regulatory mechanisms and/or processes and appropriately balancing required costs and capital expenditures with customer prices will continue to challenge the traditional electric operating companies and natural gas distribution utilities for the foreseeable future. Prices for wholesale electricity sales, interconnecting transmission lines, and the exchange of electric power are regulated by theFERC .Southern Power continues to focus on long-term PPAs. See ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Utility Regulation" herein and Note 2 to the financial statements for additional information about regulatory matters. II-39 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Each Registrant's results of operations are not necessarily indicative of its future earnings potential. The disposition activities described in Note 15 to the financial statements have reduced earnings for the applicable Registrants. The level of the Registrants' future earnings depends on numerous factors that affect the opportunities, challenges, and risks of the Registrants' primary businesses of selling electricity and/or distributing natural gas, as described further herein. For the traditional electric operating companies, these factors include the ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs during a time of increasing costs, including those related to projected long-term demand growth, stringent environmental standards, including CCR rules, safety, system reliability and resiliency, fuel, restoration following major storms, and capital expenditures, including constructing new electric generating plants and expanding and improving the transmission and distribution systems; continued customer growth; and the trend of reduced electricity usage per customer, especially in residential and commercial markets. ForGeorgia Power , completing construction of Plant Vogtle Units 3 and 4 and the related cost recovery proceedings is another major factor. Earnings in the electricity business will also depend upon maintaining and growing sales, considering, among other things, the adoption and/or penetration rates of increasingly energy-efficient technologies and increasing volumes of electronic commerce transactions, which could contribute to a net reduction in customer usage. Global andU.S. economic conditions have been significantly affected by a series of demand and supply shocks that caused a global and national economic recession in 2020. Most prominently, the COVID-19 pandemic has negatively impacted global supply chains and business operations as suppliers continue to experience difficulties keeping up with strong demand for factory goods, which is being driven by low business inventories. In addition, rising inflation in 2021 and 2022 has resulted in increasing costs for many goods and services. The combination of rising inoculation rates in theU.S. population and the federal COVID-19 relief package contributed to increased economic recovery in 2021; however, fiscal support of business and personal incomes is declining. The drivers, speed, and depth of the 2020 economic contraction were unprecedented and have reduced energy demand acrossthe Southern Company system's service territory, primarily in the commercial and industrial classes. Retail electric revenues attributable to changes in sales increased in 2021 when compared to 2020 primarily due to the normalization of economic activity; however, retail electric sales continued to be negatively impacted by the COVID-19 pandemic when compared to pre-pandemic trends. Recovery is expected to continue in 2022, but the impacts of new COVID-19 variants, as well as responses to the COVID-19 pandemic by both customers and governments, could significantly affect the pace of recovery. The ultimate extent of the negative impact on revenues depends on the depth and duration of the economic contraction inthe Southern Company system's service territory and cannot be determined at this time. See RESULTS OF OPERATIONS herein for information on COVID-19-related impacts on energy demand inthe Southern Company system's service territory during 2021. The level of future earnings forSouthern Power's competitive wholesale electric business depends on numerous factors including the parameters of the wholesale market and the efficient operation of its wholesale generating assets;Southern Power's ability to execute its growth strategy through the development or acquisition of renewable facilities and other energy projects while containing costs; regulatory matters; customer creditworthiness; total electric generating capacity available inSouthern Power's market areas;Southern Power's ability to successfully remarket capacity as current contracts expire; renewable portfolio standards; availability of federal and state ITCs and PTCs, which could be impacted by future tax legislation; transmission constraints; cost of generation from units withinthe Southern Company power pool; and operational limitations. See "Income Tax Matters" herein, Note 10 to the financial statements, and Note 15 to the financial statements under "Southern Power " for additional information. The level of future earnings forSouthern Company Gas' primary business of distributing natural gas and its complementary businesses in the gas pipeline investments and gas marketing services sectors depends on numerous factors. These factors include the natural gas distribution utilities' ability to maintain constructive regulatory environments that allow for the timely recovery of prudently-incurred costs, including those related to projected long-term demand growth, safety, system reliability and resilience, natural gas, and capital expenditures, including expanding and improving the natural gas distribution systems; the completion and subsequent operation of ongoing infrastructure and other construction projects; customer creditworthiness; certain city-wide bans on the use of natural gas in new construction; andSouthern Company Gas' ability to re-contract storage rates at favorable prices. The volatility of natural gas prices has an impact onSouthern Company Gas' customer rates, its long-term competitive position against other energy sources, and the ability ofSouthern Company Gas' gas marketing services business to capture value from locational and seasonal spreads. Additionally, changes in commodity prices, primarily driven by tight gas supplies and diminished gas production, subject a portion ofSouthern Company Gas' operations to earnings variability. Additional economic factors may contribute to this environment. If current economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis. Alternatively, a significant drop in oil and natural gas prices could lead to a consolidation of natural gas producers or reduced levels of natural gas production. II-40 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Earnings for both the electricity and natural gas businesses are subject to a variety of other factors. These factors include weather, competition, developing new and maintaining existing energy contracts and associated load requirements with wholesale customers, energy conservation practiced by customers, the use of alternative energy sources by customers, government incentives to reduce overall energy usage, the prices of electricity and natural gas, and the price elasticity of demand. Demand for electricity and natural gas in the Registrants' service territories is primarily driven by the pace of economic growth or decline that may be affected by changes in regional and global economic conditions, which may impact future earnings.Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeasternMississippi under full requirements cost-based electric tariffs which are subject to regulation by theFERC . The contracts with these wholesale customers represented 14.3% ofMississippi Power's total operating revenues in 2021 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers. As part of its ongoing effort to adapt to changing market conditions,Southern Company continues to evaluate and consider a wide array of potential business strategies. These strategies may include business combinations, partnerships, and acquisitions involving other utility or non-utility businesses or properties, disposition of, or the sale of interests in, certain assets or businesses, internal restructuring, or some combination thereof. Furthermore,Southern Company may engage in new business ventures that arise from competitive and regulatory changes in the utility industry. Pursuit of any of the above strategies, or any combination thereof, may significantly affect the business operations, risks, and financial condition ofSouthern Company . In addition,Southern Power andSouthern Company Gas regularly consider and evaluate joint development arrangements as well as acquisitions and dispositions of businesses and assets as part of their business strategies. See Note 15 to the financial statements for additional information.
Environmental Matters
The Southern Company system's operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, avian and other wildlife and habitat protection, and other natural resources.The Southern Company system maintains comprehensive environmental compliance and GHG strategies to assess both current and upcoming requirements and compliance costs associated with these environmental laws and regulations. New or revised environmental laws and regulations could further affect many areas of operations for the Subsidiary Registrants. The costs required to comply with environmental laws and regulations and to achieve stated goals, including capital expenditures, operations and maintenance costs, and costs reflected in ARO liabilities, may impact future electric generating unit retirement and replacement decisions (which are subject to approval from the traditional electric operating companies' respective state PSCs), results of operations, cash flows, and/or financial condition. Related costs may result from the installation of additional environmental controls, closure and monitoring of CCR facilities, unit retirements, or changing fuel sources for certain existing units, as well as related upgrades tothe Southern Company system's transmission and distribution (electric and natural gas) systems. A major portion of these costs is expected to be recovered through retail and wholesale rates, including existing ratemaking and billing provisions. The ultimate impact of environmental laws and regulations and the GHG goals discussed herein cannot be determined at this time and will depend on various factors, such as state adoption and implementation of requirements, the availability and cost of any deployed technology, fuel prices, the outcome of pending and/or future legal challenges, and the ability to continue recovering the related costs, through rates for the traditional electric operating companies and the natural gas distribution utilities or through long-term wholesale agreements for the traditional electric operating companies andSouthern Power .Alabama Power andMississippi Power recover environmental compliance costs through separate mechanisms, Rate CNP Compliance and theECO Plan , respectively.Georgia Power's base rates include an ECCR tariff that allows for the recovery of environmental compliance costs. The natural gas distribution utilities ofSouthern Company Gas generally recover environmental remediation expenditures through rate mechanisms approved by their applicable state regulatory agencies. See Notes 2 and 3 to the financial statements for additional information.Southern Power's PPAs generally contain provisions that permit charging the counterparty with some of the new costs incurred as a result of changes in environmental laws and regulations. SinceSouthern Power's units are generally newer natural gas and renewable generating facilities, costs associated with environmental compliance for these facilities have been less significant than for similarly situated coal or older natural gas generating facilities. Environmental, natural resource, and land use concerns, including the applicability of air quality limitations, the potential presence of wetlands or threatened and endangered species, the availability of water withdrawal rights, uncertainties regarding impacts such as increased light or noise, and concerns about potential adverse health impacts can, however, increase the cost of siting and operating any type of future facility. The impact of such laws, regulations, and other considerations onSouthern Power and subsequent recovery through PPA provisions cannot be determined at this time. II-41 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Further, increased costs that are recovered through regulated rates could contribute to reduced demand for electricity and natural gas, which could negatively affect results of operations, cash flows, and/or financial condition. Additionally, many commercial and industrial customers may also be affected by existing and future environmental requirements, which may have the potential to affect their demand for electricity and natural gas.
Although the timing, requirements, and estimated costs could change as
environmental laws and regulations are adopted or modified, as compliance plans
are revised or updated, and as legal challenges to rules are initiated or
completed, estimated capital expenditures through 2026 based on the current
environmental compliance strategy for
2022 2023 2024 2025 2026 Total
(in millions)
Southern Company $ 98 $ 111 $ 146 $ 72 $ 58 $ 485
Alabama Power 49 35 50 33 28 195
Georgia Power 37 75 91 34 25 262
Mississippi Power 12 1 5 5 5 28
These estimates do not include any costs associated with potential regulation of
GHG emissions. See "Global Climate Issues" herein for additional information.
The Southern Company system also anticipates substantial expenditures associated
with ash pond closure and groundwater monitoring under the CCR Rule and related
state rules, which are reflected in the applicable Registrants' ARO liabilities.
See FINANCIAL CONDITION AND LIQUIDITY - "Cash Requirements" herein and Note 6 to
the financial statements for additional information.
Environmental Laws and Regulations
Air Quality
The Southern Company system reduced SO2 and NOX air emissions by 99% and 93%, respectively, from 1990 to 2020.The Southern Company system reduced mercury air emissions by 98% from 2005 to 2020. TheEPA finalized regional haze regulations in 2005 and 2017. These regulations require states and various federal agencies to develop and implement plans to reduce pollutants that impair visibility and demonstrate reasonable progress toward the goal of restoring natural visibility conditions in certain areas, including national parks and wilderness areas. States were required to submit state implementation plans for the second 10-year planning period (2018 through 2028) byJuly 31, 2021 ; however, plans have not yet been submitted by the applicable states inthe Southern Company system's service territory. These plans could require further reductions in particulate matter, SO2, and/or NOX, which could result in increased compliance costs at affected electric generating units. Water Quality In 2014, theEPA finalized requirements under Section 316(b) of the Clean Water Act (CWA) to regulate cooling water intake structures (CWIS) to minimize their effects on fish and other aquatic life at existing power plants. The regulation requires plant-specific studies to determine applicable CWIS changes to protect organisms. The results of these plant-specific studies, which are ongoing withinthe Southern Company system, are being submitted with each plant's next National Pollutant Discharge Elimination System (NPDES) permit cycle.The Southern Company system anticipates applicable CWIS changes may include fish-friendly CWIS screens with fish return systems and minor additions of monitoring equipment at certain plants. The impact of this rule will depend on the outcome of these plant-specific studies, any additional protective measures required to be incorporated into each plant's NPDES permit based on site-specific factors, and the outcome of any legal challenges. InOctober 2020 , theEPA published the final steam electric ELG reconsideration rule (ELG Reconsideration Rule), a reconsideration of the 2015 ELG rule's limits on bottom ash transport water and flue gas desulfurization wastewater that extends the latest applicability date for both discharges toDecember 31, 2025 . The ELG Reconsideration Rule also updates the voluntary incentive program and provides new subcategories for low utilization electric generating units and electric generating units that will permanently cease coal combustion by 2028. As required by the ELG Reconsideration Rule, onOctober 13, 2021 ,Alabama Power andGeorgia Power each submitted initial notices of planned participation (NOPP) for applicable units seeking to qualify for these subcategories.Alabama Power submitted its NOPP to theAlabama Department of Environmental Management (ADEM) indicating plans to retire Plant Barry Unit 5 (700 MWs) and to cease using coal and begin operating solely on natural gas at Plant Barry Unit 4 (350 II-42 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
MWs) and Plant Gaston Unit 5 (880 MWs).Alabama Power , as agent for SEGCO, indicated plans to retire Plant Gaston Units 1 through 4 (1,000 MWs). These plans are expected to be completed on or before the compliance date ofDecember 31, 2028 . The NOPP submittals are subject to the review of the ADEM. Retirement of Plant Barry Unit 5 could occur as early as 2023, subject to completion of the acquisition of theCalhoun Generating Station and certain operating conditions. See Notes 2 and 7 to the financial statements under "Alabama Power - Certificates of Convenience and Necessity" and "SEGCO," respectively, for additional information. The assets for whichAlabama Power has indicated retirement, due to early closure or repowering of the unit to natural gas, have net book values totaling approximately$1.5 billion (excluding capitalized asset retirement costs which are recovered through Rate CNP Compliance) atDecember 31, 2021 . Based on an Alabama PSC order,Alabama Power is authorized to establish a regulatory asset to record the unrecovered investment costs, including the plant asset balance and the site removal and closure costs, associated with unit retirements caused by environmental regulations (Environmental Accounting Order). Under the Environmental Accounting Order, the regulatory asset would be amortized and recovered over an affected unit's remaining useful life, as established prior to the decision regarding early retirement, through Rate CNP Compliance. See Note 2 to the financial statements under "Alabama Power - Rate CNP Compliance" and " - Environmental Accounting Order" for additional information.Georgia Power submitted its NOPP to the Georgia Environmental Protection Division (EPD) indicating plans to retire Plant Wansley Units 1 and 2 (926 MWs based on 53.5% ownership), Plant Bowen Units 1 and 2 (1,400 MWs), and Plant Scherer Unit 3 (614 MWs based on 75% ownership) on or before the compliance date ofDecember 31, 2028 .Georgia Power intends to pursue compliance with the ELG Reconsideration Rule for Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) through the voluntary incentive program by no later thanDecember 31, 2028 .Georgia Power intends to comply with the ELG Rules for Plant Bowen Units 3 and 4 through the generally applicable requirements byDecember 31, 2025 ; therefore, no NOPP submission was required for these units. The NOPP submittals and generally applicable requirements are subject to the review of theGeorgia EPD. The units for whichGeorgia Power has indicated early retirement plans have net book values totaling approximately$2.2 billion (excluding capitalized asset retirement costs which are recovered through the ECCR tariff) atDecember 31, 2021 . A final decision regarding the future operation ofGeorgia Power's impacted units and the timing of any retirements are subject to review by the Georgia PSC as a part ofGeorgia Power's 2022 IRP proceeding. See Note 2 to the financial statements under "Georgia Power - Integrated Resource Plan" for additional information.
The ultimate outcome of these matters cannot be determined at this time.
The ELG Reconsideration Rule is expected to require capital expenditures and increased operational costs for the traditional electric operating companies and SEGCO. However, the ultimate impact of the ELG Reconsideration Rule will depend onthe Southern Company system's final assessment of compliance options, the incorporation of these assessments into each of the traditional electric operating company's IRP process, the incorporation of these new requirements into each plant's NPDES permit, and the outcome of legal challenges. The ELG Reconsideration Rule has been challenged by several environmental organizations and the cases have been consolidated in theU.S. Court of Appeals for the Fourth Circuit . The case is being held in abeyance while theEPA undertakes a new rulemaking to revise the ELG Reconsideration Rule. A proposed rule is expected in the fall of 2022. Any revisions could require changes in the traditional electric operating companies' compliance strategies.
Coal Combustion Residuals
In 2015, theEPA finalized non-hazardous solid waste regulations for the management and disposal of CCR, including coal ash and gypsum, in landfills and surface impoundments (ash ponds) at active electric generating power plants. The CCR Rule requires landfills and ash ponds to be evaluated against a set of performance criteria and potentially closed if certain criteria are not met. Closure of existing landfills and ash ponds requires installation of equipment and infrastructure to manage CCR in accordance with the CCR Rule. In addition to the federal CCR Rule, the States ofAlabama andGeorgia finalized state regulations regarding the management and disposal of CCR within their respective states. In 2019, theState of Georgia received partial approval from theEPA for its state CCR permitting program. TheState of Mississippi has not developed a state CCR permit program. The Holistic Approach to Closure: Part A rule, finalized inAugust 2020 , revised the deadline to stop sending CCR and non-CCR wastes to unlined surface impoundments toApril 11, 2021 and established a process for theEPA to approve extensions to the deadline. The traditional electric operating companies stopped sending CCR and non-CCR wastes to their unlined impoundments prior toApril 11, 2021 and, therefore, did not submit requests for extensions. OnJanuary 11, 2022 , theEPA proposed determinations on deadline extension requests for other non-affiliated facilities, which reflected its positions on a variety of CCR Rule compliance requirements including closure standards, groundwater monitoring, and corrective action. The traditional electric operating companies are in the process of reviewing these determinations to determine how theEPA 's current positions may II-43 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
impact their closure plans and groundwater monitoring efforts. The ultimate
impact of the
Based on requirements for closure and monitoring of landfills and ash ponds pursuant to the CCR Rule and applicable state rules, the traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to closure methodologies, schedules, and/or costs becomes available. Some of these updates have been, and future updates may be, material. Additionally, the closure designs and plans in the States ofAlabama andGeorgia are subject to approval by environmental regulatory agencies. Absent continued recovery of ARO costs through regulated rates, results of operations, cash flows, and financial condition forSouthern Company and the traditional electric operating companies could be materially impacted. See FINANCIAL CONDITION AND LIQUIDITY - "Cash Requirements," Note 2 to the financial statements under "Georgia Power - Rate Plans," and Note 6 to the financial statements for additional information.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations governing the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations,the Southern Company system could incur substantial costs to clean up affected sites. The traditional electric operating companies andSouthern Company Gas conduct studies to determine the extent of any required cleanup and have recognized the estimated costs to clean up known impacted sites in their financial statements. Amounts for cleanup and ongoing monitoring costs were not material for any year presented. The traditional electric operating companies and the natural gas distribution utilities inIllinois andGeorgia (which represent substantially all ofSouthern Company Gas' accrued remediation costs) have all received authority from their respective state PSCs or other applicable state regulatory agencies to recover approved environmental remediation costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the state PSCs or other applicable state regulatory agencies. The traditional electric operating companies andSouthern Company Gas may be liable for some or all required cleanup costs for additional sites that may require environmental remediation. See Note 3 to the financial statements under "Environmental Remediation" for additional information.
Global Climate Issues
In 2019, theEPA published the final Affordable Clean Energy rule (ACE Rule), which would have required states to develop unit-specific CO2 emission rate standards for existing coal-fired units based on heat-rate efficiency improvements. OnJanuary 19, 2021 , theU.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the ACE Rule back to theEPA . OnOctober 29, 2021 , theU.S. Supreme Court granted four petitions for writs of certiorari asking the court to review theDistrict of Columbia Circuit's decision.The U.S. Supreme Court's review will focus on the extent of theEPA 's authority to regulate GHG emissions from the power sector under Section 111(d) of the Clean Air Act. OnFebruary 19, 2021 ,the United States officially rejoined the Paris Agreement. The Paris Agreement establishes a non-binding universal framework for addressing GHG emissions based on nationally determined emissions reduction contributions and sets in place a process for tracking progress towards the goals every five years. OnApril 22, 2021 President Biden announced a new target forthe United States to achieve a 50% to 52% reduction in economy-wide GHG emissions from 2005 levels by 2030. The target was accepted by theUnited Nations asthe United States' nationally determined emissions reduction contribution under theParis Agreement. Additional GHG policies, including legislation, may emerge in the future requiringthe United States to transition to a lower GHG emitting economy; however, associated impacts are currently unknown.The Southern Company system has transitioned from an electric generating mix of 70% coal and 15% natural gas in 2007 to a mix of 22% coal and 48% natural gas in 2021. This transition has been supported in part bythe Southern Company system retiring over 5,600 MWs of coal-fired generating capacity since 2010 and converting over 3,400 MWs of generating capacity from coal to natural gas since 2015, as well as constructing and/or acquiring over 11,000 MWs of renewable resource capacity since 2010. See "Environmental Laws and Regulations - Water Quality" herein for information on plans to retire or convert to natural gas additional coal-fired generating capacity. In addition,Southern Company Gas has replaced over 6,000 miles of pipe material that was more prone to fugitive emissions (unprotected steel and cast-iron pipe), resulting in mitigation of more than 3.3 million metric tons of CO2 equivalents from its natural gas distribution system since 1998. II-44 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The following table provides the Registrants' 2020 and preliminary 2021 GHG emissions based on equity share of facilities:
2020 Preliminary 2021
(in million metric tons of CO2 equivalent)
Southern Company(*) 75 82
Alabama Power(*) 28 34
Georgia Power 21 23
Mississippi Power 8 8
Southern Power 12 11
Southern Company Gas(*) 1 1
(*)Includes GHG emissions attributable to disposed assets through the date of
the applicable disposition and to acquired assets beginning with the date of the
applicable acquisition. See Note 15 to the financial statements for additional
information.
Southern Company system management has established an intermediate goal of a 50%
reduction in GHG emissions from 2007 levels by 2030 and a long-term goal of net
zero GHG emissions by 2050. Based on the preliminary 2021 emissions, the
Southern Company system has achieved an estimated GHG emission reduction of 47%
since 2007. In 2020, the COVID-19 pandemic resulted in reduced electricity usage
by customers, which led to a higher than expected decline in GHG emissions. In
2021, increased customer demand combined with increased utilization of the coal
generating fleet due to higher natural gas prices resulted in an increase in GHG
emissions from 2020 levels. Southern Company system management expects to
achieve sustained GHG emissions reductions of at least 50% as early as 2025.
Southern Company system management, working with applicable regulators, plans to
transition its generating fleet in a manner responsible to customers,
communities, employees, and other stakeholders. Achievement of these goals is
dependent on many factors, including natural gas prices and the pace and extent
of development and deployment of low- to no-GHG energy technologies and negative
carbon concepts. Southern Company system management plans to continue to pursue
a diverse portfolio including low-carbon and carbon-free resources and energy
efficiency resources; continue to transition the Southern Company system's
generating fleet and make the necessary related investments in transmission and
distribution systems; continue its research and development with a particular
focus on technologies that lower GHG emissions, including methods of removing
carbon from the atmosphere; and constructively engage with policymakers,
regulators, investors, customers, and other stakeholders to support outcomes
leading to a net zero future.
Regulatory Matters
See OVERVIEW - "Recent Developments" herein and Note 2 to the financial
statements for a discussion of regulatory matters related to Alabama Power ,
Georgia Power , Mississippi Power , and Southern Company Gas , including items that
could impact the applicable registrants' future earnings, cash flows, and/or
financial condition.
Construction Programs
The Subsidiary Registrants are engaged in continuous construction programs to
accommodate existing and estimated future loads on their respective systems. The
Southern Company system intends to continue its strategy of developing and
constructing new electric generating facilities, expanding and improving the
electric transmission and electric and natural gas distribution systems, and
undertaking projects to comply with environmental laws and regulations.
For the traditional electric operating companies, major generation construction
projects are subject to state PSC approval in order to be included in retail
rates. The largest construction project currently underway in the Southern
Company system is Plant Vogtle Units 3 and 4. See Note 2 to the financial
statements under "Georgia Power - Nuclear Construction " for additional
information. Also see Note 2 to the financial statements under "Alabama Power -
Certificates of Convenience and Necessity" for information regarding Alabama
Power's construction of Plant Barry Unit 8.
See Note 15 to the financial statements under "
Southern Company Gas is engaged in various infrastructure improvement programs designed to update or expand the natural gas distribution systems of the natural gas distribution utilities to improve reliability and meet operational flexibility and growth. The natural gas distribution utilities recover their investment and a return associated with these infrastructure programs through their regulated rates. See Note 2 to the financial statements under "Southern Company Gas - Infrastructure Replacement Programs and Capital Projects" for additional information onSouthern Company Gas' construction program. II-45 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
See FINANCIAL CONDITION AND LIQUIDITY - "Cash Requirements" herein for additional information regarding the Registrants' capital requirements for their construction programs, including estimated totals for each of the next five years.
General
Southern Power has PPAs with some of the traditional electric operating companies, other investor-owned utilities, IPPs, municipalities, and other load-serving entities, as well as commercial and industrial customers. The PPAs are expected to provideSouthern Power with a stable source of revenue during their respective terms. Many ofSouthern Power's PPAs have provisions that requireSouthern Power or the counterparty to post collateral or an acceptable substitute guarantee if (i) S&P or Moody's downgrades the credit ratings of the respective company to an unacceptable credit rating, (ii) the counterparty is not rated, or (iii) the counterparty fails to maintain a minimum coverage ratio.Southern Power is working to maintain and expand its share of the wholesale markets. During 2021,Southern Power continued to be successful in remarketing up to 2,025 MWs of annual natural gas generation capacity to load-serving entities through several PPAs extending over the next 16 years. Market demand is being driven by load-serving entities replacing expired purchase contracts and/or retired generation, as well as planning for future growth.
Natural Gas
Southern Power's electricity sales from natural gas facilities are primarily through long-term PPAs that consist of two types of agreements. The first type, referred to as a unit or block sale, is a customer purchase from a dedicated generating unit where all or a portion of the generation from that unit is reserved for that customer.Southern Power typically has the ability to serve the unit or block sale customer from an alternate resource. The second type, referred to as requirements service, provides thatSouthern Power serve the customer's capacity and energy requirements from a combination of the customer's own generating units and fromSouthern Power resources not dedicated to serve unit or block sales.Southern Power has rights to purchase power provided by the requirements customers' resources when economically viable. As a general matter, substantially all of the PPAs provide that the purchasers are responsible for either procuring the fuel (tolling agreements) or reimbursingSouthern Power for substantially all of the cost of fuel or purchased power relating to the energy delivered under such PPAs. To the extent a particular generating facility does not meet the operational requirements contemplated in the PPAs,Southern Power may be responsible for excess fuel costs. With respect to fuel transportation risk, most ofSouthern Power's PPAs provide that the counterparties are responsible for the availability of fuel transportation to the particular generating facility. Capacity charges that form part of the PPA payments are designed to recover fixed and variable operation and maintenance costs based on dollars-per-kilowatt year. In general, to reduceSouthern Power's exposure to certain operation and maintenance costs,Southern Power has LTSAs. See Note 1 to the financial statements under "Long-Term Service Agreements" for additional information.
Solar and Wind
Southern Power's electricity sales from solar and wind generating facilities are also primarily through long-term PPAs; however, these solar and wind PPAs do not have a capacity charge and customers either purchase the energy output of a dedicated renewable facility through an energy charge or provideSouthern Power a certain fixed price for the electricity sold to the grid. As a result,Southern Power's ability to recover fixed and variable operations and maintenance expenses is dependent upon the level of energy generated from these facilities, which can be impacted by weather conditions, equipment performance, transmission constraints, and other factors. Generally, under the renewable generation PPAs, the purchasing party retains the right to keep or resell the renewable energy credits. Income Tax Matters Consolidated Income Taxes The impact of certain tax events atSouthern Company and/or its other subsidiaries can, and does, affect each Registrant's ability to utilize certain tax credits. See "Tax Credits" and ACCOUNTING POLICIES - "Application of Critical Accounting Policies and Estimates - Accounting for Income Taxes" herein and Note 10 to the financial statements for additional information. II-46 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Tax Credits
The Tax Reform Legislation, as modified by the 2021 Consolidated Appropriations
Act signed into law in
ITC Percentage
30% Prior to December 31, 2019
26% From 2020 through 2022
22% During 2023
A permanent 10% ITC will remain for projects that commence construction on or
after
In addition, various tax legislation has retained or extended wind energy incentives as described in the following table:
PTC Percentage
100% 2016
80% 2017
60% 2018
40% 2019
60% 2020 or 2021
0% 2022 and after
Southern Power's ITCs relate to its investment in new solar facilities and battery energy storage facilities (co-located with existing solar facilities) that are acquired or constructed and its PTCs relate to the first 10 years of energy production from its wind facilities, which have had, and may continue to have, a material impact onSouthern Power's cash flows and net income. AtDecember 31, 2021 ,Southern Company andSouthern Power had approximately$1.2 billion and$0.8 billion , respectively, of unutilized federal ITCs and PTCs, which are currently expected to be fully utilized by 2024, but could be further delayed. Since 2018,Southern Power has been utilizing tax equity partnerships for wind, solar, and battery energy storage projects, where the tax partner takes significantly all of the respective federal tax benefits. These tax equity partnerships are consolidated inSouthern Company's andSouthern Power's financial statements using the HLBV methodology to allocate partnership gains and losses. See Note 1 to the financial statements under "General" for additional information on the HLBV methodology and Note 1 to the financial statements under "Income Taxes" and Note 10 to the financial statements under "Deferred Tax Assets and Liabilities - Tax Credit Carryforwards" and "Effective Tax Rate" for additional information regarding utilization and amortization of credits and the tax benefit related to associated basis differences.
General Litigation and Other Matters
The Registrants are involved in various matters being litigated and/or regulatory and other matters that could affect future earnings, cash flows, and/or financial condition. The ultimate outcome of such pending or potential litigation against each Registrant and any subsidiaries or regulatory and other matters cannot be determined at this time; however, for current proceedings and/or matters not specifically reported herein or in Notes 2 and 3 to the financial statements, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings and/or matters would have a material effect on such Registrant's financial statements. See Notes 2 and 3 to the financial statements for a discussion of various contingencies, including matters being litigated, regulatory matters, and other matters which may affect future earnings potential.
ACCOUNTING POLICIES
Application of Critical Accounting Policies and Estimates
The Registrants prepare their financial statements in accordance with GAAP. Significant accounting policies are described in the notes to the financial statements. In the application of these policies, certain estimates are made that may have a material impact on the results of operations and related disclosures of the applicable Registrants (as indicated in the section descriptions herein). Different assumptions and measurements could produce estimates that are significantly different from those recorded in the
II-47
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
financial statements. Senior management has reviewed and discussed the following critical accounting policies and estimates with the Audit Committee ofSouthern Company's Board of Directors.
Utility Regulation (
The traditional electric operating companies and the natural gas distribution utilities are subject to retail regulation by their respective state PSCs or other applicable state regulatory agencies and wholesale regulation by theFERC . These regulatory agencies set the rates the traditional electric operating companies and the natural gas distribution utilities are permitted to charge customers based on allowable costs, including a reasonable ROE. As a result, the traditional electric operating companies and the natural gas distribution utilities apply accounting standards which require the financial statements to reflect the effects of rate regulation. Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of the accounting standards for rate regulated entities also impacts their financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the traditional electric operating companies and the natural gas distribution utilities; therefore, the accounting estimates inherent in specific costs such as depreciation, AROs, and pension and other postretirement benefits have less of a direct impact on the results of operations and financial condition of the applicable Registrants than they would on a non-regulated company. Revenues related to regulated utility operations as a percentage of total operating revenues in 2021 for the applicable Registrants were as follows: 88% forSouthern Company , 98% forAlabama Power , 96% forGeorgia Power , 99.7% forMississippi Power , and 84% forSouthern Company Gas . As reflected in Note 2 to the financial statements, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and any requirement to refund these regulatory liabilities based on applicable regulatory guidelines and GAAP. However, adverse legislative, judicial, or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact the financial statements of the applicable Registrants. Estimated Cost, Schedule, and Rate Recovery for the Construction ofPlant Vogtle Units 3 and 4 (Southern Company andGeorgia Power ) In 2016, the Georgia PSC approved the Vogtle Cost Settlement Agreement, which resolved certain prudency matters in connection withGeorgia Power's fifteenth VCM report. In 2017, the Georgia PSC approvedGeorgia Power's seventeenth VCM report, which included a recommendation to continue construction ofPlant Vogtle Units 3 and 4, with Southern Nuclear serving as project manager and Bechtel serving as the primary construction contractor, as well as a modification of the Vogtle Cost Settlement Agreement. The Georgia PSC's related order stated that under the modified Vogtle Cost Settlement Agreement, (i) none of the$3.3 billion of costs incurred throughDecember 31, 2015 should be disallowed as imprudent; (ii) the Contractor Settlement Agreement was reasonable and prudent and none of the$0.3 billion paid pursuant to the Contractor Settlement Agreement should be disallowed from rate base on the basis of imprudence; (iii) capital costs incurred up to$5.68 billion would be presumed to be reasonable and prudent with the burden of proof on any party challenging such costs; (iv)Georgia Power would have the burden of proof to show that any capital costs above$5.68 billion were prudent; (v)Georgia Power's total project capital cost forecast of$7.3 billion (net of$1.7 billion received under the Guarantee Settlement Agreement and approximately$188 million in related customer refunds) was found reasonable and did not represent a cost cap; and (vi) a prudence proceeding on cost recovery will occur subsequent to achieving fuel load for Unit 4. In its order, the Georgia PSC also stated if other conditions change and assumptions upon whichGeorgia Power's seventeenth VCM report are based do not materialize, the Georgia PSC reserved the right to reconsider the decision to continue construction. As ofDecember 31, 2021 ,Georgia Power revised its total project capital cost forecast to$10.4 billion (net of$1.7 billion received under the Guarantee Settlement Agreement and approximately$188 million in related customer refunds). This forecast includes construction contingency of$150 million and is based on projected in-service dates at the end of the first quarter 2023 and the fourth quarter 2023 for Units 3 and 4, respectively. Since 2018, established construction contingency and additional costs totaling$2.2 billion have been assigned to the base capital cost forecast. AlthoughGeorgia Power believes these incremental costs are reasonable and necessary to complete the project and the Georgia PSC's order in the seventeenth VCM proceeding specifically states that the construction of Plant Vogtle Units 3 and 4 is not subject to a cost cap,Georgia Power will not seek rate recovery for the$0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income byGeorgia Power in the second quarter 2018 and has not sought rate recovery for the construction contingency costs. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these II-48 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in these future regulatory proceedings,Georgia Power recorded total pre-tax charges to income of$1.1 billion ($0.8 billion after tax) in the second quarter 2018;$149 million ($111 million after tax) and$176 million ($131 million after tax) in the second quarter and the fourth quarter 2020, respectively; and$48 million ($36 million after tax),$460 million ($343 million after tax),$264 million ($197 million after tax), and$480 million ($358 million after tax) in the first quarter 2021, the second quarter 2021, the third quarter 2021, and the fourth quarter 2021, respectively.Georgia Power and the other Vogtle Owners do not agree on either the starting dollar amount for the determination of cost increases subject to the cost-sharing and tender provisions of the Global Amendments (as defined in Note 2 to the financial statements under "Georgia Power -Nuclear Construction - Joint Owner Contracts") or the extent to which COVID-19-related costs impact the calculation. Based on the definition in the Global Amendments,Georgia Power believes the starting dollar amount is$18.38 billion and the current project capital cost forecast has triggered the cost-sharing provisions. The other Vogtle Owners have asserted that the project cost increases have reached the cost-sharing thresholds and have triggered the tender provisions under the Global Amendments.Georgia Power recorded an additional pre-tax charge to income in the fourth quarter 2021 of approximately$440 million ($328 million after tax) associated with these cost-sharing and tender provisions, which is included in the total project capital cost forecast.Georgia Power may be required to record further pre-tax charges to income of up to approximately$460 million associated with these provisions based on the current project capital cost forecast. The incremental charges associated with these provisions will not be recovered from retail customers. OnOctober 29, 2021 ,Georgia Power and the other Vogtle Owners entered into an agreement to clarify the process for the tender provisions of the Global Amendments to provide for a decision between 120 and 180 days after the tender option is triggered, which the other Vogtle Owners assert occurred onFebruary 14, 2022 . See Note 2 to the financial statements under "Georgia Power -Nuclear Construction - Joint Owner Contracts" for additional information on the Global Amendments. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.Georgia Power estimates the productivity impacts of the COVID-19 pandemic have consumed approximately three to four months of schedule margin previously embedded in the site work plan for Unit 3 and Unit 4. As Unit 3 completes system turnover from construction and moves to testing and transition to operations, ongoing and potential future challenges include completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, and final component and pre-operational tests. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical installation, availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3 construction efforts, and the pace of work package closures and system turnovers. As construction, including subcontract work, continues on both Units 3 and 4, ongoing or future challenges include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction and testing activities at Plant Vogtle Units 3 and 4. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. Findings resulting from such inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs. The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described in Note II-49 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
2, is estimated to result in additional base capital costs forGeorgia Power of up to$60 million per month for Unit 3 and$40 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. WhileGeorgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing and tender provisions of the joint ownership agreements described above, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material. Given the significant complexity involved in estimating the future costs to complete construction and start-up of Plant Vogtle Units 3 and 4 and the significant management judgment necessary to assess the related uncertainties surrounding future rate recovery of any projected cost increases, as well as the potential impact on results of operations and cash flows,Southern Company andGeorgia Power consider these items to be critical accounting estimates. See Note 2 to the financial statements under "Georgia Power -Nuclear Construction " for additional information.
Accounting for Income Taxes (
The consolidated income tax provision and deferred income tax assets and liabilities, as well as any unrecognized tax benefits and valuation allowances, require significant judgment and estimates. These estimates are supported by historical tax return data, reasonable projections of taxable income, the ability and intent to implement tax planning strategies if necessary, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. The effective tax rate reflects the statutory tax rates and calculated apportionments for the various states in whichthe Southern Company system operates.Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, eachSouthern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance withIRS regulations, each company is jointly and severally liable for the federal tax liability. Certain deductions and credits can be limited or utilized at the consolidated or combined level resulting in tax credit and/or state NOL carryforwards that would not otherwise result on a stand-alone basis. Utilization of these carryforwards and the assessment of valuation allowances are based on significant judgment and extensive analysis ofSouthern Company's and its subsidiaries' current financial position and results of operations, including currently available information about future years, to estimate when future taxable income will be realized. Current and deferred state income tax liabilities and assets are estimated based on laws of multiple states that determine the income to be apportioned to their jurisdictions. States have various filing methodologies and utilize specific formulas to calculate the apportionment of taxable income. The calculation of deferred state taxes considers apportionment factors and filing methodologies that are expected to apply in future years. The apportionments and methodologies which are ultimately finalized in a manner inconsistent with expectations could have a material effect on the financial statements of the applicable Registrants. Given the significant judgment involved in estimating tax credit and/or state NOL carryforwards and multi-state apportionments for all subsidiaries, the applicable Registrants consider deferred income tax liabilities and assets to be critical accounting estimates.
Asset Retirement Obligations (
AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition,Alabama Power andGeorgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley andGeorgia Power's ownership interests inPlant Hatch and Plant Vogtle Units 1 and 2). Other significant AROs include various landfill sites and asbestos removal forAlabama Power ,Georgia Power , andMississippi Power and gypsum cells and mine reclamation forMississippi Power . The traditional electric operating companies andSouthern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property II-50 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
associated withthe Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. The cost estimates for AROs related to the disposal of CCR are based on information using various assumptions related to closure and post-closure costs, timing of future cash outlays, inflation and discount rates, and the potential methods for complying with the CCR Rule and the related state rules. The traditional electric operating companies have periodically updated, and expect to continue periodically updating, their related cost estimates and ARO liabilities for each CCR unit as additional information related to these assumptions becomes available. Some of these updates have been, and future updates may be, material. See Note 6 to the financial statements for additional information, including increases to AROs related to ash ponds recorded during 2021 by certain Registrants.
Given the significant judgment involved in estimating AROs, the applicable Registrants consider the liabilities for AROs to be critical accounting estimates.
Pension and Other Postretirement Benefits (
The applicable Registrants' calculations of pension and other postretirement benefits expense are dependent on a number of assumptions. These assumptions include discount rates, healthcare cost trend rates, expected long-term rate of return (LRR) on plan assets, mortality rates, expected salary and wage increases, and other factors. Components of pension and other postretirement benefits expense include interest and service cost on the pension and other postretirement benefit plans, expected return on plan assets, and amortization of certain unrecognized costs and obligations. Actual results that differ from the assumptions utilized are accumulated and amortized over future periods and, therefore, generally affect recognized expense and the recorded obligation in future periods. While the applicable Registrants believe the assumptions used are appropriate, differences in actual experience or significant changes in assumptions would affect their pension and other postretirement benefit costs and obligations. Key elements in determining the applicable Registrants' pension and other postretirement benefit expense are the LRR and the discount rate used to measure the benefit plan obligations and the periodic benefit plan expense for future periods. For purposes of determining the applicable Registrants' liabilities related to the pension and other postretirement benefit plans,Southern Company discounts the future related cash flows using a single-point discount rate for each plan developed from the weighted average of market-observed yields for high quality fixed income securities with maturities that correspond to expected benefit payments. The discount rate assumption impacts both the service cost and non-service costs components of net periodic benefit costs as well as the projected benefit obligations. The LRR on pension and other postretirement benefit plan assets is based onSouthern Company's investment strategy, as described in Note 11 to the financial statements, historical experience, and expectations that consider external actuarial advice, and represents the average rate of earnings expected over the long term on the assets invested to provide for anticipated future benefit payments.Southern Company determines the amount of the expected return on plan assets component of non-service costs by applying the LRR of various asset classes toSouthern Company's target asset allocation. The LRR only impacts the non-service costs component of net periodic benefit costs for the following year and is set annually at the beginning of the year. II-51 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The following table illustrates the sensitivity to changes in the applicable
Registrants' long-term assumptions with respect to the discount rate, salary
increases, and the long-term rate of return on plan assets:
Increase/(Decrease) in
Projected Obligation for
Projected Obligation for Other Postretirement
Total Benefit Expense Pension Plan at December 31, Benefit Plans at
25 Basis Point Change in: for 2022 2021 December 31, 2021
(in millions)
Discount rate:
Southern Company $44 /$(43) $610 /$(575) $53 /$(51)
Alabama Power $12 /$(12) $149 /$(140) $14 /$(13)
Georgia Power $12 /$(12) $180 /$(170) $18 /$(17)
Mississippi Power $2 /$(2) $27 /$(26) $2 /$(2)
Southern Company Gas $-/$- $40 /$(38) $6 /$(6)
Salaries:
Southern Company $26 /$(24) $131 /$(127) $-/$-
Alabama Power $8 /$(7) $37 /$(36) $-/$-
Georgia Power $7 /$(7) $37 /$(36) $-/$-
Mississippi Power $1 /$(1) $6 /$(6) $-/$-
Southern Company Gas $-/$- $2 /$(2) $-/$-
Long-term return on plan assets:
Southern Company $41 /$(41) N/A N/A
Alabama Power $10 /$(10) N/A N/A
Georgia Power $13 /$(13) N/A N/A
Mississippi Power $2 /$(2) N/A N/A
Southern Company Gas $3 /$(3) N/A N/A
See Note 11 to the financial statements for additional information regarding pension and other postretirement benefits.
Asset Impairment (
The acquisition method of accounting requires the assets acquired and liabilities assumed to be recorded at the date of acquisition at their respective estimated fair values. The applicable Registrants have recognized goodwill as of the date of their acquisitions, as a residual over the fair values of the identifiable net assets acquired.Goodwill is tested for impairment at the reporting unit level on an annual basis in the fourth quarter of the year as well as on an interim basis as events and changes in circumstances occur, including, but not limited to, a significant change in operating performance, the business climate, legal or regulatory factors, or a planned sale or disposition of a significant portion of the business. A reporting unit is the operating segment, or a business one level below the operating segment (a component), if discrete financial information is prepared and regularly reviewed by management. Components are aggregated if they have similar economic characteristics. As part of the impairment tests, the applicable Registrant may perform an initial qualitative assessment to determine whether it is more likely than not that the fair value of each reporting unit is less than its carrying amount before applying the quantitative goodwill impairment test. If the applicable Registrant elects to perform the qualitative assessment, it evaluates relevant events and circumstances, including but not limited to, macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. If the applicable Registrant determines that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, or it elects not to perform a qualitative assessment, it compares the fair value of the reporting unit to its carrying value to determine if the fair value is greater than its carrying value.Goodwill forSouthern Company andSouthern Company Gas was$5.3 billion and$5.0 billion , respectively, atDecember 31, 2021 . For its 2021 annual impairment test,Southern Company Gas performed the quantitative assessment and confirmed that the II-52 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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fair value of all of its reporting units with goodwill exceeded their carrying value. For its 2020 and 2019 annual impairment tests,Southern Company Gas performed the qualitative assessment and determined that it was more likely than not that the fair value of all of its reporting units with goodwill exceeded their carrying amounts, and therefore no quantitative assessment was required. For its annual impairment tests for PowerSecure,Southern Company performed the quantitative assessment, which resulted in the fair value of goodwill at PowerSecure exceeding its carrying value in all years presented. However,Southern Company recorded goodwill impairment charges totaling$34 million in 2019 as a result of its decision to sell certain PowerSecure business units. See Note 15 to the financial statements under "Southern Company " for additional information. The COVID-19 pandemic and the related impacts on the worldwide economy have disrupted supply chains, reduced labor availability and productivity, and reduced economic activity inthe United States . These effects have had a variety of adverse impacts onSouthern Company and its subsidiaries, including PowerSecure. If these factors continue to negatively affect the operating results of PowerSecure and its businesses, a portion of the associated goodwill of$263 million may become impaired. The ultimate outcome of this matter cannot be determined at this time. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can significantly impact the applicable Registrant's results of operations. Fair values and useful lives are determined based on, among other factors, the expected future period of benefit of the asset, the various characteristics of the asset, and projected cash flows. As the determination of an asset's fair value and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates.
See Note 1 to the financial statements under "
Long-Lived Assets (
The applicable Registrants assess their other long-lived assets for impairment whenever events or changes in circumstances indicate that an asset's carrying amount may not be recoverable. If an indicator exists, the asset is tested for recoverability by comparing the asset carrying value to the sum of the undiscounted expected future cash flows directly attributable to the asset's use and eventual disposition. If the estimate of undiscounted future cash flows is less than the carrying value of the asset, the fair value of the asset is determined and a loss is recorded equal to the difference between the carrying value and the fair value of the asset. In addition, when assets are identified as held for sale, an impairment loss is recognized to the extent the carrying value of the assets or asset group exceeds their fair value less cost to sell. A high degree of judgment is required in developing estimates related to these evaluations, which are based on projections of various factors, some of which have been quite volatile in recent years. Impairments of long-lived assets of the traditional electric utilities and natural gas distribution utilities are generally related to specific regulatory disallowances.Southern Power's investments in long-lived assets are primarily generation assets. Excluding the natural gas distribution utilities,Southern Company Gas' investments in long-lived assets are primarily natural gas transportation and storage facility assets, whether in service or under construction. ForSouthern Power , examples of impairment indicators could include significant changes in construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to remarket generating capacity for an extended period, the unplanned termination of a customer contract, or the inability of a customer to perform under the terms of the contract. ForSouthern Company Gas , examples of impairment indicators could include, but are not limited to, significant changes in theU.S. natural gas storage market, construction schedules, current period losses combined with a history of losses or a projection of continuing losses, a significant decrease in market prices, the inability to renew or extend customer contracts or the inability of a customer to perform under the terms of the contract, attrition rates, or the inability to deploy a development project. As the determination of the expected future cash flows generated from an asset, an asset's fair value, and useful life involves management making certain estimates and because these estimates form the basis for the determination of whether or not an impairment charge should be recorded, the applicable Registrants consider these estimates to be critical accounting estimates. During 2021 and 2020,Southern Company recorded impairment charges totaling$7 million ($6 million after tax) and$206 million ($105 million after tax), respectively, related to its leveraged lease investments. During 2021,Southern Company Gas recorded total pre-tax charges of$84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. During 2019,Southern Company Gas recorded pre-tax impairment charges of$91 million ($69 million after-tax) related to a natural gas storage facility and approximately$24 million ($17 million after tax) related to the sale of Pivotal LNG. See Notes 7 and 9 to the financial statements under "Southern Company Gas " and "Southern Company Leveraged Lease," respectively, and Note 15 to the financial statements for additional information on recent asset impairments. II-53 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Revenue Recognition (
Southern Power's power sale transactions, which include PPAs, are classified in one of four general categories: leases, non-derivatives or normal sale derivatives, derivatives designated as cash flow hedges, and derivatives not designated as hedges.Southern Power's revenues are dependent upon significant judgments used to determine the appropriate transaction classification, which must be documented upon the inception of each contract. The two categories with the most judgment required forSouthern Power are described further below.
Lease Transactions
Southern Power considers the terms of a sales contract to determine whether it should be accounted for as a lease. A contract is or contains a lease if the contract conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. If the contract meets the criteria for a lease,Southern Power performs further analysis to determine whether the lease is classified as operating, financing, or sales-type. Generally,Southern Power's power sales contracts that are determined to be leases are accounted for as operating leases and the capacity revenue is recognized on a straight-line basis over the term of the contract and is included inSouthern Power's operating revenues. Energy revenues and other contingent revenues are recognized in the period the energy is delivered or the service is rendered. For those contracts that are determined to be sales-type leases, capacity revenues are recognized by accounting for interest income on the net investment in the lease and are included inSouthern Power's operating revenues. See Note 9 to the financial statements for additional information.
Non-Derivative and Normal Sale Derivative Transactions
If the power sales contract is not classified as a lease,Southern Power further considers whether the contract meets the definition of a derivative. If the contract does meet the definition of a derivative,Southern Power will assess whether it can be designated as a normal sale contract. The determination of whether a contract can be designated as a normal sale contract requires judgment, including whether the sale of electricity involves physical delivery in quantities withinSouthern Power's available generating capacity and that the purchaser will take quantities expected to be used or sold in the normal course of business. Contracts that do not meet the definition of a derivative or are designated as normal sales are accounted for as executory contracts. For contracts that have a capacity charge, the revenue is generally recognized in the period that it becomes billable. Revenues related to energy and ancillary services are recognized in the period the energy is delivered or the service is rendered. See Note 4 to the financial statements for additional information.
Acquisition Accounting (
Southern Power may acquire generation assets as part of its overall growth strategy. At the time of an acquisition,Southern Power will assess if these assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, the purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets, primarily related to acquired PPAs). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and Southern Power may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions, and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred by Southern Power for potential or successful acquisitions are expensed as incurred. See Note 13 to the financial statements for additional fair value information and Note 15 to the financial statements for additional information on recent acquisitions.
Variable Interest Entities (Southern Power)
Southern Power enters into partnerships with varying ownership structures. Upon
entering into these arrangements, membership interests and other variable
interests are evaluated to determine if the legal entity is a VIE. If the legal
entity is a VIE, Southern Power will assess if it has both the power to direct
the activities of the VIE that most significantly impact the VIE's economic
performance and the obligation to absorb losses or the right to receive benefits
from the VIE that could potentially be significant to the VIE, making it the
primary beneficiary. Making this determination may require significant
management judgment.
If Southern Power is the primary beneficiary and is considered to have a
controlling ownership, the assets, liabilities, and results of operations of the
entity are consolidated. If Southern Power is not the primary beneficiary, the
legal entity is generally accounted for under the equity method of accounting.
Southern Power reconsiders its conclusions as to whether the legal entity is
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a VIE and whether it is the primary beneficiary for events that impact the rights of variable interests, such as ownership changes in membership interests.
Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period.
Contingent Obligations (All Registrants)
The Registrants are subject to a number of federal and state laws and regulations, as well as other factors and conditions that subject them to environmental, litigation, and other risks. See FUTURE EARNINGS POTENTIAL herein and Notes 2 and 3 to the financial statements for more information regarding certain of these contingencies. The Registrants periodically evaluate their exposure to such risks and record reserves for those matters where a non-tax-related loss is considered probable and reasonably estimable. The adequacy of reserves can be significantly affected by external events or conditions that can be unpredictable; thus, the ultimate outcome of such matters could materially affect the results of operations, cash flows, or financial condition of the Registrants.
Recently Issued Accounting Standards
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU 2020-04) providing temporary guidance to ease the potential burden in accounting for reference rate reform primarily resulting from the discontinuation of LIBOR, which began phasing out on December 31, 2021. The amendments in ASU 2020-04 are elective and apply to all entities that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued. The new guidance (i) simplifies accounting analyses under current GAAP for contract modifications; (ii) simplifies the assessment of hedge effectiveness and allows hedging relationships affected by reference rate reform to continue; and (iii) allows a one-time election to sell or transfer debt securities classified as held to maturity that reference a rate affected by reference rate reform. An entity may elect to apply the amendments prospectively from March 12, 2020 through December 31, 2022 by accounting topic. The Registrants have elected to apply the amendments to modifications of debt arrangements that meet the scope of ASU 2020-04. The Registrants currently reference LIBOR for certain debt and hedging arrangements. In addition, certain provisions in PPAs at Southern Power include references to LIBOR. Contract language has been, or is expected to be, incorporated into each of these agreements to address the transition to an alternative rate for agreements that will be in place at the transition date. While no material impacts are expected from modifications to the arrangements and effective hedging relationships are expected to continue, the Registrants will continue to evaluate the provisions of ASU 2020-04 and the impacts of transitioning to an alternative rate, and the ultimate outcome of the transition cannot be determined at this time. See FINANCIAL CONDITION AND LIQUIDITY - "Overview" and "Financing Activities" herein and Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.
FINANCIAL CONDITION AND LIQUIDITY
Overview
The financial condition of each Registrant remained stable at December 31, 2021. The Registrants' cash requirements primarily consist of funding ongoing operations, including unconsolidated subsidiaries, as well as common stock dividends, capital expenditures, and debt maturities. Southern Power's cash requirements also include distributions to noncontrolling interests. Capital expenditures and other investing activities for the traditional electric operating companies include investments to build new generation facilities to meet projected long-term demand requirements and to replace units being retired as part of the generation fleet transition, to maintain existing generation facilities, to comply with environmental regulations including adding environmental modifications to certain existing generating units and closures of ash ponds, to expand and improve transmission and distribution facilities, and for restoration following major storms. Southern Power's capital expenditures and other investing activities may include acquisitions or new construction associated with its overall growth strategy and to maintain its existing generation fleet's performance.Southern Company Gas' capital expenditures and other investing activities include investments to meet projected long-term demand requirements, to maintain existing natural gas distribution systems as well as to update and expand these systems, and to comply with environmental regulations. See "Cash Requirements" herein for additional information. Operating cash flows provide a substantial portion of the Registrants' cash needs. During 2021, Southern Power utilized tax credits, which provided $288 million in operating cash flows. For the three-year period from 2022 through 2024, each Registrant's II-55 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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projected stock dividends, capital expenditures, and debt maturities, as well as distributions to noncontrolling interests for Southern Power, are expected to exceed its operating cash flows.Southern Company plans to finance future cash needs in excess of its operating cash flows through one or more of the following: accessing borrowings from financial institutions, issuing debt and hybrid securities in the capital markets, and/or through its stock plans. Each Subsidiary Registrant plans to finance its future cash needs in excess of its operating cash flows primarily through external securities issuances, borrowings from financial institutions, and equity contributions fromSouthern Company . In addition, Southern Power plans to utilize tax equity partnership contributions. The Registrants plan to use commercial paper to manage seasonal variations in operating cash flows and for other working capital needs and continue to monitor their access to short-term and long-term capital markets as well as their bank credit arrangements to meet future capital and liquidity needs. See "Sources of Capital" and "Financing Activities" herein for additional information. To facilitate an orderly transition from LIBOR to alternative benchmark rate(s), the Registrants have established an initiative to assess and mitigate risks associated with the discontinuation of LIBOR. As part of this initiative, several alternative benchmark rates have been, and continue to be, evaluated and implemented. Substantially all of the Registrants' credit facilities allow for LIBOR to be phased out and replaced with the Secured Overnight Financing Rate and interest rate derivatives address the LIBOR transition through the adoption of the ISDA 2020 IBOR Fallbacks Protocol and subsequent amendments. None of the Registrants expects the transition from LIBOR to have a material impact. The Registrants' investments in their qualified pension plans andAlabama Power's and Georgia Power's investments in their nuclear decommissioning trust funds increased in value at December 31, 2021 as compared to December 31, 2020. No contributions to the qualified pension plan were made during 2021 and no mandatory contributions to the qualified pension plans are anticipated during 2022. See Notes 6 and 11 to the financial statements under "Nuclear Decommissioning" and "Pension Plans," respectively, for additional information. At the end of 2021, the market price ofSouthern Company's common stock was $68.58 per share (based on the closing price as reported on the NYSE) and the book value was $26.30 per share, representing a market-to-book value ratio of 261%, compared to $61.43, $26.48, and 232%, respectively, at the end of 2020. Cash Requirements Capital Expenditures
Total estimated capital expenditures, including LTSA and nuclear fuel commitments, for the Registrants through 2026 based on their current construction programs are as follows:
2022 2023 2024 2025 2026
(in billions)
Southern Company(a)(b)(c) $ 8.7 $ 8.6 $ 7.5 $ 7.2 $ 7.1
Alabama Power(a) 1.9 1.8 1.7 1.7 1.7
Georgia Power(b) 4.4 4.5 3.5 3.5 3.4
Mississippi Power 0.3 0.3 0.2 0.2 0.2
Southern Power(c) 0.1 0.2 0.1 0.1 0.1
Southern Company Gas 1.7 1.7 1.8 1.7 1.7
(a)Includes expenditures of approximately $0.3 billion and $0.1 billion for the
construction of Plant Barry Unit 8 in 2022 and 2023, respectively. See Note 2 to
the financial statements under "Alabama Power" for additional information.
(b)Includes expenditures of approximately $1.3 billion and $0.9 billion for the construction of Plant Vogtle Units 3 and 4 in 2022 and 2023, respectively.
(c)Excludes approximately $0.3 billion in 2022, $0.5 billion in 2023, and $0.8
billion per year for 2024 through 2026 for Southern Power's planned acquisitions
and placeholder growth, which may vary materially due to market opportunities
and Southern Power's ability to execute its growth strategy.
These capital expenditures include estimates to comply with environmental laws
and regulations, but do not include any potential compliance costs associated
with any future regulation of CO2 emissions from fossil fuel-fired electric
generating units. See FUTURE EARNINGS POTENTIAL - "Environmental Matters" herein
for additional information. At December 31, 2021, significant purchase
commitments were outstanding in connection with the Registrants' construction
programs.
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The traditional electric operating companies also anticipate expenditures associated with closure and monitoring of ash ponds and landfills in accordance with the CCR Rule and the related state rules, which are reflected in the applicable Registrants' ARO liabilities. The cost estimates forAlabama Power and Mississippi Power are based on closure-in-place for all ash ponds. The cost estimates for Georgia Power are based on a combination of closure-in-place for some ash ponds and closure by removal for others. These anticipated costs are likely to change, and could change materially, as assumptions and details pertaining to closure are refined and compliance activities continue. Current estimates of these costs through 2026 are provided in the table below. Material expenditures in future years for ARO settlements will also be required for ash ponds, nuclear decommissioning (forAlabama Power and Georgia Power), and other liabilities reflected in the applicable Registrants' AROs, as discussed further in Note 6 to the financial statements. Also see FUTURE EARNINGS POTENTIAL - "Environmental Matters - Environmental Laws and Regulations - Coal Combustion Residuals" herein. 2022 2023 2024 2025 2026 (in millions) Southern Company $ 687 $ 688 $ 767 $ 907 $ 888 Alabama Power 320 330 346 364 299 Georgia Power 317 307 368 489 555 Mississippi Power 16 20 23 30 16 The construction programs are subject to periodic review and revision, and actual construction costs may vary from these estimates because of numerous factors. These factors include: changes in business conditions; changes in load projections; changes in environmental laws and regulations; the outcome of any legal challenges to environmental rules; changes in electric generating plants, including unit retirements and replacements and adding or changing fuel sources at existing electric generating units, to meet regulatory requirements; changes inFERC rules and regulations; state regulatory agency approvals; changes in the expected environmental compliance program; changes in legislation and/or regulation; the cost, availability, and efficiency of construction labor, equipment, and materials; project scope and design changes; abnormal weather; delays in construction due to judicial or regulatory action; storm impacts; and the cost of capital. The continued impacts of the COVID-19 pandemic could also impair the ability to develop, construct, and operate facilities, as discussed further in Item 1A herein. In addition, there can be no assurance that costs related to capital expenditures and AROs will be fully recovered. Additionally, expenditures associated with Southern Power's planned acquisitions may vary due to market opportunities and the execution of its growth strategy. See Note 15 to the financial statements under "Southern Power" for additional information regarding Southern Power's plant acquisitions and construction projects. The construction program of Georgia Power includes Plant Vogtle Units 3 and 4, which includes components based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale and which may be subject to additional revised cost estimates during construction. See Note 2 to the financial statements under "Georgia Power - Nuclear Construction" for information regarding Plant Vogtle Units 3 and 4 and additional factors that may impact construction expenditures.
See FUTURE EARNINGS POTENTIAL - "Construction Programs" herein for additional information.
Other Significant Cash Requirements
Long-term debt maturities and the interest payable on long-term debt each
represent a significant cash requirement for the Registrants. See Note 8 to the
financial statements for information regarding the Registrants' long-term debt
at December 31, 2021, the weighted average interest rate applicable to each
long-term debt category, and a schedule of long-term debt maturities over the
next five years. The Registrants plan to continue, when economically feasible,
to retire higher-cost securities and replace these obligations with lower-cost
capital if market conditions permit.
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Fuel and purchased power costs represent a significant component of funding ongoing operations for the traditional electric operating companies and Southern Power. See Note 3 to the financial statements under "Commitments" for information onSouthern Company Gas' commitments for pipeline charges, storage capacity, and gas supply. Total estimated costs for fuel and purchased power commitments at December 31, 2021 for the applicable Registrants are provided in the table below. Fuel costs include purchases of coal (for the traditional electric operating companies) and natural gas (for the traditional electric operating companies and Southern Power), as well as the related transportation and storage. In most cases, these contracts contain provisions for price escalation, minimum purchase levels, and other financial commitments. Natural gas purchase commitments are based on various indices at the time of delivery; the amounts reflected below have been estimated based on the NYMEX future prices at December 31, 2021. As discussed under "Capital Expenditures" herein, estimated expenditures for nuclear fuel are included in the applicable Registrants' construction programs for the years 2022 through 2026. Nuclear fuel commitments at December 31, 2021 that extend beyond 2026 are included in the table below. Purchased power costs represent estimated minimum obligations for various PPAs for the purchase of capacity and energy, except for those accounted for as leases, which are discussed in Note 9 to the financial statements. 2022 2023 2024 2025 2026 Thereafter (in millions) Southern Company(*) $ 3,740 $ 1,983 $ 1,302 $ 969 $ 753 $ 5,803 Alabama Power 1,170 581 446 358 203 1,182 Georgia Power(*) 1,405 795 440 348 329 4,118 Mississippi Power 539 235 168 109 98 491 Southern Power 626 372 248 154 123 12
(*)Excludes capacity payments related to Plant Vogtle Units 1 and 2, which are discussed in Note 3 to the financial statements under "Commitments."
Georgia Power's 2022 IRP filing included a request for six PPAs, which are expected to be accounted for as leases, that are contingent upon approval by the Georgia PSC. Five of the six PPAs are with Southern Power and are also contingent upon approval by theFERC . The expected capacity payments associated with the PPAs total $6 million in 2024, $79 million in 2025, $86 million in 2026, and $908 million thereafter, of which $5 million in 2024, $68 million in 2025, $75 million in 2026, and $748 million thereafter relate to the affiliate PPAs with Southern Power. See Note 2 to the financial statements under "Georgia Power - Integrated Resource Plan" for additional information. The traditional electric operating companies and Southern Power have entered into LTSAs for the purpose of securing maintenance support for certain of their generating facilities. See Note 1 to the financial statements under "Long-term Service Agreements" for additional information. As discussed under "Capital Expenditures" herein, estimated expenditures related to LTSAs are included in the applicable Registrants' construction programs for the years 2022 through 2026. Total estimated payments for LTSA commitments at December 31, 2021 that extend beyond 2026 are provided in the following table and include price escalation based on inflation indices: Southern Georgia Company Alabama Power Power Mississippi Power Southern Power (in millions) LTSA commitments (after 2026) $ 1,918 $ 203 $ 347 $ 137 $ 1,231
In addition, Southern Power has certain other operations and maintenance agreements. Total estimated costs for these commitments at December 31, 2021 are provided in the table below.
2022 2023 2024 2025 2026 Thereafter
(in millions)
Southern Power's operations and maintenance agreements $ 77 $ 65 $ 62 $
47 $ 36 $ 303
See Note 9 to the financial statements for information on the Registrants' operating lease obligations, including a maturity analysis of the lease liabilities over the next five years and thereafter.
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Sources of Capital
Southern Company intends to meet its future capital needs through operating cash flows, borrowings from financial institutions, and debt and equity issuances. Equity capital can be provided from any combination ofSouthern Company's stock plans, private placements, or public offerings.Southern Company does not expect to issue any equity in the capital markets through 2026 but may issue equity through its stock plans during this time. See Note 8 to the financial statements under "Equity Units" for information on stock purchase contracts associated withSouthern Company's equity units. The Subsidiary Registrants plan to obtain the funds to meet their future capital needs from sources similar to those they used in the past, which were primarily from operating cash flows, external securities issuances, borrowings from financial institutions, and equity contributions fromSouthern Company . In addition, Southern Power plans to utilize tax equity partnership contributions (as discussed further herein).
The amount, type, and timing of any financings in 2022, as well as in subsequent years, will be contingent on investment opportunities and the Registrants' capital requirements and will depend upon prevailing market conditions, regulatory approvals (for certain of the Subsidiary Registrants), and other factors. See "Cash Requirements" herein for additional information.
Southern Power utilizes tax equity partnerships as one of its financing sources, where the tax partner takes significantly all of the federal tax benefits. These tax equity partnerships are consolidated in Southern Power's financial statements and are accounted for using HLBV methodology to allocate partnership gains and losses. During 2021, Southern Power obtained tax equity funding for the Deuel Harvest wind facility, the Garland and Tranquillity battery energy storage facilities, and existing tax equity partnerships totaling $299 million. See Notes 1 and 15 to the financial statements under "General" and "Southern Power," respectively, for additional information. The issuance of securities by the traditional electric operating companies and Nicor Gas is generally subject to the approval of the applicable state PSC or other applicable state regulatory agency. The issuance of all securities by Mississippi Power and short-term securities by Georgia Power is generally subject to regulatory approval by theFERC . Additionally, with respect to the public offering of securities,Southern Company , the traditional electric operating companies, and Southern Power (excluding its subsidiaries), Southern Company Gas Capital, andSouthern Company Gas (excluding its other subsidiaries) file registration statements with theSEC under the Securities Act of 1933, as amended (1933 Act). The amounts of securities authorized by the appropriate regulatory authorities, as well as the securities registered under the 1933 Act, are closely monitored and appropriate filings are made to ensure flexibility in the capital markets. The Registrants generally obtain financing separately without credit support from any affiliate. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information.The Southern Company system does not maintain a centralized cash or money pool. Therefore, funds of each company are not commingled with funds of any other company inthe Southern Company system, except in the case ofSouthern Company Gas , as described below. The traditional electric operating companies and SEGCO may utilize aSouthern Company subsidiary organized to issue and sell commercial paper at their request and for their benefit. Proceeds from such issuances for the benefit of an individual company are loaned directly to that company. The obligations of each traditional electric operating company and SEGCO under these arrangements are several and there is no cross-affiliate credit support.Alabama Power also maintains its own separate commercial paper program. Southern Company Gas Capital obtains external financing forSouthern Company Gas and its subsidiaries, other than Nicor Gas, which obtains financing separately without credit support from any affiliates.Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and Nicor Gas. Nicor Gas' commercial paper program supports its working capital needs as Nicor Gas is not permitted to make money pool loans to affiliates. All of the otherSouthern Company Gas subsidiaries benefit from Southern Company Gas Capital's commercial paper program. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2021, the amount of subsidiary retained earnings restricted to dividend totaled $1.3 billion. This restriction did not impactSouthern Company Gas' ability to meet its cash obligations, nor does management expect such restriction to materially impactSouthern Company Gas' ability to meet its currently anticipated cash obligations. II-59 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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Certain Registrants' current liabilities frequently exceed their current assets
because of long-term debt maturities and the periodic use of short-term debt as
a funding source, as well as significant seasonal fluctuations in cash needs.
The Registrants generally plan to refinance long-term debt as it matures. See
Note 8 to the financial statements for additional information. Also see
"Financing Activities" herein for information on financing activities that
occurred subsequent to December 31, 2021. The following table shows the amount
by which current liabilities exceeded current assets at December 31, 2021 for
the applicable Registrants:
Southern Georgia Southern
At December 31, 2021 Company Power Mississippi Power Southern Power Company Gas
(in millions)
Current liabilities in excess of current
assets $ 1,956 $ 1,544 $ 57 $ 748 $ 471
The Registrants believe the need for working capital can be adequately met by
utilizing operating cash flows, as well as commercial paper, lines of credit,
and short-term bank notes, as market conditions permit. In addition, under
certain circumstances, the Subsidiary Registrants may utilize equity
contributions and/or loans from Southern Company .
At December 31, 2021, the Registrants' unused committed credit arrangements with
banks were as follows:
Southern Southern
Company Alabama Georgia Southern Company Southern
At December 31, 2021 parent Power Power Mississippi Power Power(a) Gas(b) SEGCO Company
(in millions)
Unused committed credit $ 1,998 $ 1,250 $ 1,726 $ 275 $ 568 $ 1,747 $ 30 $ 7,594
(a)At December 31, 2021, Southern Power also had two continuing letters of credit facilities for standby letters of credit, of which $12 million was unused. Southern Power's subsidiaries are not parties to its bank credit arrangements or letter of credit facilities.
(b)Includes $1.047 billion and $700 million at Southern Company Gas Capital and Nicor Gas, respectively.
Subject to applicable market conditions, the Registrants, Nicor Gas, and SEGCO expect to renew or replace their bank credit arrangements as needed, prior to expiration. In connection therewith, the Registrants, Nicor Gas, and SEGCO may extend the maturity dates and/or increase or decrease the lending commitments thereunder. A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at December 31, 2021 was approximately $1.5 billion (comprised of approximately $789 million atAlabama Power , $672 million at Georgia Power, and $34 million atMississippi Power). In addition, at December 31, 2021, Georgia Power had approximately $157 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months. See Note 8 to the financial statements under "Bank Credit Arrangements" for additional information. II-60 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
Short-term Borrowings
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily
through commercial paper programs that have the liquidity support of the
committed bank credit arrangements described above. Southern Power's
subsidiaries are not issuers or obligors under its commercial paper program.
Commercial paper and short-term bank term loans are included in notes payable in
the balance sheets. Details of the Registrants' short-term borrowings were as
follows:
Short-term Debt at the End of the Period
Amount Weighted Average
Outstanding Interest Rate
December 31, December 31,
2021 2020 2019 2021 2020 2019
(in millions)
Southern Company $ 1,440 $ 609 $ 2,055 0.4 % 0.3 % 2.1 %
Georgia Power - 60 365 - 0.3 2.2
Mississippi Power - 25 - - 0.4 -
Southern Power 211 175 549 0.3 0.3 2.2
Southern Company Gas :
Southern Company Gas Capital $ 379 $ 220 $ 372 0.3 % 0.3 % 2.1 %
Nicor Gas 830 104 278 0.4 % 0.2 1.8
Southern Company Gas Total $ 1,209 $ 324 $ 650
0.4 % 0.2 % 2.0 %
Short-term Debt During the Period(*)
Weighted Average
Average Amount Outstanding Interest Rate Maximum Amount Outstanding
2021 2020 2019 2021 2020 2019 2021 2020 2019
(in millions) (in millions)
Southern Company $ 1,141 $ 1,017 $ 1,240 0.3 % 1.6 % 2.6 % $ 1,809 $ 2,113 $ 2,914
Alabama Power 27 20 17 0.1 1.1 2.6 200 155 190
Georgia Power 95 264 371 0.2 1.7 2.7 407 478 935
Mississippi Power 15 9 - 0.2 1.6 - 81 40 -
Southern Power 133 64 76 0.2 1.5 2.7 520 550 578
Southern Company Gas :
Southern Company Gas
Capital $ 206 $ 316 $ 302 0.2 % 1.4 % 2.6 % $ 485 $ 641 $ 490
Nicor Gas 420 49 91 0.4 1.4 2.3 897 278 278
Southern Company Gas
Total $ 626 $ 365 $ 393 0.4 % 1.4 % 2.5 %
(*) Average and maximum amounts are based upon daily balances during the 12-month periods ended December 31, 2021, 2020, and 2019.
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Analysis of Cash Flows
Net cash flows provided from (used for) operating, investing, and financing activities in 2021 and 2020 are presented in the following table:
Net cash provided from (used Southern Georgia Southern for): Company Alabama Power Power
Mississippi Power Southern Power Company Gas
(in millions)
2021
Operating activities $ 6,169 $ 2,053 $ 2,747 $ 246 $ 951 $ 663
Investing activities (7,353) (1,961) (3,590) (257) (803) (1,379)
Financing activities 1,945 438 867 33 (195) 745
2020
Operating activities $ 6,696 $ 1,742 $ 2,784 $ 298 $ 901 $ 1,207
Investing activities (7,030) (2,122) (3,503) (323) 374 (1,417)
Financing activities (576) 16 676 (222) (1,372) 180
Fluctuations in cash flows from financing activities vary from year to year based on capital needs and the maturity or redemption of securities.
Net cash provided from operating activities decreased $0.5 billion in 2021 as compared to 2020 largely due to decreased fuel cost recovery at the traditional electric operating companies and under recovered natural gas costs at the natural gas distribution utilities, partially offset by customer bill credits issued in 2020 at Georgia Power and the timing of customer receivable collections.
The net cash used for investing activities in 2021 and 2020 was primarily related to the Subsidiary Registrants' construction programs.
The net cash provided from financing activities in 2021 was primarily related to net issuances of long-term and short-term debt, partially offset by common stock dividend payments. The net cash used for financing activities in 2020 was primarily related to common stock dividend payments and net repayments of short-term bank debt and commercial paper, partially offset by net issuances of long-term debt and issuances of common stock.
Net cash provided from operating activities increased $311 million in 2021 as compared to 2020 primarily due to an increase in retail revenues associated with a Rate RSE adjustment effective in January 2021 and higher customer usage, as well as the timing of fossil fuel stock purchases and receivable collections, partially offset by decreased fuel cost recovery.
The net cash used for investing activities in 2021 and 2020 was primarily related to gross property additions.
The net cash provided from financing activities in 2021 and 2020 was primarily related to capital contributions fromSouthern Company and net long-term debt issuances, partially offset by common stock dividend payments.
Georgia Power
Net cash provided from operating activities decreased $37 million in 2021 as
compared to 2020 primarily due to decreased fuel cost recovery, partially offset
by the timing of customer receivable collections and vendor payments and
customer bill credits issued in 2020 associated with Tax Reform and 2018 and
2019 earnings in excess of the allowed retail ROE range.
The net cash used for investing activities in 2021 and 2020 was primarily
related to gross property additions, including approximately $1.3 billion and
$1.4 billion, respectively, related to the construction of Plant Vogtle Units 3
and 4. See Note 2 to the financial statements under "Georgia Power - Nuclear
Construction" for additional information on construction of Plant Vogtle Units 3
and 4.
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The net cash provided from financing activities in 2021 and 2020 was primarily related to capital contributions fromSouthern Company , borrowings from the FFB for construction of Plant Vogtle Units 3 and 4, and net issuances and reofferings of other debt, partially offset by common stock dividend payments.
Mississippi Power
Net cash provided from operating activities decreased $52 million in 2021 as compared to 2020 primarily due to the timing of vendor payments and decreased fuel cost recovery, partially offset by the timing of receivable collections.
The net cash used for investing activities in 2021 and 2020 was primarily related to gross property additions.
The net cash provided from financing activities in 2021 was primarily related to the issuance of senior notes and capital contributions fromSouthern Company , partially offset by debt redemptions, common stock dividend payments, and a decrease in commercial paper borrowings. The net cash used for financing activities in 2020 was primarily related to debt repayments and redemptions and a return of capital and common stock dividends paid toSouthern Company , partially offset by debt issuances and capital contributions fromSouthern Company .
Southern Power
Net cash provided from operating activities increased $50 million in 2021 as compared to 2020 primarily due to the timing of vendor payments.
The net cash used for investing activities in 2021 was primarily related to the acquisition of the Deuel Harvest wind facility and ongoing construction activities. The net cash provided from investing activities in 2020 was primarily related to proceeds from the disposition of Plant Mankato, partially offset by ongoing construction activities and the acquisition of the Beech Ridge II wind facility. See Note 15 to the financial statements under "Southern Power" for additional information. The net cash used for financing activities in 2021 was primarily related to a return of capital toSouthern Company and common stock dividend payments, partially offset by net capital contributions from noncontrolling interests and net issuances of senior notes. The net cash used for financing activities in 2020 was primarily related to the repayment of senior notes at maturity, common stock dividend payments, and net repayments of short-term bank debt and commercial paper, partially offset by net contributions from noncontrolling interests.
Net cash provided from operating activities decreased $544 million in 2021 as compared to 2020 primarily due to natural gas cost under recovery, reflecting an increase in the cost of gas purchased during Winter Storm Uri, as well as the timing of vendor payments.
The net cash used for investing activities in 2021 and 2020 was primarily related to construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs at gas distribution operations, partially offset by proceeds from dispositions. See Note 15 to the financial statements for additional information.
The net cash provided from financing activities in 2021 was primarily related to net issuances of long-term and short-term debt and capital contributions fromSouthern Company , partially offset by common stock dividend payments. The net cash provided from financing activities in 2020 was primarily related to proceeds from issuances of senior notes and first mortgage bonds, as well as capital contributions fromSouthern Company , partially offset by common stock dividend payments and net repayments of short-term borrowings.
Significant Balance Sheet Changes
Significant balance sheet changes in 2021 for
•an increase of $3.7 billion in long-term debt (including securities due within one year) related to new issuances;
•an increase of $3.5 billion in total property, plant, and equipment primarily
related to the Subsidiary Registrants' construction programs (net of pre-tax
charges totaling $1.7 billion recorded during 2021 at Georgia Power for
estimated probable losses associated with the construction of Plant Vogtle Units
3 and 4);
•decreases of $1.8 billion and $0.7 billion in other regulatory assets and
employee benefit obligations, respectively, and an increase of $1.7 billion in
prepaid pension costs primarily due to actuarial gains related to increases in
the assumed discount rates and actual asset returns associated with retirement
benefit plans;
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•increases of $1.0 billion and $0.5 billion in AROs and regulatory assets associated with AROs, respectively, primarily related to cost estimate updates at the traditional electric operating companies for ash pond facilities;
•an increase of $0.8 billion in notes payable due to an increase in commercial paper borrowings and short-term bank debt;
•an increase of $0.7 billion in accumulated deferred income taxes primarily related to the utilization of tax credits in 2021, an increase in under recovered fuel and natural gas costs, and an increase in property-related timing differences; and
•an increase of $0.7 billion in cash and cash equivalents, as discussed further
under "Analysis of Cash Flows -
See "Financing Activities" herein and Notes 2, 5, 6, 8, 10, and 11 to the financial statements for additional information.
Significant balance sheet changes in 2021 for
•an increase of $1.3 billion in total property, plant, and equipment primarily related to construction of distribution and transmission facilities, increases to AROs, construction of Plant Barry Unit 8, and the installation of equipment to comply with environmental standards;
•an increase of $0.9 billion in total common stockholder's equity primarily due
to capital contributions from
•an increase of $0.8 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes;
•an increase of $0.5 billion in cash and cash equivalents, as discussed further
under "Analysis of Cash Flows -
•an increase of $0.5 billion in prepaid pension and other postretirement benefit costs primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans.
See "Financing Activities -
Georgia Power
Significant balance sheet changes in 2021 for Georgia Power included:
•an increase of $0.9 billion in total property, plant, and equipment primarily related to the construction of generation, transmission, and distribution facilities (net of pre-tax charges totaling $1.7 billion for estimated probable losses on Plant Vogtle Units 3 and 4);
•an increase of $0.8 billion in long-term debt (including securities due within one year) primarily due to a net increase in outstanding senior notes and borrowings from the FFB for construction of Plant Vogtle Units 3 and 4;
•an increase of $0.7 billion in common stockholder's equity related to capital
contributions from
•a decrease of $0.7 billion in other regulatory assets, deferred and an increase of $0.6 billion in prepaid pension costs primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans;
•increases of $0.6 billion and $0.4 billion in AROs and regulatory assets associated with AROs, respectively, primarily due to cost estimate updates for ash pond closures; and
•an increase of $0.4 billion in deferred under recovered fuel clause revenues resulting from higher fuel and purchased power costs.
See "Financing Activities - Georgia Power" herein and Notes 2, 5, 6, 8, and 11 to the financial statements for additional information.
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Mississippi Power
Significant balance sheet changes in 2021 for Mississippi Power included:
•an increase of $125 million in common stockholder's equity related to net
income and capital contributions from
•an increase of $92 million in long-term debt (including securities due within one year) primarily due to the issuance of senior notes, partially offset by the redemption of revenue bonds and bank term loans; and •an increase of $79 million in prepaid pension costs and a decrease of $71 million in other regulatory assets, deferred primarily due to actuarial gains related to increases in the assumed discount rates and actual asset returns associated with retirement benefit plans.
See "Financing Activities - Mississippi Power" herein and Notes 8 and 11 to the financial statements for additional information.
Southern Power
Significant balance sheet changes in 2021 for Southern Power included:
•an increase of $681 million in property, plant, and equipment in service primarily due to the acquisition of the Deuel Harvest wind facility and the Glass Sands wind facility being placed in service;
•a decrease of $262 million in accumulated deferred income tax assets and an increase of $92 million in accumulated deferred income tax liabilities primarily related to the utilization of ITCs in 2021;
•a decrease of $173 million in common stockholder's equity primarily due to a
return of capital to
•an increase of $161 million in net investment in sales-type leases recorded upon commencement of the Garland and Tranquillity battery energy storage facilities' PPAs.
See Notes 5, 9, 10, and 15 to the financial statements for additional information.
Significant balance sheet changes in 2021 for
•an increase of $1.06 billion in total property, plant, and equipment primarily related to the construction of transportation and distribution assets recovered through base rates and infrastructure investment recovered through replacement programs;
•an increase of $885 million in notes payable due to issuances of short-term debt and an increase in commercial paper borrowings;
•decreases of $516 million in energy marketing receivables and $494 million in energy marketing trade payables due to the sale of Sequent;
•an increase of $473 million in natural gas cost under recovery, including $207 million in other regulatory assets, deferred, reflecting an increase in the cost of gas purchased during Winter Storm Uri;
•an increase of $290 million in accumulated deferred income taxes primarily due to an increase in natural gas cost under recovery and changes in state apportionment rates as a result of the sale of Sequent; and
•an increase of $276 million in long-term debt (including securities due within one year) primarily due to net issuances of senior notes and first mortgage bonds.
See "Financing Activities -
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Financing Activities
The following table outlines the Registrants' long-term debt financing activities for the year ended December 31, 2021:
Issuances/Reofferings Maturities, Redemptions, and Repurchases
Revenue Other Senior Other Long-Term
Company Senior Notes Bonds Long-Term Debt Notes Revenue Bonds Debt(a)
(in millions)
Southern Company parent $ 1,600 $ - $ 2,476 $ 1,500 $ - $ 800
Alabama Power 1,300 - - 200 65 207
Georgia Power 750 122 440 325 69 105
Mississippi Power 525 - - - 320 100
Southern Power 400 - - 300 - -
Southern Company Gas 450 - 200 300 - 30
Other - - - - - 14
Elimination(b) - - - - - (7)
Southern Company $ 5,025 $ 122 $ 3,116 $ 2,625 $ 454 $ 1,249
(a)Includes reductions in finance lease obligations resulting from cash payments
under finance leases and, for Georgia Power, principal amortization payments for
FFB borrowings.
(b)Represents reductions in affiliate finance lease obligations at Georgia
Power, which are eliminated in
Except as otherwise described herein, the Registrants used the proceeds of debt issuances for their redemptions and maturities shown in the table above, to repay short-term indebtedness, and for general corporate purposes, including working capital. The Subsidiary Registrants also used the proceeds for their construction programs. In addition to any financings that may be necessary to meet capital requirements and contractual obligations, the Registrants plan to continue, when economically feasible, a program to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit.
During 2021,Southern Company issued approximately 3.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $73 million.
In January 2021,
In February 2021,
In May 2021,
Also in May 2021,
In September 2021,Southern Company issued €1.25 billion (approximately $1.476 billion) aggregate principal amount of Series 2021B 1.875% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due September 15, 2081.Southern Company's obligations under these notes were effectively converted to fixed-rateU.S. dollars at issuance for the first six years through cross-currency swaps, mitigating foreign currency exchange risk associated with the interest and principal payments during this period. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information.
In October 2021,
In November 2021,
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In March 2021,
In June 2021,
Also in June 2021,
In July 2021,Alabama Power redeemed all of its approximately $206 million aggregate principal amount of Series E Junior Subordinated Notes due October 1, 2042. The Series E Junior Subordinated Notes were held by an affiliated trust, Alabama Power Capital Trust V, which applied the redemption proceeds to the simultaneous redemption of (i) its Flexible Trust Preferred Securities totaling approximately $200 million, which were guaranteed byAlabama Power , and (ii) shares of its common securities totaling approximately $6 million that were held byAlabama Power . In November 2021,Alabama Power repaid at maturity $65 million aggregate principal amount of The Industrial Development Board of theTown of Columbia (Alabama ) Tax Exempt Variable Rate Demand Revenue Bonds (Alabama Power Company Project), Series 1997.
Also in November 2021,
Subsequent to December 31, 2021,Alabama Power received a capital contribution totaling $625 million fromSouthern Company and announced the redemption in February 2022 of all $550 million aggregate principal amount of its Series 2017A 2.45% Senior Notes due March 30, 2022.
Georgia Power
In February 2021, Georgia Power issued $750 million aggregate principal amount of Series 2021A 3.25% Senior Notes due March 15, 2051. An amount equal to the net proceeds of the senior notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers.
In March 2021, Georgia Power redeemed all $325 million aggregate principal amount of its Series 2016B 2.40% Senior Notes due April 1, 2021.
Also in March 2021, Georgia Power extended the maturity date of its $125 million term loan from June 2021 to June 2022.
In June 2021, Georgia Power purchased and held approximately $69 million aggregate principal amount of Development Authority ofBurke County (Georgia ) Pollution Control Revenue Bonds (Georgia Power Company Plant Vogtle Project), First Series 2008. In August 2021, Georgia Power reoffered these bonds to the public. In June 2021 and December 2021, Georgia Power made the final borrowings under the FFB Credit Facilities in aggregate principal amounts of $371 million and $69 million, respectively, at an interest rate of 2.434% and 2.178%, respectively, through the final maturity date of February 20, 2044. No further borrowings are permitted under the FFB Credit Facilities. The proceeds were used to reimburse Georgia Power for Eligible Project Costs relating to the construction of Plant Vogtle Units 3 and 4. During 2021, Georgia Power made principal amortization payments of $96 million under the FFB Credit Facilities. See Note 8 to the financial statements under "Long-term Debt - DOE Loan Guarantee Borrowings" for additional information.
In August 2021, Georgia Power reoffered to the public $53 million aggregate
principal amount of Development Authority of
Subsequent to December 31, 2021, Georgia Power redeemed all $400 million aggregate principal amount of its Series 2012B 2.85% Senior Notes due May 15, 2022.
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Mississippi Power
In June 2021, Mississippi Power issued $200 million aggregate principal amount of Series 2021A Floating Rate Senior Notes due June 28, 2024 and $325 million aggregate principal amount of Series 2021B 3.10% Senior Notes due July 30, 2051. An amount equal to the net proceeds of the Series 2021B Senior Notes is being allocated to finance or refinance, in whole or in part, one or more renewable energy projects and/or expenditures and programs related to enabling opportunities for diverse and small businesses/suppliers. In July 2021, Mississippi Power redeemed all $270 million aggregate principal amount of Mississippi Business Finance Corporation Taxable Revenue Bonds, 7.13% Series 1999A due October 20, 2021 at par plus accrued interest and a make-whole premium.
Also in July 2021, Mississippi Power repaid its $60 million and $15 million floating rate bank term loans, with maturity dates in December 2021 and January 2022, respectively.
In October 2021, Mississippi Power repaid $25 million previously borrowed under its $125 million revolving credit arrangement that matures in March 2023.
In December 2021, Mississippi Power redeemed all $50 million aggregate principal amount of Mississippi Business Finance Corporation Revenue Bonds, First Series 2010 due December 1, 2040.
Subsequent to December 31, 2021, Mississippi Power received a capital
contribution totaling $50 million from
Southern Power
In January 2021, Southern Power issued $400 million aggregate principal amount of Series 2021A 0.90% Senior Notes due January 15, 2026. An amount equal to the net proceeds of the senior notes was allocated to finance or refinance, in whole or in part, one or more renewable energy projects.
In November 2021, Southern Power redeemed all $300 million aggregate principal amount of its Series 2016E 2.500% Senior Notes due December 15, 2021.
In February 2021,
In March 2021, Nicor Gas entered into three short-term floating rate bank loans in an aggregate principal amount of $300 million, each bearing interest based on one-month LIBOR.
In June 2021, Southern Company Gas Capital redeemed all $300 million aggregate principal amount of its 3.50% Senior Notes due September 15, 2021.
In August 2021, Nicor Gas issued in a private placement $50 million aggregate principal amount of 1.42% Series First Mortgage Bonds due August 31, 2026 and $50 million aggregate principal amount of 2.19% Series First Mortgage Bonds due August 31, 2033. In October 2021, Nicor Gas issued in a private placement $100 million aggregate principal amount of 1.77% Series First Mortgage Bonds due October 28, 2028. Nicor Gas also entered into an agreement to issue in a private placement additional first mortgage bonds with aggregate principal amounts of $100 million and $75 million expected to be issued in August 2022 and October 2022, respectively.
In September 2021, Southern Company Gas Capital, as borrower, and
Credit Rating Risk
At December 31, 2021, the Registrants did not have any credit arrangements that
would require material changes in payment schedules or terminations as a result
of a credit rating downgrade.
There are certain contracts that could require collateral, but not accelerated
payment, in the event of a credit rating change of certain Registrants to BBB
and/or Baa2 or below. These contracts are primarily for physical electricity and
natural gas purchases and sales, fuel purchases, fuel transportation and
storage, energy price risk management, transmission, interest rate management,
and, for Georgia Power, construction of new generation at Plant Vogtle Units 3
and 4.
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The maximum potential collateral requirements under these contracts at December 31, 2021 were as follows:
Southern Southern Southern Company
Credit Ratings Company(*) Alabama Power Georgia Power Mississippi Power Power(*) Gas
(in millions)
At BBB and/or Baa2 $ 41 $ 1 $ - $ - $ 40 $ -
At BBB- and/or Baa3 419 2 61 1 357 -
At BB+ and/or Ba1 or
below 1,934 407 939 307 1,186 9
(*)Southern Power has PPAs that could require collateral, but not accelerated
payment, in the event of a downgrade of Southern Power's credit. The PPAs
require credit assurances without stating a specific credit rating. The amount
of collateral required would depend upon actual losses resulting from a credit
downgrade. Southern Power had $105 million of cash collateral posted related to
PPA requirements at December 31, 2021.
The amounts in the previous table for the traditional electric operating
companies and Southern Power include certain agreements that could require
collateral if either Alabama Power or Georgia Power has a credit rating change
to below investment grade. Generally, collateral may be provided by a Southern
Company guaranty, letter of credit, or cash. Additionally, a credit rating
downgrade could impact the ability of the Registrants to access capital markets
and would be likely to impact the cost at which they do so.
Mississippi Power and its largest retail customer, Chevron , have agreements
under which Mississippi Power provides retail service to the Chevron refinery in
Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a
security interest in the co-generation assets owned by Mississippi Power located
at the refinery that is exercisable upon the occurrence of (i) certain
bankruptcy events or (ii) other events of default coupled with specific
reductions in steam output at the facility and a downgrade of Mississippi
Power's credit rating to below investment grade by two of the three rating
agencies.
On October 27, 2021, S&P downgraded the Southern Company issuer credit rating to
BBB+ from A-. Due to S&P's consolidated rating methodology, the downgrade of
Southern Company's issuer credit rating resulted in the downgrade of the senior
unsecured long-term debt rating of Alabama Power and the long-term issuer rating
of Nicor Gas to A- from A, the senior unsecured long-term debt ratings of
Atlanta Gas Light , Georgia Power, Mississippi Power, and Southern Company Gas
Capital to BBB+ from A-, and the senior unsecured long-term debt ratings of
Southern Company and Southern Power to BBB from BBB+. S&P revised its credit
rating outlook for Southern Company and its subsidiaries to stable from
negative.
Market Price Risk
As a result of the sale of Sequent on July 1, 2021,Southern Company Gas' market risk exposure decreased significantly. The other Registrants had no material change in market risk exposure for the year ended December 31, 2021 when compared to the year ended December 31, 2020. See Note 14 to the financial statements for an in-depth discussion of the Registrants' derivatives, as well as Note 1 to the financial statements under "Financial Instruments" for additional information. See Note 15 to the financial statements under "Southern Company Gas" for information regarding the sale of Sequent. Due to cost-based rate regulation and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities that sell natural gas directly to end-use customers continue to have limited exposure to market volatility in interest rates, foreign currency exchange rates, commodity fuel prices, and prices of electricity. The traditional electric operating companies and certain of the natural gas distribution utilities manage fuel-hedging programs implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies to hedge the impact of market fluctuations in natural gas prices for customers. Mississippi Power also manages wholesale fuel-hedging programs under agreements with its wholesale customers. Because energy from Southern Power's facilities is primarily sold under long-term PPAs with tolling agreements and provisions shifting substantially all of the responsibility for fuel cost to the counterparties, Southern Power's exposure to market volatility in commodity fuel prices and prices of electricity is generally limited. However, Southern Power has been and may continue to be exposed to market volatility in energy-related commodity prices as a result of uncontracted generating capacity. To mitigate residual risks relative to movements in electricity prices, the traditional electric operating companies and Southern Power may enter into physical fixed-price contracts for the purchase and sale of electricity through the wholesale electricity market and, to a lesser extent, financial hedge contracts for natural gas purchases; however, a significant portion of contracts are priced at market. Certain ofSouthern Company Gas' non-regulated operations (primarily Sequent until its sale on July 1, 2021) routinely utilize various types of derivative instruments to economically hedge certain commodity price and weather risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts, and swap agreements.Southern Company Gas' gas marketing services business also actively II-69 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
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manages storage positions through a variety of hedging transactions for the purpose of managing exposures arising from changing natural gas prices. These hedging instruments are used to substantially protect economic margins (as spreads between wholesale and retail natural gas prices widen between periods) and thereby minimize exposure to declining earnings. Some of these economic hedge activities may not qualify, or may not be designated, for hedge accounting treatment.
The following table provides information related to variable interest rate exposure on long-term debt (including amounts due within one year) at December 31, 2021 for the applicable Registrants:
Southern Alabama Georgia Mississippi Southern Company
At December 31, 2021 Company(*) Power Power Power Gas
(in millions, except percentages)
Long-term variable interest rate
exposure $ 4,464 $ 834 $ 797 $ 234 $ 500
Weighted average interest rate on
long-term variable interest rate
exposure 0.84 % 0.21 % 0.21 % 0.32 % 0.49 %
Impact on annualized interest expense
of 100 basis point change in interest
rates $ 45 $ 8 $ 8 $ 2 $ 5
(*)Includes $2.0 billion of long-term variable interest rate exposure at
The Registrants may enter into interest rate derivatives designated as hedges, which are intended to mitigate interest rate volatility related to forecasted debt financings and existing fixed and floating rate obligations. See Note 14 to the financial statements under "Interest Rate Derivatives" for additional information.Southern Company and Southern Power had foreign currency denominated debt at December 31, 2021 and have each mitigated exposure to foreign currency exchange rate risk through the use of foreign currency swaps. See Note 14 to the financial statements under "Foreign Currency Derivatives" for additional information. Changes in fair value of energy-related derivative contracts forSouthern Company andSouthern Company Gas for the years ended December 31, 2021 and 2020 are provided in the table below. At December 31, 2021 and 2020, substantially all of the traditional electric operating companies' and certain of the natural gas distribution utilities' energy-related derivative contracts were designated as regulatory hedges and were related to the applicable company's fuel-hedging program. Southern Company Southern Company(a) Gas(a) (in millions) Contracts outstanding at December 31, 2019, assets (liabilities), net $ (21) $ 72 Contracts realized or settled (14) (98) Current period changes(b) 142 127 Contracts outstanding at December 31, 2020, assets (liabilities), net $ 107 $ 101 Contracts realized or settled (252) (85) Current period changes(b) 243 (84) Sale of Sequent 76 76
Contracts outstanding at December 31, 2021, assets (liabilities), net
$ 174 $ 8
(a)Excludes cash collateral held on deposit in broker margin accounts of $3 million, $28 million, and $99 million at December 31, 2021, 2020, and 2019, respectively, and immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
(b)The changes in fair value of energy-related derivative contracts are substantially attributable to both the volume and the price of natural gas. Current period changes also include the changes in fair value of new contracts entered into during the period, if any.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The net hedge volumes of energy-related derivative contracts for natural gas purchased (sold) at December 31, 2021 and 2020 forSouthern Company andSouthern Company Gas were as follows: Southern Company Southern Company Gas mmBtu Volume (in millions) At December 31, 2021: Commodity - Natural gas swaps 57 - Commodity - Natural gas options 253 68 Total hedge volume 310 68 At December 31, 2020: Commodity - Natural gas swaps 262 - Commodity - Natural gas options 574 523 Total hedge volume 836 523Southern Company Gas' derivative contracts are comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. The volumes presented above forSouthern Company Gas represent the net of long natural gas positions of 74 million mmBtu and short natural gas positions of 6 million mmBtu at December 31, 2021 and the net of long natural gas positions of 4.42 billion mmBtu and short natural gas positions of 3.90 billion mmBtu at December 31, 2020. Forthe Southern Company system, the weighted average swap contract cost per mmBtu was approximately $0.74 per mmBtu below market prices at December 31, 2021 and was equal to market prices at December 31, 2020. The change in option fair value is primarily attributable to the volatility of the market and the underlying change in the natural gas price. Substantially all of the traditional electric operating companies' natural gas hedge gains and losses are recovered through their respective fuel cost recovery clauses. The Registrants use over-the-counter contracts that are not exchange traded but are fair valued using prices which are market observable, and thus fall into Level 2 of the fair value hierarchy. In addition,Southern Company Gas uses exchange-traded market-observable contracts, which are categorized as Level 1. See Note 13 to the financial statements for further discussion of fair value measurements. The maturities of the energy-related derivative contracts forSouthern Company andSouthern Company Gas at December 31, 2021 were as follows: Fair Value
Measurements of Contracts at
December 31, 2021
Total Maturity
Fair Value 2022 2023 - 2024 2025 - 2026
(in millions)
Southern Company
Level 1(a) $ 15 $ 14 $ 1 $ -
Level 2(b) 159 93 65 1
Southern Company total(c) $ 174 $ 107 $ 66 $ 1
Southern Company Gas
Level 1(a) $ 15 $ 14 $ 1 $ -
Level 2(b) (7) (7) - -
Southern Company Gas total(c) $ 8 $ 7 $ 1 $ -
(a)Valued using NYMEX futures prices.
(b)Level 2 amounts forSouthern Company Gas are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(c)Excludes cash collateral of $3 million as well as immaterial premium and associated intrinsic value associated with weather derivatives.
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COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS (continued)
The Registrants are exposed to risk in the event of nonperformance by counterparties to energy-related and interest rate derivative contracts, as applicable. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P, or with counterparties who have posted collateral to cover potential credit exposure. Therefore, the Registrants do not anticipate market risk exposure from nonperformance by the counterparties. For additional information, see Note 1 to the financial statements under "Financial Instruments" and Note 14 to the financial statements.
Credit Risk
Southern Company (except as discussed herein), the traditional electric operating companies, and Southern Power are not exposed to any concentrations of credit risk.Southern Company Gas' exposure to concentrations of credit risk is discussed herein.Southern Company Gas
Gas Distribution Operations
Concentration of credit risk occurs atAtlanta Gas Light for amounts billed for services and other costs to its customers, which consist of the 16 Marketers inGeorgia . The credit risk exposure to the Marketers varies seasonally, with the lowest exposure in the non-peak summer months and the highest exposure in the peak winter months. Marketers are responsible for the retail sale of natural gas to end-use customers inGeorgia . The provisions ofAtlanta Gas Light's tariff allowAtlanta Gas Light to obtain credit security support in an amount equal to a minimum of two times a Marketer's highest month's estimated bill fromAtlanta Gas Light . For 2021, the four largest Marketers based on customer count, which includes SouthStar, accounted for 15% ofSouthern Company Gas' operating revenues and 17% of operating revenues forSouthern Company Gas' gas distribution operations segment. Several factors are designed to mitigateSouthern Company Gas' risks from the increased concentration of credit that has resulted from deregulation. In addition to the security support described above,Atlanta Gas Light bills intrastate delivery service to Marketers in advance rather than in arrears.Atlanta Gas Light accepts credit support in the form of cash deposits, letters of credit/surety bonds from acceptable issuers, and corporate guarantees from investment-grade entities.Southern Company Gas reviews the adequacy of credit support coverage, credit rating profiles of credit support providers, and payment status of each Marketer.Southern Company Gas believes that adequate policies and procedures are in place to properly quantify, manage, and report onAtlanta Gas Light's credit risk exposure to Marketers.Atlanta Gas Light also faces potential credit risk in connection with assignments of interstate pipeline transportation and storage capacity to Marketers. AlthoughAtlanta Gas Light assigns this capacity to Marketers, in the event that a Marketer fails to pay the interstate pipelines for the capacity, the interstate pipelines would likely seek repayment fromAtlanta Gas Light .
Wholesale Gas Services
Following the sale of Sequent on July 1, 2021,Southern Company Gas no longer has exposure to counterparty credit risk for wholesale gas services. See Note 15 to the financial statements under "Southern Company Gas" for information on the sale of Sequent. Gas Marketing ServicesSouthern Company Gas obtains credit scores for its firm residential and small commercial customers using a national credit reporting agency, enrolling only those customers that meet or exceedSouthern Company Gas' credit threshold.Southern Company Gas considers potential interruptible and large commercial customers based on reviews of publicly available financial statements and commercially available credit reports. Prior to entering into a physical transaction,Southern Company Gas also assigns physical wholesale counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. II-72 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements
Item 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
The Southern Company and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm II- 74Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 78
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 79
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019
II- 80
Consolidated Balance Sheets at December 31 , 2021 and 2020 II- 81
Consolidated Statements of Stockholders' Equity for the Years Ended December 31 ,
2021, 2020, and 2019 II- 83
Alabama Power:
Report of Independent Registered Public Accounting Firm II- 84Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 86
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 87
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019
II- 88
Balance Sheets at December 31 , 2021 and 2020 II- 89
Statements of Common Stockholder's Equity for the Years Ended December 31
, 2021,
2020, and 2019 II- 91
Georgia Power:
Report of Independent Registered Public Accounting Firm II- 92Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 95
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 96
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019
II- 97
Balance Sheets at December 31 , 2021 and 2020 II- 98
Statements of Common Stockholder's Equity for the Years Ended December 31
, 2021,
2020, and 2019 II- 100
Mississippi Power:
Report of Independent Registered Public Accounting Firm II- 101Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 103
Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 104
Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019 II- 105
Balance Sheets at December 31 , 2021 and 2020 II- 106
Statements of Common Stockholder's Equity for the Years Ended December 31
, 2021,
2020, and 2019 II- 108
Southern Power and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm II- 109Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 111
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 112
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019
II- 113
Consolidated Balance Sheets at December 31 , 2021 and 2020 II- 114
Consolidated Statements of Stockholders' Equity for the Years Ended December 31 , 2021, 2020, and 2019
II- 116
Southern Company Gas and Subsidiary Companies:
Report of Independent Registered Public Accounting Firm II- 117Consolidated Statements of Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 121
Consolidated Statements of Comprehensive Income for the Years Ended December 31 , 2021, 2020, and 2019
II- 122
Consolidated Statements of Cash Flows for the Years Ended December 31 , 2021, 2020, and 2019
II- 123
Consolidated Balance Sheets at December 31 , 2021 and 2020 II- 124
Consolidated Statements of Common Stockholder's Equity for the Years Ended December 31 , 2021, 2020, and 2019
II- 126
Combined Notes to Financial Statements II- 127
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets ofThe Southern Company and Subsidiary Companies (Southern Company ) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). We also have auditedSouthern Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position ofSouthern Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted inthe United States of America . Also, in our opinion,Southern Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Basis for OpinionsSouthern Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion onSouthern Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with thePublic Company Accounting Oversight Board (United States ) (PCAOB) and are required to be independent with respect toSouthern Company in accordance with theU.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
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Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the Audit Committee ofSouthern Company's Board of Directors and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Impact of Rate Regulation on the Financial Statements - Refer to Note 1 (Summary of Significant Accounting Policies - Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters) to the financial statements
Critical Audit Matter Description
Southern Company's traditional electric operating companies and natural gas distribution utilities (the "regulated utility subsidiaries"), which represent approximately 88% ofSouthern Company's consolidated operating revenues for the year ended December 31, 2021 and 86% of its consolidated total assets at December 31, 2021, are subject to rate regulation by their respective state Public Service Commissions or other applicable state regulatory agencies and wholesale regulation by theFederal Energy Regulatory Commission (collectively, the "Commissions"). Management has determined that the regulated utility subsidiaries meet the requirements under accounting principles generally accepted inthe United States of America to utilize specialized rules to account for the effects of rate regulation in the preparation of its financial statements. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, including, but not limited to, property, plant, and equipment; other regulatory assets; other regulatory liabilities; other cost of removal obligations; deferred charges and credits related to income taxes; under and over recovered regulatory clause revenues; operating revenues; operations and maintenance expenses; and depreciation and amortization. The Commissions set the rates the regulated utility subsidiaries are permitted to charge customers. Rates are determined and approved in regulatory proceedings based on an analysis of the applicable regulated utility subsidiary's costs to provide utility service and a return on, and recovery of, its investment in the utility business. Current and future regulatory decisions can have an impact on the recovery of costs, the rate of return earned on investments, and the timing and amount of assets to be recovered by rates. The Commissions' regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. WhileSouthern Company's regulated utility subsidiaries expect to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures (e.g., asset retirement costs, property damage reserves, and remaining net book values of retired assets) and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, (2) a disallowance of part of the cost of recently completed plant or plant under construction, and/or (3) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities and significant auditor judgment to evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management's controls over the evaluation of the
likelihood of (1) the recovery in future rates of costs incurred as property,
plant, and equipment and deferred as regulatory assets, and (2) a refund or a
future reduction in rates that should be reported as regulatory liabilities. We
also tested the effectiveness of management's controls over the initial
recognition of amounts as property, plant, and equipment; regulatory assets or
liabilities; and the monitoring and evaluation of regulatory developments that
may affect the likelihood of recovering costs in future rates or of a future
reduction in rates.
•We read relevant regulatory orders issued by the Commissions for the regulated
utility subsidiaries, regulatory statutes, interpretations, procedural
memorandums, filings made by intervenors, and other publicly available
information to assess the likelihood of recovery in future rates or of a future
reduction in rates based on precedents of the Commissions' treatment of similar
costs under similar circumstances. We evaluated the external information and
compared it to management's recorded regulatory asset and liability balances for
completeness.
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•For regulatory matters in process, we inspected filings with the Commissions by
Southern Company's regulated utility subsidiaries and other interested parties
that may impact the regulated utility subsidiaries' future rates for any
evidence that might contradict management's assertions.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.
•We evaluated
Disclosure of Uncertainties - Plant Vogtle Units 3 and 4 Construction - Refer to Note 2 (Regulatory Matters - Georgia Power - Nuclear Construction) to the financial statements
Critical Audit Matter Description
As discussed in Note 2 to the financial statements, the ultimate recovery ofGeorgia Power Company's (Georgia Power) investment in the construction of Plant Vogtle Units 3 and 4 is subject to multiple uncertainties. Such uncertainties include the potential impact of future decisions by Georgia Power's regulators (particularly theGeorgia Public Service Commission ) and potential actions by the co-owners of the Vogtle project. In addition, Georgia Power's ability to meet its cost and schedule forecasts could impact its ability to fully recover its investment in the project. While the project is not subject to a cost cap, Georgia Power's cost and schedule forecasts are subject to numerous uncertainties which could impact cost recovery, including ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Plant Vogtle Units 3 and 4. The ultimate recovery of Georgia Power's investment in Plant Vogtle Units 3 and 4 is subject to the outcome of future assessments by management as well asGeorgia Public Service Commission decisions in future regulatory proceedings. After considering the significant level of uncertainty that exists regarding the future recoverability of these costs since the ultimate outcome of these matters is subject to the outcome of future assessments by management, as well as Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded pre-tax charges to income of $1.692 billion in 2021. In addition, management has disclosed the status, risks, and uncertainties associated with Plant Vogtle Units 3 and 4, including (1) the status of construction; (2) the status of regulatory proceedings; (3) the status of legal actions or issues involving the co-owners of the project; and (4) other matters which could impact the ultimate recoverability of Georgia Power's investment in the project. We identified as a critical audit matter the evaluation ofGeorgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4. This critical audit matter involved significant audit effort requiring specialized industry and construction expertise, extensive knowledge of rate regulation, and difficult and subjective judgments.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4 included the following, among others: •We tested the effectiveness of internal controls over the on-going evaluation, monitoring, and disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4. •We involved construction specialists to assist in our evaluation of the reasonableness of the projected in-service dates for Plant Vogtle Units 3 and 4 and Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and to assess the disclosures of the uncertainties impacting the ultimate cost recovery of its investment in the construction of these units. •We attended meetings with Georgia Power andSouthern Company officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to evaluate and monitor construction status and identify cost and schedule challenges. II-76 -------------------------------------------------------------------------------- Table of Contents Index to Financial Statements •We read reports of external independent monitors employed by theGeorgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of the uncertainties impacting the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4. •We inquired of Georgia Power andSouthern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts. •We inspected regulatory filings and transcripts ofGeorgia Public Service Commission hearings regarding the construction and cost recovery ofPlant Vogtle Units 3 and 4 to identify potential challenges to the recovery ofGeorgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties. •We inquired of Georgia Power andSouthern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project. •We monitored the status of reviews and inspections by the Nuclear Regulatory Commission to identify potential impediments to the licensing and commercial operation of the project that could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4. •We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4. •We obtained representation from management regarding disclosure of all matters related to the cost and/or status of the construction of Plant Vogtle Units 3 and 4, including matters related to a co-owner or regulatory development, that could impact the recovery of the related costs. /s/Deloitte & Touche LLP Atlanta, Georgia February 16, 2022
We have served as
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CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2021, 2020, and 2019
2021 2020 2019
(in millions)
Operating Revenues:
Retail electric revenues $ 14,852 $ 13,643 $ 14,084
Wholesale electric revenues 2,455 1,945 2,152
Other electric revenues 718 672 636
Natural gas revenues 4,380 3,434 3,792
Other revenues 708 681 755
Total operating revenues 23,113 20,375 21,419
Operating Expenses:
Fuel 4,010 2,967 3,622
Purchased power 978 799 816
Cost of natural gas 1,619 972 1,319
Cost of other sales 357 327 435
Other operations and maintenance 6,088 5,413 5,624
Depreciation and amortization 3,565 3,518 3,038
Taxes other than income taxes 1,290 1,234 1,230
Estimated loss on Plant Vogtle Units 3 and 4 1,692 325 -
Impairment charges 2 - 168
Gain on dispositions, net (186) (65) (2,569)
Total operating expenses 19,415 15,490 13,683
Operating Income 3,698 4,885 7,736
Other Income and (Expense):
Allowance for equity funds used during construction 190 149 128
Earnings from equity method investments 76 153 162
Interest expense, net of amounts capitalized (1,837) (1,821) (1,736)
Impairment of leveraged leases (7) (206) -
Other income (expense), net 456 336 252
Total other income and (expense) (1,122) (1,389) (1,194)
Earnings Before Income Taxes 2,576 3,496 6,542
Income taxes 267 393 1,798
Consolidated Net Income 2,309 3,103 4,744
Dividends on preferred stock of subsidiaries 15 15 15
Net loss attributable to noncontrolling interests (99) (31) (10)
Consolidated Net Income Attributable to Southern
Company $ 2,393 $ 3,119 $ 4,739
Common Stock Data:
Earnings per share -
Basic $ 2.26 $ 2.95 $ 4.53
Diluted 2.24 2.93 4.50
Average number of shares of common stock outstanding -
(in millions)
Basic 1,061 1,058 1,046
Diluted 1,068 1,065 1,054
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the Years Ended December 31, 2021, 2020, and 2019
2021 2020 2019
(in millions)
Consolidated Net Income $ 2,309 $ 3,103 $ 4,744
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of
$(16), $3, and $(39), respectively (49) 10 (115)
Reclassification adjustment for amounts included in net income,
net of tax of $31, $(13), and $19, respectively 96 (40) 57 Pension and other postretirement benefit plans: Benefit plan net gain (loss), net of tax of $37, $(17), and $(31), respectively 98 (55) (64)
Reclassification adjustment for amounts included in net income,
net of tax of $5, $3, and $1, respectively 13 10 4 Total other comprehensive income (loss) 158 (75) (118) Dividends on preferred stock of subsidiaries 15 15 15 Comprehensive loss attributable to noncontrolling interests (99) (31) (10)
Consolidated Comprehensive Income Attributable to
$ 2,551 $ 3,044 $ 4,621
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2021, 2020, and 2019
2021 2020 2019
(in millions)
Operating Activities:
Consolidated net income $ 2,309 $ 3,103 $ 4,744
Adjustments to reconcile consolidated net income
to net cash provided from operating activities - Depreciation and amortization, total
3,973 3,905 3,331
Deferred income taxes (49) (241) 611
Utilization of federal investment tax credits 288 341 757
Allowance for equity funds used during construction (190) (149) (128)
Pension, postretirement, and other employee benefits (305) (259) (204)
Pension and postretirement funding - (2) (1,136)
Settlement of asset retirement obligations (456) (442) (328)
Storm damage accruals 288 325 168
Stock based compensation expense 144 113 107
Estimated loss on Plant Vogtle Units 3 and 4 1,692 325 -
Impairment charges 91 206 168
Gain on dispositions, net (176) (66) (2,588)
Retail fuel cost under recovery - long-term (536) - -
Natural gas cost under recovery - long-term (207) - -
Other, net 86 (74) 115
Changes in certain current assets and liabilities -
-Receivables (81) (222) 630
-Materials and supplies (130) (157) (17)
-Natural gas cost under recovery (266) - -
-Other current assets (170) (161) 12
-Accounts payable (8) (27) (693)
-Accrued taxes (54) 242 117
-Retail fuel cost over recovery (155) 96 62
-Customer refunds 130 (236) 126
-Other current liabilities (49) 76 (73)
Net cash provided from operating activities 6,169 6,696 5,781
Investing Activities:
Business acquisitions, net of cash acquired (345) (81) (50)
Property additions (7,240) (7,441) (7,555)
Nuclear decommissioning trust fund purchases (1,598) (877) (888)
Nuclear decommissioning trust fund sales 1,593 871 882
Proceeds from dispositions 917 1,049 5,122
Cost of removal, net of salvage (442) (361) (393)
Change in construction payables, net (124) 37 (169)
Payments pursuant to LTSAs (188) (211) (234)
Other investing activities 74 (16) (107)
Net cash used for investing activities (7,353) (7,030) (3,392)
Financing Activities:
Increase (decrease) in notes payable, net 530 (1,096) 640
Proceeds -
Long-term debt 8,262 8,047 5,220
Short-term borrowings 325 615 350
Common stock 73 74 844
Redemptions and repurchases -
Long-term debt (4,327) (4,458) (4,347)
Short-term borrowings (25) (840) (1,850)
Capital contributions from noncontrolling interests 501 363 196
Distributions to noncontrolling interests (351) (271) (256)
Payment of common stock dividends (2,777) (2,685) (2,570)
Other financing activities (266) (325) (157)
Net cash provided from (used for) financing activities 1,945 (576) (1,930)
Net Change in Cash, Cash Equivalents, and Restricted Cash 761 (910) 459
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
1,068 1,978 1,519
Cash, Cash Equivalents, and Restricted Cash at End of Year $ 1,829
$ 1,068 $ 1,978
Supplemental Cash Flow Information:
Cash paid during the period for -
Interest (net of $92, $81, and $74 capitalized, respectively) $ 1,718 $ 1,683 $ 1,651
Income taxes, net 93 64 276
Noncash transactions -
Accrued property additions at year-end 866 989 932
Contributions from noncontrolling interests 89 12 80
Contributions of wind turbine equipment 82 17 26
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company and Subsidiary Companies 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 1,798 $ 1,065
Receivables -
Customer accounts 1,806 1,753
Energy marketing - 516
Unbilled revenues 711 672
Other accounts and notes 523 512
Accumulated provision for uncollectible accounts (78) (118)
Materials and supplies 1,543 1,478
Fossil fuel for generation 450 550
Natural gas for sale 362 460
Prepaid expenses 330 276
Assets from risk management activities, net of collateral 151 147
Regulatory assets - asset retirement obligations 219 214
Natural gas cost under recovery 266 -
Other regulatory assets 653 810
Other current assets 231 282
Total current assets 8,965 8,617
Property, Plant, and Equipment:
In service 115,592 110,516
Less: Accumulated depreciation 34,079 32,397
Plant in service, net of depreciation 81,513 78,119
Nuclear fuel, at amortized cost 824 818
Construction work in progress 8,771 8,697
Total property, plant, and equipment 91,108 87,634
Other Property and Investments:
Goodwill 5,280 5,280
Nuclear decommissioning trusts, at fair value 2,542 2,303
Equity investments in unconsolidated subsidiaries 1,282 1,362
Other intangible assets, net of amortization of $307 and $328, respectively
445 487
Leveraged leases - 556
Miscellaneous property and investments 653 398
Total other property and investments 10,202 10,386
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization 1,701 1,802
Deferred charges related to income taxes 824 796
Prepaid pension costs 1,657 -
Unamortized loss on reacquired debt 258 280
Regulatory assets - asset retirement obligations, deferred 5,466 4,934
Other regulatory assets, deferred 5,577 7,198
Other deferred charges and assets 1,776 1,288
Total deferred charges and other assets 17,259 16,298
Total Assets $ 127,534 $ 122,935
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company and Subsidiary Companies 2021 Annual Report
Liabilities and Stockholders' Equity 2021 2020
(in millions)
Current Liabilities:
Securities due within one year $ 2,157 $ 3,507
Notes payable 1,440 609 Energy marketing trade payables - 494 Accounts payable 2,169 2,312 Customer deposits 479 487 Accrued taxes - Accrued income taxes 50 130 Other accrued taxes 641 699 Accrued interest 533 513 Accrued compensation 1,070 1,025 Asset retirement obligations 697 585 Operating lease obligations 250 241 Other regulatory liabilities 563 509 Other current liabilities 872 968 Total current liabilities 10,921 12,079 Long-Term Debt 50,120 45,073 Deferred Credits and Other Liabilities: Accumulated deferred income taxes 8,862 8,175 Deferred credits related to income taxes 5,401 5,767 Accumulated deferred ITCs 2,216 2,235 Employee benefit obligations 1,550 2,213 Operating lease obligations, deferred 1,503 1,611 Asset retirement obligations, deferred 10,990 10,099 Other cost of removal obligations 2,103 2,211 Other regulatory liabilities, deferred 485 251 Other deferred credits and liabilities 816 696 Total deferred credits and other liabilities 33,926 33,258 Total Liabilities 94,967 90,410 Redeemable Preferred Stock of Subsidiaries: Cumulative preferred stock
$100 par or stated value - 4.20% to 4.92%
(Authorized - 10 million shares; Outstanding - 0.5 million shares)
48 48
$1 par value - 5.00% (Authorized - 28 million shares; Outstanding - 10 million shares)
243 243
Total redeemable preferred stock of subsidiaries (annual dividend requirement - $15 million)
291 291
Common Stockholders' Equity: Common stock, par value $5 per share (Authorized - 1.5 billion shares)
5,279 5,268
(Issued - 1.1 billion shares;
Paid-in capital 11,950 11,834 Treasury, at cost (47) (46) Retained earnings 10,929 11,311 Accumulated other comprehensive loss (237) (395) Total common stockholders' equity 27,874 27,972 Noncontrolling interests 4,402 4,262 Total Stockholders' Equity (See accompanying statements) 32,276 32,234 Total Liabilities and Stockholders' Equity $ 127,534 $ 122,935 Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended December 31, 2021, 2020, and 2019
Southern Company Common Stockholders' Equity
Accumulated
Number of Common Shares Common Stock Other
Comprehensive
Paid-In Retained Income Noncontrolling
Issued Treasury Par Value Capital Treasury Earnings (Loss) Interests Total
(in millions)
Balance at December 31, 2018 1,035 (1) $ 5,164 $ 11,094 $ (38) $ 8,706 $ (203) $ 4,316 $ 29,039
Consolidated net income (loss) - - - - - 4,739 - (10) 4,729
Other comprehensive income (loss) - - - - - - (118) - (118)
Issuance of equity units(*) - - - (198) - - - - (198)
Stock issued 19 - 93 751 - - - - 844
Stock-based compensation - - - 66 - - - - 66
Cash dividends of $2.4600 per share - - - - - (2,570) - - (2,570)
Contributions from
noncontrolling interests - - - - - - - 276 276
Distributions to
noncontrolling interests - - - - - - - (327) (327)
Other - - - 21 (4) 2 - (1) 18
Balance at December 31, 2019 1,054 (1) 5,257 11,734 (42) 10,877 (321) 4,254 31,759
Consolidated net income (loss) - - - - - 3,119 - (31) 3,088
Other comprehensive income (loss) - - - - - - (75) - (75)
Stock issued 4 - 11 63 - - - - 74
Stock-based compensation - - - 44 - - - - 44
Cash dividends of $2.5400 per share - - - - - (2,685) - - (2,685)
Contributions from
noncontrolling interests - - - - - - - 307 307
Distributions to
noncontrolling interests - - - - - - - (271) (271)Purchase of membership interests
from noncontrolling interests - - - 5 - - - (65) (60) Sale of noncontrolling interests - - - (2) - - - 67 65 Other - - - (10) (4) - 1 1 (12) Balance at December 31, 2020 1,058 (1) 5,268 11,834 (46) 11,311 (395) 4,262 32,234 Consolidated net income (loss) - - - - - 2,393 - (99) 2,294 Other comprehensive income - - - - - - 158 - 158 Stock issued 3 - 11 62 - - - - 73 Stock-based compensation - - - 62 - - - - 62 Cash dividends of $2.6200 per share - - - - - (2,777) - - (2,777) Contributions from noncontrolling interests - - - - - - - 590 590 Distributions to noncontrolling interests - - - - - - - (351) (351) Other - - - (8) (1) 2 - - (7) Balance at December 31, 2021 1,061 (1) $ 5,279 $ 11,950 $ (47) $ 10,929 $ (237) $ 4,402 $ 32,276
(*)See Note 8 under "Equity Units" for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of
Opinion on the Financial Statements
We have audited the accompanying balance sheets ofAlabama Power Company (Alabama Power ) (a wholly-owned subsidiary ofThe Southern Company ) as of December 31, 2021 and 2020, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Alabama Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Alabama Power's management. Our responsibility is to express an opinion on Alabama Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Alabama Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Alabama Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Alabama Power's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Impact of Rate Regulation on the Financial Statements - Refer to Note 1 (Summary of Significant Accounting Policies - Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters - Alabama Power) to the financial statements
Critical Audit Matter Description
Alabama Power is subject to retail rate regulation by the Alabama Public Service
Commission and wholesale regulation by the Federal Energy Regulatory Commission
(collectively, the "Commissions"). Management has determined that it meets the
requirements under accounting principles generally accepted in the United States
of America to utilize specialized rules to account for the effects of rate
regulation in the preparation of its financial statements. Accounting for the
economics of rate regulation impacts multiple financial statement line items and
disclosures, including, but not limited to, property, plant, and equipment;
other regulatory assets; other regulatory liabilities; other cost of removal
obligations; deferred charges and credits related to income taxes; under and
over recovered regulatory clause revenues; operating revenues; operations and
maintenance expenses; and depreciation and amortization.
The Commissions set the rates Alabama Power is permitted to charge customers.
Rates are determined and approved in regulatory proceedings based on an analysis
of Alabama Power's costs to provide utility service and a return on, and
recovery of, its investment in the utility business. Current and future
regulatory decisions can have an impact on the recovery of costs, the rate of
return earned on investments, and the timing and amount of assets to be
recovered by rates. The Commissions' regulation of rates is premised on the full
recovery of prudently incurred costs and a reasonable rate of return on invested
capital. While Alabama Power expects to recover costs from customers through
regulated rates, there is a risk that the Commissions will not approve: (1)
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full recovery of the costs of providing utility service, or (2) full recovery of
all amounts invested in the utility business and a reasonable return on that
investment.
We identified the impact of rate regulation as a critical audit matter due to
the significant judgments made by management to support its assertions about
impacted account balances and disclosures (e.g., asset retirement costs and the
remaining net book values of retired assets) and the high degree of subjectivity
involved in assessing the potential impact of future regulatory orders on the
financial statements. Management judgments include assessing the likelihood of
(1) recovery in future rates of incurred costs, (2) a disallowance of part of
the cost of recently completed plant or plant under construction, and/or (3) a
refund to customers. Given that management's accounting judgments are based on
assumptions about the outcome of future decisions by the Commissions, auditing
these judgments required specialized knowledge of accounting for rate regulation
and the rate setting process due to its inherent complexities and significant
auditor judgment to evaluate management estimates and the subjectivity of audit
evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates. •We read relevant regulatory orders issued by the Commissions for Alabama Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected filings with the Commissions by Alabama Power and other interested parties that may impact Alabama Power's future rates for any evidence that might contradict management's assertions.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.
•We evaluated Alabama Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP Birmingham, Alabama February 16, 2022
We have served as Alabama Power's auditor since 2002.
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STATEMENTS OF INCOME For the Years Ended December 31, 2021, 2020, and 2019 Alabama Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Revenues:
Retail revenues $ 5,499 $ 5,213 $ 5,501
Wholesale revenues, non-affiliates 377 269 258
Wholesale revenues, affiliates 171 46 81 Other revenues 366 302 285 Total operating revenues 6,413 5,830 6,125 Operating Expenses: Fuel 1,235 970 1,112 Purchased power, non-affiliates 221 191
203
Purchased power, affiliates 147 128
200
Other operations and maintenance 1,735 1,619 1,821 Depreciation and amortization 859 812 793 Taxes other than income taxes 410 416 403 Total operating expenses 4,607 4,136 4,532 Operating Income 1,806 1,694 1,593 Other Income and (Expense): Allowance for equity funds used during construction 52 46
52
Interest expense, net of amounts capitalized (340) (338)
(336)
Other income (expense), net 107 100
46
Total other income and (expense) (181) (192)
(238)
Earnings Before Income Taxes 1,625 1,502 1,355 Income taxes 372 337 270 Net Income 1,253 1,165 1,085 Dividends on Preferred Stock 15 15
15
Net Income After Dividends on Preferred Stock $ 1,238 $ 1,150
$ 1,070
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2021, 2020, and 2019 Alabama Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Net Income $ 1,253 $ 1,165 $ 1,085
Other comprehensive income:
Qualifying hedges:
Changes in fair value, net of tax of $1, $-, and $-,
respectively 2 - -
Reclassification adjustment for amounts included in net income,
net of tax of $2, $2, and $2, respectively 4 4 4 Total other comprehensive income 6 4 4 Comprehensive Income $ 1,259 $ 1,169 $ 1,089
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2021, 2020, and 2019 Alabama Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Activities:
Net income $ 1,253 $ 1,165 $ 1,085
Adjustments to reconcile net income
to net cash provided from operating activities - Depreciation and amortization, total
1,005 963 951
Deferred income taxes 245 78 197
Allowance for equity funds used during construction (52) (46) (52)
Pension, postretirement, and other employee benefits (106) (88) (95)
Pension and postretirement funding - (2) (362)
Settlement of asset retirement obligations (202) (219) (127)
Natural disaster reserve accruals 75 112 138
Retail fuel cost under recovery - long-term (126) - -
Other deferred charges - affiliated - - (42)
Other, net (51) 50 4
Changes in certain current assets and liabilities -
-Receivables 42 (49) 9
-Materials and supplies (6) (47) 23
-Other current assets 44 (66) (89)
-Accounts payable (109) (90) (41)
-Accrued taxes (56) 84 49
-Accrued compensation (7) (32) (14)
-Retail fuel cost over recovery (18) (31) 47
-Customer refunds 128 (12) 30
-Other current liabilities (6) (28) 68
Net cash provided from operating activities 2,053 1,742 1,779
Investing Activities:
Property additions (1,753) (1,970) (1,757)
Nuclear decommissioning trust fund purchases (638) (268) (261)
Nuclear decommissioning trust fund sales 637 267 260
Cost of removal net of salvage (165) (98) (103)
Change in construction payables (16) (34) (71)
Other investing activities (26) (19) (31)
Net cash used for investing activities (1,961) (2,122) (1,963)
Financing Activities:
Proceeds -
Senior notes 1,300 600 600
Pollution control revenue bonds - 87 -
Redemptions and repurchases -
Senior notes (200) (250) (200)
Pollution control revenue bonds (65) (87) -
Other long-term debt (206) - -
Capital contributions from parent company 636 653 1,240
Payment of common stock dividends (984) (957) (844)
Other financing activities (43) (30) (31)
Net cash provided from financing activities 438 16 765
Net Change in Cash, Cash Equivalents, and Restricted Cash 530 (364) 581
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
530 894 313
Cash, Cash Equivalents, and Restricted Cash at End of Year $ 1,060
$ 530 $ 894
Supplemental Cash Flow Information:
Cash paid during the period for -
Interest (net of $15, $15, and $19 capitalized, respectively) $ 308 $ 321 $ 311
Income taxes, net 185 187 26
Noncash transactions - Accrued property additions at year-end 150
166 200
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Alabama Power Company 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 1,060 $ 530
Receivables -
Customer accounts 410 429
Unbilled revenues 138 152
Affiliated 37 31
Other accounts and notes 55 66
Accumulated provision for uncollectible accounts (14) (43)
Fossil fuel stock 159 235
Materials and supplies 548 546
Prepaid expenses 41 42
Other regulatory assets 208 226
Other current assets 67 33
Total current assets 2,709 2,247
Property, Plant, and Equipment:
In service 33,135 31,816
Less: Accumulated provision for depreciation 10,313
10,009
Plant in service, net of depreciation 22,822
21,807
Nuclear fuel, at amortized cost 247
270
Construction work in progress 1,147
866
Total property, plant, and equipment 24,216
22,943
Other Property and Investments: Nuclear decommissioning trusts, at fair value 1,325
1,157
Equity investments in unconsolidated subsidiaries 57
63
Miscellaneous property and investments 126
131
Total other property and investments 1,508
1,351
Deferred Charges and Other Assets: Operating lease right-of-use assets, net of amortization 108
151
Deferred charges related to income taxes 240
235
Prepaid pension and other postretirement benefit costs 513
-
Regulatory assets - asset retirement obligations 1,547
1,441
Other regulatory assets, deferred 1,807
2,162
Other deferred charges and assets 334
273
Total deferred charges and other assets 4,549 4,262 Total Assets $ 32,982 $ 30,803
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Alabama Power Company 2021 Annual Report
Liabilities and Stockholder's Equity 2021 2020
(in millions)
Current Liabilities:
Securities due within one year $ 751 $ 311
Accounts payable -
Affiliated 309 316
Other 459 545
Customer deposits 106 104
Accrued taxes 98 152
Accrued interest 100 90
Accrued compensation 219 212
Asset retirement obligations 320 254
Other regulatory liabilities 215 108
Other current liabilities 125 107
Total current liabilities 2,702 2,199
Long-Term Debt 8,936 8,558
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 3,573 3,273
Deferred credits related to income taxes 1,968 2,016
Accumulated deferred ITCs 88 94
Employee benefit obligations 171 214
Operating lease obligations 66 119
Asset retirement obligations, deferred 4,014 3,720
Other cost of removal obligations 192 335
Other regulatory liabilities, deferred 210 124
Other deferred credits and liabilities 58 50
Total deferred credits and other liabilities 10,340 9,945
Total Liabilities 21,978 20,702
Redeemable Preferred Stock:
Cumulative redeemable preferred stock
$100 par or stated value - 4.20% to 4.92%
(Authorized - 3.9 million shares; Outstanding - 0.5 million shares)
48 48
$1 par value - 5.00%
(Authorized - 27.5 million shares; Outstanding - 10 million shares: $25 stated value)
243 243
Total redeemable preferred stock (annual dividend requirement - $15 million)
291 291
Common Stockholder's Equity:
Common stock, par value $40 per share
(Authorized - 40 million shares; Outstanding - 31 million shares) 1,222 1,222
Paid-in capital 6,056 5,413
Retained earnings 3,448 3,194
Accumulated other comprehensive loss (13) (19)
Total common stockholder's equity (See accompanying statements) 10,713
9,810
Total Liabilities and Stockholder's Equity $ 32,982 $ 30,803
Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2021, 2020, and 2019 Alabama Power Company 2021 Annual Report
Number of Accumulated
Common Other
Shares Common Paid-In Retained Comprehensive
Issued Stock Capital Earnings Income (Loss) Total
(in millions)
Balance at December 31, 2018 31 $ 1,222 $ 3,508 $ 2,775 $ (28) $ 7,477
Net income after dividends on
preferred stock - - - 1,070 - 1,070
Capital contributions from parent
company - - 1,247 - - 1,247
Other comprehensive income - - - - 4 4
Cash dividends on common stock - - - (844) - (844)
Other - - - - 1 1
Balance at December 31, 2019 31 1,222 4,755 3,001 (23) 8,955
Net income after dividends on
preferred stock - - - 1,150 - 1,150 Capital contributions from parent company - - 658 - - 658 Other comprehensive income - - - - 4 4 Cash dividends on common stock - - - (957) - (957) Balance at December 31, 2020 31 1,222 5,413 3,194 (19) 9,810
Net income after dividends on
preferred stock - - - 1,238 - 1,238 Capital contributions from parent company - - 643 - - 643 Other comprehensive income - - - - 6 6 Cash dividends on common stock - - - (984) - (984) Balance at December 31, 2021 31 $ 1,222 $
6,056 $ 3,448 $ (13) $ 10,713
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Georgia Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Georgia Power Company (Georgia Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2021 and 2020, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Georgia Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Georgia Power's management. Our responsibility is to express an opinion on Georgia Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Georgia Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Georgia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Georgia Power's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. Impact of Rate Regulation on the Financial Statements - Refer to Note 1 (Summary of Significant Accounting Policies - Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters - Georgia Power) to the financial statements
Critical Audit Matter Description
Georgia Power is subject to retail rate regulation by the Georgia Public Service
Commission and wholesale regulation by the Federal Energy Regulatory Commission
(collectively, the "Commissions"). Management has determined that it meets the
requirements under accounting principles generally accepted in the United States
of America to utilize specialized rules to account for the effects of rate
regulation in the preparation of its financial statements. Accounting for the
economics of rate regulation impacts multiple financial statement line items and
disclosures, including, but not limited to, property, plant, and equipment;
other regulatory assets; other regulatory liabilities; other cost of removal
obligations; deferred charges and credits related to income taxes; under and
over recovered regulatory clause revenues; operating revenues; operations and
maintenance expenses; and depreciation and amortization.
The Commissions set the rates Georgia Power is permitted to charge customers.
Rates are determined and approved in regulatory proceedings based on an analysis
of Georgia Power's costs to provide utility service and a return on, and
recovery of, its investment in the utility business. Current and future
regulatory decisions can have an impact on the recovery of costs, the rate of
return earned on investments, and the timing and amount of assets to be
recovered by rates. The Commissions' regulation of rates is premised on the full
recovery of prudently incurred costs and a reasonable rate of return on invested
capital. While Georgia Power expects to recover costs from customers through
regulated rates, there is a risk that the Commissions will not approve: (1)
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full recovery of the costs of providing utility service, or (2) full recovery of
all amounts invested in the utility business and a reasonable return on that
investment.
We identified the impact of rate regulation as a critical audit matter due to
the significant judgments made by management to support its assertions about
impacted account balances and disclosures (e.g., asset retirement costs,
property damage reserves, and remaining net book values of retired assets) and
the high degree of subjectivity involved in assessing the potential impact of
future regulatory orders on the financial statements. Management judgments
include assessing the likelihood of (1) recovery in future rates of incurred
costs, (2) a disallowance of part of the cost of recently completed plant or
plant under construction, and/or (3) a refund to customers. Given that
management's accounting judgments are based on assumptions about the outcome of
future decisions by the Commissions, auditing these judgments required
specialized knowledge of accounting for rate regulation and the rate setting
process due to its inherent complexities and significant auditor judgment to
evaluate management estimates and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates. •We read relevant regulatory orders issued by the Commissions for Georgia Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected filings with the Commissions by Georgia Power and other interested parties that may impact Georgia Power's future rates for any evidence that might contradict management's assertions.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.
•We evaluated Georgia Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
Disclosure of Uncertainties - Plant Vogtle Units 3 and 4 Construction - Refer to Note 2 (Regulatory Matters - Georgia Power - Nuclear Construction) to the financial statements
Critical Audit Matter Description
As discussed in Note 2 to the financial statements, the ultimate recovery of
Georgia Power's investment in the construction of Plant Vogtle Units 3 and 4 is
subject to multiple uncertainties. Such uncertainties include the potential
impact of future decisions by Georgia Power's regulators (particularly the
Georgia Public Service Commission) and potential actions by the co-owners of the
Vogtle project. In addition, Georgia Power's ability to meet its cost and
schedule forecasts could impact its ability to fully recover its investment in
the project. While the project is not subject to a cost cap, Georgia Power's
cost and schedule forecasts are subject to numerous uncertainties which could
impact cost recovery, including ongoing or future challenges with management of
contractors and vendors; subcontractor performance; supervision of craft labor
and related productivity, particularly in the installation of electrical,
mechanical, and instrumentation and controls commodities, ability to attract and
retain craft labor, and/or related cost escalation; and procurement and related
installation. New challenges may arise, particularly as Units 3 and 4 move into
initial testing and start-up, which may result in required engineering changes
or remediation related to plant systems, structures, or components (some of
which are based on new technology that only within the last few years began
initial operation in the global nuclear industry at this scale). The ongoing and
potential future challenges described above may change the projected schedule
and estimated cost.
In addition, the continuing effects of the COVID-19 pandemic could further
disrupt or delay construction, testing, supervisory, and support activities at
Plant Vogtle Units 3 and 4. The ultimate recovery of Georgia Power's investment
in Plant Vogtle Units 3 and 4 is subject to the outcome of future assessments by
management as well as Georgia Public Service Commission decisions in
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future regulatory proceedings. After considering the significant level of
uncertainty that exists regarding the future recoverability of these costs since
the ultimate outcome of these matters is subject to the outcome of future
assessments by management, as well as Georgia PSC decisions in future regulatory
proceedings, Georgia Power recorded pre-tax charges to income of $1.692 billion
in 2021.
In addition, management has disclosed the status, risks, and uncertainties
associated with Plant Vogtle Units 3 and 4, including (1) the status of
construction; (2) the status of regulatory proceedings; (3) the status of legal
actions or issues involving the co-owners of the project; and (4) other matters
which could impact the ultimate recoverability of Georgia Power's investment in
the project. We identified as a critical audit matter the evaluation of Georgia
Power's identification and disclosure of events and uncertainties that could
impact the ultimate cost recovery of its investment in the construction of Plant
Vogtle Units 3 and 4. This critical audit matter involved significant audit
effort requiring specialized industry and construction expertise, extensive
knowledge of rate regulation, and difficult and subjective judgments.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to Georgia Power's identification and disclosure of events and uncertainties that could impact the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4 included the following, among others: •We tested the effectiveness of internal controls over the on-going evaluation, monitoring, and disclosure of matters related to the construction and ultimate cost recovery of Plant Vogtle Units 3 and 4. •We involved construction specialists to assist in our evaluation of the reasonableness of the projected in-service dates for Plant Vogtle Units 3 and 4 and Georgia Power's processes for on-going evaluation and monitoring of the construction schedule and to assess the disclosures of the uncertainties impacting the ultimate cost recovery of its investment in the construction of these units. •We attended meetings with Georgia Power and Southern Company officials, project managers (including contractors), independent regulatory monitors, and co-owners of the project to evaluate and monitor construction status and identify cost and schedule challenges. •We read reports of external independent monitors employed by the Georgia Public Service Commission to monitor the status of construction at Plant Vogtle Units 3 and 4 to evaluate the completeness of Georgia Power's disclosure of the uncertainties impacting the ultimate cost recovery of its investment in the construction of Plant Vogtle Units 3 and 4. •We inquired of Georgia Power and Southern Company officials and project managers regarding the status of construction, the construction schedule, and cost forecasts to assess the financial statement disclosures with respect to project status and potential risks and uncertainties to the achievement of such forecasts. •We inspected regulatory filings and transcripts of Georgia Public Service Commission hearings regarding the construction and cost recovery of Plant Vogtle Units 3 and 4 to identify potential challenges to the recovery of Georgia Power's construction costs and to evaluate the disclosures with respect to such uncertainties. •We inquired of Georgia Power and Southern Company management and internal and external legal counsel regarding any potential legal actions or issues arising from project construction or issues involving the co-owners of the project. •We monitored the status of reviews and inspections by the Nuclear Regulatory Commission to identify potential impediments to the licensing and commercial operation of the project that could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4. •We compared the financial statement disclosures relating to this matter to the information gathered through the conduct of all our procedures to evaluate whether there were omissions relating to significant facts or uncertainties regarding the status of construction or other factors which could impact the ultimate cost recovery of Plant Vogtle Units 3 and 4. •We obtained representation from management regarding disclosure of all matters related to the cost and/or status of the construction of Plant Vogtle Units 3 and 4, including matters related to a co-owner or regulatory development, that could impact the recovery of the related costs. /s/ Deloitte & Touche LLP Atlanta, Georgia February 16, 2022
We have served as Georgia Power's auditor since 2002.
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STATEMENTS OF INCOME For the Years Ended December 31, 2021, 2020, and 2019 Georgia Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Revenues:
Retail revenues $ 8,478 $ 7,609 $ 7,707
Wholesale revenues 197 115 140
Other revenues 585 585 561
Total operating revenues 9,260 8,309 8,408
Operating Expenses:
Fuel 1,449 1,141 1,444
Purchased power, non-affiliates 632 540 521
Purchased power, affiliates 859 509
575
Other operations and maintenance 2,213 1,953
1,972
Depreciation and amortization 1,371 1,425
981
Taxes other than income taxes 476 444
454
Estimated loss on Plant Vogtle Units 3 and 4 1,692 325 - Total operating expenses 8,692 6,337 5,947 Operating Income 568 1,972 2,461 Other Income and (Expense): Allowance for equity funds used during construction 127 91
68
Interest expense, net of amounts capitalized (421) (425)
(409)
Other income (expense), net 142 89
72
Total other income and (expense) (152) (245)
(269)
Earnings Before Income Taxes 416 1,727 2,192 Income taxes (benefit) (168) 152 472 Net Income $ 584 $ 1,575 $ 1,720
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2021, 2020, and 2019 Georgia Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Net Income $ 584 $ 1,575 $ 1,720
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $-, $(1), and
$(15), respectively - (2) (44)
Reclassification adjustment for amounts included in net income,
net of tax of $2, $2, and $1, respectively 6 6 2 Total other comprehensive income (loss) 6 4 (42) Comprehensive Income $ 590 $ 1,579 $ 1,678
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2021, 2020, and 2019 Georgia Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Activities:
Net income $ 584 $ 1,575 $ 1,720
Adjustments to reconcile net income
to net cash provided from operating activities - Depreciation and amortization, total
1,557 1,607 1,193
Deferred income taxes (550) (273) 179
Allowance for equity funds used during construction (127) (91) (68)
Pension, postretirement, and other employee benefits (148) (137) (146)
Pension and postretirement funding - - (200)
Settlement of asset retirement obligations (210) (185) (151)
Storm damage accruals 213 213 30
Retail fuel cost recovery - long-term (410) (73) 73
Other deferred charges - affiliated - - (108)
Estimated loss on Plant Vogtle Units 3 and 4 1,692 325 -
Other, net 53 14 50
Changes in certain current assets and liabilities -
-Receivables 81 (114) 177
-Fossil fuel stock 30 (6) (41)
-Materials and supplies (82) (91) (4)
-Prepaid income taxes - - 102
-Other current assets (30) (48) (15)
-Accounts payable 186 59 (92)
-Accrued taxes 21 55 58
-Retail fuel cost over recovery (113) 113 -
-Customer refunds 1 (223) 116
-Other current liabilities (1) 64 34
Net cash provided from operating activities 2,747 2,784 2,907
Investing Activities:
Property additions (3,376) (3,445) (3,510)
Nuclear decommissioning trust fund purchases (960) (609) (628)
Nuclear decommissioning trust fund sales 956 604 622
Cost of removal, net of salvage (149) (143) (186)
Change in construction payables, net of joint owner portion (65) 16 (122)
Payments pursuant to LTSAs (42) (86) (81)
Contributions in aid of construction 65 20 18
Proceeds from dispositions 8 153 14
Other investing activities (27) (13) (12)
Net cash used for investing activities (3,590) (3,503) (3,885)
Financing Activities:
Decrease in notes payable, net (60) (55) (179)
Proceeds -
Senior notes 750 1,500 750
FFB loan 440 848 1,218
Pollution control revenue bonds 122 53 584
Short-term borrowings - 250 250
Redemptions and repurchases -
Senior notes (325) (950) (500)
FFB loan (96) (73) -
Pollution control revenue bonds (69) (336) (223)
Short-term borrowings - (375) -
Capital contributions from parent company 1,782 1,392 634
Payment of common stock dividends (1,649) (1,542) (1,576)
Other financing activities (28) (36) (40)
Net cash provided from financing activities 867 676 918
Net Change in Cash, Cash Equivalents, and Restricted Cash 24 (43) (60)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
9 52 112
Cash, Cash Equivalents, and Restricted Cash at End of Year $ 33
$ 9 $ 52
Supplemental Cash Flow Information:
Cash paid during the period for -
Interest (net of $63, $47, and $35 capitalized, respectively) $ 382 $ 380 $ 373
Income taxes, net 305 373 110
Noncash transactions - Accrued property additions at year-end 479
553 560
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Georgia Power Company 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 33 $ 9
Receivables -
Customer accounts 549 621
Unbilled revenues 231 233
Joint owner accounts 116 123
Affiliated 25 21
Other accounts and notes 44 67
Accumulated provision for uncollectible accounts (2) (26)
Fossil fuel stock 248 278
Materials and supplies 670 592
Regulatory assets - storm damage 48 213
Regulatory assets - asset retirement obligations 178 166 Other regulatory assets 241 248 Other current assets 178 143 Total current assets 2,559 2,688 Property, Plant, and Equipment: In service 41,332
39,682
Less: Accumulated provision for depreciation 12,854
12,251
Plant in service, net of depreciation 28,478
27,431
Nuclear fuel, at amortized cost 577
548
Construction work in progress 6,688
6,857
Total property, plant, and equipment 35,743
34,836
Other Property and Investments: Nuclear decommissioning trusts, at fair value 1,217
1,145
Equity investments in unconsolidated subsidiaries 50
51
Miscellaneous property and investments 69
63
Total other property and investments 1,336
1,259
Deferred Charges and Other Assets: Operating lease right-of-use assets, net of amortization 1,157
1,308
Deferred charges related to income taxes 550
527
Prepaid pension costs 563
-
Deferred under recovered fuel clause revenues 410
-
Regulatory assets - asset retirement obligations, deferred 3,688
3,291
Other regulatory assets, deferred 1,964
2,692
Other deferred charges and assets 491
479
Total deferred charges and other assets 8,823 8,297 Total Assets $ 48,461 $ 47,080
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Georgia Power Company 2021 Annual Report
Liabilities and Stockholder's Equity 2021 2020
(in millions)
Current Liabilities:
Securities due within one year $ 675 $ 542
Notes payable - 60
Accounts payable -
Affiliated 757 597
Other 702 753
Customer deposits 259 276
Accrued taxes 335 407
Accrued interest 136 130
Accrued compensation 232 233
Operating lease obligations 156 151
Asset retirement obligations 317 287
Over recovered fuel clause revenues - 113
Other regulatory liabilities 280 228
Other current liabilities 254 254
Total current liabilities 4,103 4,031
Long-Term Debt 13,109 12,428
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 3,019 3,272
Deferred credits related to income taxes 2,321 2,588
Accumulated deferred ITCs 328 273
Employee benefit obligations 402 586
Operating lease obligations, deferred 999 1,156
Asset retirement obligations, deferred 6,507 5,978
Other deferred credits and liabilities 439 267
Total deferred credits and other liabilities 14,015 14,120
Total Liabilities 31,227 30,579
Common Stockholder's Equity:
Common stock, without par value
(Authorized - 20 million shares; Outstanding - 9 million shares) 398 398
Paid-in capital 14,153 12,361
Retained earnings 2,724 3,789
Accumulated other comprehensive loss (41) (47)
Total common stockholder's equity (See accompanying statements) 17,234
16,501
Total Liabilities and Stockholder's Equity $ 48,461 $ 47,080
Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2021, 2020, and 2019 Georgia Power Company 2021 Annual Report
Accumulated Other
Number of Common Paid-In Retained Comprehensive
Shares Issued Common Stock Capital Earnings Income (Loss) Total
(in millions)
Balance at December 31, 2018 9 $ 398 $ 10,322 $ 3,612 $ (9) $ 14,323
Net income - - - 1,720 - 1,720
Capital contributions from
parent company - - 640 - - 640
Other comprehensive income
(loss) - - - - (42) (42)
Cash dividends on common stock - - - (1,576) - (1,576)
Balance at December 31, 2019 9 398 10,962 3,756 (51) 15,065 Net income - - - 1,575 - 1,575 Capital contributions from parent company - - 1,399 - - 1,399 Other comprehensive income - - - - 4 4 Cash dividends on common stock - - - (1,542) -
(1,542)
Balance at December 31, 2020 9 398 12,361 3,789 (47) 16,501 Net income - - - 584 - 584 Capital contributions from parent company - - 1,792 - - 1,792 Other comprehensive income - - - - 6 6 Cash dividends on common stock - - - (1,649) -
(1,649)
Balance at December 31, 2021 9 $ 398 $ 14,153 $ 2,724 $ (41) $ 17,234
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Mississippi Power Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Mississippi Power Company (Mississippi Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2021 and 2020, the related statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Mississippi Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Mississippi Power's management. Our responsibility is to express an opinion on Mississippi Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Mississippi Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Mississippi Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Mississippi Power's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Impact of Rate Regulation on the Financial Statements - Refer to Note 1 (Summary of Significant Accounting Policies - Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters - Mississippi Power) to the financial statements
Critical Audit Matter Description
Mississippi Power is subject to retail rate regulation by the Mississippi Public
Service Commission and wholesale regulation by the Federal Energy Regulatory
Commission (collectively, the "Commissions"). Management has determined that it
meets the requirements under accounting principles generally accepted in the
United States of America to utilize specialized rules to account for the effects
of rate regulation in the preparation of its financial statements. Accounting
for the economics of rate regulation impacts multiple financial statement line
items and disclosures, including, but not limited to, property, plant, and
equipment; other regulatory assets; other regulatory liabilities; regulatory
assets - asset retirement obligations; other cost of removal obligations;
deferred charges and credits related to income taxes; under and over recovered
regulatory clause revenues; operating revenues; operations and maintenance
expenses; and depreciation and amortization.
The Commissions set the rates Mississippi Power is permitted to charge
customers. Rates are determined and approved in regulatory proceedings based on
an analysis of Mississippi Power's costs to provide utility service and a return
on, and recovery of, its investment in the utility business. Current and future
regulatory decisions can have an impact on the recovery of costs, the rate of
return earned on investments, and the timing and amount of assets to be
recovered by rates. The Commissions' regulation of rates is premised on the full
recovery of prudently incurred costs and a reasonable rate of return on invested
capital. While Mississippi Power expects to recover costs from customers through
regulated rates, there is a risk that the Commissions will not
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approve: (1) full recovery of the costs of providing utility service, or (2)
full recovery of all amounts invested in the utility business and a reasonable
return on that investment.
We identified the impact of rate regulation as a critical audit matter due to
the significant judgments made by management to support its assertions about
impacted account balances and disclosures (e.g., asset retirement costs,
property damage reserves, and the remaining net book values of retired assets)
and the high degree of subjectivity involved in assessing the potential impact
of future regulatory orders on the financial statements. Management judgments
include assessing the likelihood of (1) recovery in future rates of incurred
costs, (2) a disallowance of part of the cost of recently completed plant,
and/or (3) a refund to customers. Given that management's accounting judgments
are based on assumptions about the outcome of future decisions by the
Commissions, auditing these judgments required specialized knowledge of
accounting for rate regulation and the rate setting process due to its inherent
complexities and significant auditor judgment to evaluate management estimates
and the subjectivity of audit evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We read relevant regulatory orders issued by the Commissions for Mississippi Power, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.
•For regulatory matters in process, we inspected filings with the Commissions by Mississippi Power and other interested parties that may impact Mississippi Power's future rates for any evidence that might contradict management's assertions.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery, refund, or a future reduction in rates.
•We evaluated Mississippi Power's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP Atlanta, Georgia February 16, 2022
We have served as Mississippi Power's auditor since 2002.
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STATEMENTS OF INCOME For the Years Ended December 31, 2021, 2020, and 2019 Mississippi Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Revenues:
Retail revenues $ 875 $ 821 $ 877
Wholesale revenues, non-affiliates 230 215 237
Wholesale revenues, affiliates 188 111 132 Other revenues 29 25 18 Total operating revenues 1,322 1,172 1,264 Operating Expenses: Fuel 470 350 407 Purchased power 26 22 20 Other operations and maintenance 313 284 307 Depreciation and amortization 180 183 192 Taxes other than income taxes 128 124 113 Total operating expenses 1,117 963 1,039 Operating Income 205 209 225 Other Income and (Expense):
Interest expense, net of amounts capitalized (60) (60) (69) Other income (expense), net
35 17 13
Total other income and (expense) (25) (43)
(56)
Earnings Before Income Taxes 180 166 169 Income taxes 21 14 30 Net Income $ 159 $ 152 $ 139
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2021, 2020, and 2019 Mississippi Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Net Income $ 159 $ 152 $ 139
Other comprehensive income:
Qualifying hedges:
Reclassification adjustment for amounts included in net income,
net of tax of $-, $-, and $-, respectively 1 1 1 Total other comprehensive income 1 1 1 Comprehensive Income $ 160 $ 153 $ 140
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2021, 2020, and 2019 Mississippi Power Company 2021 Annual Report
2021 2020 2019
(in millions)
Operating Activities:
Net income $ 159 $ 152 $ 139
Adjustments to reconcile net income
to net cash provided from operating activities - Depreciation and amortization, total
213 191 197
Deferred income taxes (4) (4) 37
Pension and postretirement funding -
- (54)
Settlement of asset retirement obligations (24)
(22) (35)
Other, net (33) (1) 35 Changes in certain current assets and liabilities - -Receivables 9 (7) 6 -Prepaid income taxes 3 (3) 12 -Other current assets (9) (28) (8) -Accounts payable (35) 20 3 -Accrued taxes 6 10 11 -Over recovered regulatory clause revenues (34)
5 16
-Other current liabilities (5) (15) (20) Net cash provided from operating activities 246 298 339 Investing Activities: Property additions (213) (274) (202) Payments pursuant to LTSAs (29) (28) (23) Contributions in aid of construction 15 - - Other investing activities (30) (21) (38) Net cash used for investing activities (257) (323) (263) Financing Activities: Increase (decrease) in notes payable, net (25) 25 - Proceeds - Senior notes 525 - - Short-term borrowings - 40 - Pollution control revenue bonds - 34 43 Other long-term debt - 100 - Redemptions - Senior notes - (275) (25) Short-term borrowings - (40) - Pollution control revenue bonds - (41) - Other revenue bonds (320) - - Other long-term debt (100) - - Capital contributions from parent company 120 85 51 Return of capital to parent company -
(74) (150)
Payment of common stock dividends (157) (74) - Other financing activities (10) (2) (2) Net cash provided from (used for) financing activities 33 (222) (83) Net Change in Cash, Cash Equivalents, and Restricted Cash 22 (247) (7) Cash, Cash Equivalents, and Restricted Cash at Beginning of Year 39 286 293 Cash, Cash Equivalents, and Restricted Cash at End of Year $ 61 $ 39 $ 286 Supplemental Cash Flow Information: Cash paid (received) during the period for - Interest (net of $-, $-, and $(1) capitalized, respectively) $ 58 $ 63 $ 71 Income taxes, net 16
28 (27)
Noncash transactions - Accrued property additions at year-end 25
34 35
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Mississippi Power Company 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 61 $ 39
Receivables -
Customer accounts 37 34
Unbilled revenues 34 38
Affiliated 29 32
Other accounts and notes 28 32
Fossil fuel stock 28 24
Materials and supplies 70 65
Other regulatory assets 54 60
Other current assets 41 20
Total current assets 382 344
Property, Plant, and Equipment:
In service 5,106 5,011
Less: Accumulated provision for depreciation 1,591 1,545
Plant in service, net of depreciation 3,515 3,466
Construction work in progress 127 146
Total property, plant, and equipment 3,642 3,612
Other Property and Investments 179 151
Deferred Charges and Other Assets:
Deferred charges related to income taxes 31 32
Prepaid pension costs 79 -
Regulatory assets - asset retirement obligations 232 201
Other regulatory assets, deferred 317 388
Accumulated deferred income taxes 118 129
Other deferred charges and assets 100 55
Total deferred charges and other assets 877 805
Total Assets $ 5,080 $ 4,912
The accompanying notes are an integral part of these financial statements.
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BALANCE SHEETS
At December 31, 2021 and 2020
Mississippi Power Company 2021 Annual Report
Liabilities and Stockholder's Equity 2021 2020
(in millions)
Current Liabilities:
Securities due within one year $ 1 $ 406
Notes payable - 25
Accounts payable -
Affiliated 81 63
Other 47 109
Accrued taxes 120 114
Accrued interest 16 15
Accrued compensation 36 34
Asset retirement obligations 30 27
Over recovered regulatory clause liabilities - 34
Other regulatory liabilities 59 49
Other current liabilities 49 40
Total current liabilities 439 916
Long-Term Debt 1,510 1,013
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 464 447
Deferred credits related to income taxes 269
287
Employee benefit obligations 88
113
Asset retirement obligations, deferred 160
150
Other cost of removal obligations 195
194
Other regulatory liabilities, deferred 64
15
Other deferred credits and liabilities 24
35
Total deferred credits and other liabilities 1,264
1,241
Total Liabilities 3,213
3,170
Common Stockholder's Equity: Common stock, without par value (Authorized and outstanding - 1 million shares) 38 38 Paid-in capital 4,582 4,460 Accumulated deficit (2,753) (2,754) Accumulated other comprehensive loss -
(2)
Total common stockholder's equity (See accompanying statements) 1,867
1,742
Total Liabilities and Stockholder's Equity $ 5,080 $ 4,912 Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these financial statements.
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STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2021, 2020, and 2019 Mississippi Power Company 2021 Annual Report
Retained Earnings Accumulated Other
Number of Common Common Paid-In (Accumulated Comprehensive
Shares Issued Stock Capital Deficit) Income (Loss) Total
(in millions)
Balance at December 31, 2018 1 $ 38 $ 4,546 $ (2,971) $ (4) $ 1,609
Net income - - - 139 - 139
Return of capital to parent
company - - (150) - - (150)
Capital contributions from
parent company - - 53 - - 53
Other comprehensive income - - - - 1 1
Balance at December 31, 2019 1 38 4,449 (2,832) (3) 1,652
Net income - - - 152 - 152
Return of capital to parent
company - - (74) - - (74)
Capital contributions from
parent company - - 86 - - 86
Other comprehensive income - - - - 1 1
Cash dividends on common stock - - - (74) - (74)
Other - - (1) - - (1)
Balance at December 31, 2020 1 38 4,460 (2,754) (2) 1,742
Net income - - - 159 - 159
Capital contributions from
parent company - - 122 - - 122
Other comprehensive income - - - - 1 1
Cash dividends on common stock - - - (157) - (157)
Other - - - (1) 1 -
Balance at December 31, 2021 1 $ 38 $ 4,582 $ (2,753) $ - $ 1,867
The accompanying notes are an integral part of these financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Power Company and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Power Company and subsidiary companies (Southern Power) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Power as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Southern Power's management. Our responsibility is to express an opinion on Southern Power's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Power's internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which is relates.
Income/Loss Allocation to Noncontrolling Interests - Refer to Notes 1 and 7 to the financial statements
Critical Audit Matter Description
Southern Power has entered into a number of tax equity partnership arrangements,
wherein they agree to sell 100% of a class of membership interests (e.g. Class
A) in an entity to a noncontrolling investor in exchange for cash contributions,
while retaining control of the entity through a separate class of membership
interests (e.g. Class B). The agreements for these partnerships give different
rights and priorities to their owners in terms of cash distributions, tax
attribute allocations, and partnership income or loss allocations. These
provisions make the conventional equity method of accounting where an investor
applies its "percentage ownership interest" to the investee's net income under
generally accepted accounting principles to determine the investor's share of
earnings or losses difficult to apply. Therefore, Southern Power uses the
Hypothetical Liquidation at Book Value (HLBV) accounting method to account for
these partnership arrangements. The HLBV accounting method calculates each
partner's share of income or loss based on the change in net equity the partner
can legally claim at the end of the reporting period compared to the beginning
of the reporting period. The application of the HLBV accounting method by
Southern Power required significant consideration of the allocations between
Southern Power and the noncontrolling investors over the life of the agreement
and the liquidation provisions of the agreement to determine the appropriate
allocation of income or loss between the parties.
The determination of the appropriate amount of allocated partnership income or
loss to noncontrolling interests using the HLBV accounting method required
increased audit effort and specialized skill and knowledge, including evaluation
of the terms of the agreement and consideration of the appropriateness of the
HLBV model based on the provisions of the agreement.
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How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures included the following, among others:
•For agreements that result in potentially material allocations of partnership income or loss, we read the agreements to understand the liquidation provisions and the provisions governing the allocation of benefits. •We evaluated the HLBV models utilized by management to determine whether the models accurately reflect the allocation of income or loss and tax attributes in accordance with the liquidation provisions and allocation terms defined in the agreements, as well as whether the inputs in the models are accurate and complete. /s/ Deloitte & Touche LLP Atlanta, Georgia February 16, 2022
We have served as Southern Power's auditor since 2002.
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CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2021, 2020, and 2019 Southern Power Company and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Operating Revenues:
Wholesale revenues, non-affiliates $ 1,671 $ 1,355 $ 1,528
Wholesale revenues, affiliates 515 364 398
Other revenues 30 14 12
Total operating revenues 2,216 1,733 1,938
Operating Expenses:
Fuel 802 470 577
Purchased power 139 74 108
Other operations and maintenance 423 353 362
Depreciation and amortization 517 494 479
Taxes other than income taxes 45 39 40
Loss on sales-type leases 40 - -
Gain on dispositions, net (41) (39) (23)
Total operating expenses 1,925 1,391 1,543
Operating Income 291 342 395
Other Income and (Expense):
Interest expense, net of amounts capitalized (147) (151) (169)
Other income (expense), net 10 19
47
Total other income and (expense) (137) (132) (122) Earnings Before Income Taxes 154 210 273 Income taxes (benefit) (13) 3 (56) Net Income 167 207 329
Net loss attributable to noncontrolling interests (99) (31)
(10)
Net Income Attributable to Southern Power $ 266 $ 238
$ 339
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2021, 2020, and 2019 Southern Power Company and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Net Income $ 167 $ 207 $ 329
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $(22), $12, and
$(22), respectively (67) 33 (66)
Reclassification adjustment for amounts included in net income,
net of tax of $30, $(22), and $14, respectively 89 (65) 41 Pension and other postretirement benefit plans: Benefit plan net gain (loss), net of tax of $5, $(4), and $(6), respectively 16 (12) (17)
Reclassification adjustment for amounts included in net income,
net of tax of $1, $1, and $-, respectively 2 2 - Total other comprehensive income (loss) 40 (42) (42) Comprehensive loss attributable to noncontrolling interests (99) (31) (10)
Comprehensive Income Attributable to Southern Power $ 306 $ 196 $ 297
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2021, 2020, and 2019 Southern Power Company and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Operating Activities:
Net income $ 167 $ 207 $ 329
Adjustments to reconcile net income
to net cash provided from operating activities - Depreciation and amortization, total
542 519 505
Deferred income taxes 55 (25) (74)
Utilization of federal investment tax credits 288 340 734
Amortization of investment tax credits (58) (59) (151)
Income taxes receivable, non-current 5 (20) 25
Pension and postretirement funding - - (24)
Gain on dispositions, net (41) (39) (24)
Loss on sales-type leases 40 - -
Other, net (6) (5) (6)
Changes in certain current assets and liabilities -
-Receivables (44) (4) 72
-Prepaid income taxes (16) 20 39
-Other current assets (14) (30) (8)
-Accrued taxes (6) 11 6
-Other current liabilities 39 (14) (38)
Net cash provided from operating activities 951 901 1,385
Investing Activities:
Business acquisitions, net of cash acquired (345) (81) (50)
Property additions (396) (223) (489)
Change in construction payables (15) 31 7
Investment in unconsolidated subsidiaries - - (116)
Proceeds from dispositions 24 666 572
Payments pursuant to LTSAs (82) (76) (104)
Other investing activities 11 57 13
Net cash provided from (used for) investing activities (803) 374 (167)
Financing Activities:
Increase (decrease) in notes payable, net 36 (274) 449
Proceeds -
Senior notes 400 - -
Short-term borrowings - - 100
Redemptions -
Senior notes (300) (825) (600)
Short-term borrowings - (100) (100)
Capital contributions from parent company 8 6 64
Return of capital to parent company (271) - (755)
Capital contributions from noncontrolling interests 501 363 196
Distributions to noncontrolling interests (351) (271) (256)
Purchase of membership interests from noncontrolling interests
- (60) -
Payment of common stock dividends (204) (201) (206)
Other financing activities (14) (10) (12)
Net cash used for financing activities (195) (1,372) (1,120)
Net Change in Cash, Cash Equivalents, and Restricted Cash (47)
(97) 98
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
182 279 181
Cash, Cash Equivalents, and Restricted Cash at End of Year $ 135
$ 182 $ 279
Supplemental Cash Flow Information:
Cash paid (received) during the period for -
Interest (net of $6, $11, and $15 capitalized, respectively) $ 140 $ 147 $ 167
Income taxes, net (275) (283) (664)
Noncash transactions -
Accrued property additions at year-end 72 89 57
Contributions from noncontrolling interests 89 12 80
Contributions of wind turbine equipment 82 17 26
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Power Company and Subsidiary Companies 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 107 $ 182
Receivables -
Customer accounts 139 125
Affiliated 51 37
Other 29 27
Materials and supplies 106 157
Prepaid income taxes 27 11
Other current assets 46 36
Total current assets 505 575
Property, Plant, and Equipment:
In service 14,585 13,904
Less: Accumulated provision for depreciation 3,241 2,842
Plant in service, net of depreciation 11,344 11,062
Construction work in progress 45 127
Total property, plant, and equipment 11,389 11,189
Other Property and Investments:
Intangible assets, net of amortization of $109 and $89, respectively
282 302
Equity investments in unconsolidated subsidiaries 86 19
Net investment in sales-type leases 161 -
Total other property and investments 529 321
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization 479 415
Prepaid LTSAs 210 155
Accumulated deferred income taxes - 262
Income taxes receivable, non-current 20 25
Other deferred charges and assets 258 293
Total deferred charges and other assets 967 1,150
Total Assets $ 13,390 $ 13,235
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Power Company and Subsidiary Companies 2021 Annual Report
Liabilities and Stockholders' Equity 2021 2020
(in millions)
Current Liabilities: Securities due within one year $ 679 $ 299 Notes payable 211 175 Accounts payable - Affiliated 92 65 Other 85 92 Accrued taxes 14 30 Accrued interest 32 32 Other current liabilities 140 132 Total current liabilities 1,253 825 Long-Term Debt 3,009 3,393 Deferred Credits and Other Liabilities: Accumulated deferred income taxes 215 123 Accumulated deferred ITCs 1,614 1,672 Operating lease obligations 497 426 Other deferred credits and liabilities 204
165
Total deferred credits and other liabilities 2,530
2,386
Total Liabilities 6,792
6,604
Common Stockholder's Equity: Common stock, par value $0.01 per share
(Authorized - 1.0 million shares; Outstanding - 1,000 shares) -
-
Paid-in capital 638 914
Retained earnings 1,585 1,522
Accumulated other comprehensive loss (27) (67)
Total common stockholder's equity 2,196
2,369
Noncontrolling Interests 4,402
4,262
Total Stockholders' Equity (See accompanying statements) 6,598
6,631
Total Liabilities and Stockholders' Equity $ 13,390 $ 13,235 Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY For the Years Ended December 31, 2021, 2020, and 2019 Southern Power Company and Subsidiary Companies 2021 Annual Report
Number of
Common Accumulated Other
Shares Paid-In Retained Comprehensive Total Common Noncontrolling
Issued Common Stock Capital Earnings Income (Loss) Stockholder's Equity Interests Total
(in millions)
Balance at December 31, 2018 - $ - $ 1,600 $ 1,352 $ 16 $ 2,968 $ 4,316 $ 7,284
Net income (loss) - - - 339 - 339 (10) 329
Return of capital to parent
company - - (755) - - (755) - (755)
Capital contributions from parent
company - - 64 - - 64 - 64 Other comprehensive income (loss) - - - - (42) (42) - (42)
Cash dividends on common
stock - - - (206) - (206) - (206)
Capital contributions from
noncontrolling interests - - - - - - 276 276
Distributions to noncontrolling
interests - - - - - - (327) (327) Other - - - - - - (1) (1) Balance at December 31, 2019 - - 909 1,485 (26) 2,368 4,254 6,622 Net income (loss) - - - 238 - 238 (31) 207
Capital contributions from parent
company - - 2 - - 2 - 2 Other comprehensive income (loss) - - - - (42) (42) - (42)
Cash dividends on common
stock - - - (201) - (201) - (201)
Capital contributions from
noncontrolling interests - - - - - - 307 307
Distributions to noncontrolling
interests - - - - - - (271) (271)
Purchase of membership interests
from noncontrolling interests - - 5 - - 5 (65) (60) Sale of noncontrolling interests(*) - - (2) - - (2) 67 65 Other - - - - 1 1 1 2 Balance at December 31, 2020 - - 914 1,522 (67) 2,369 4,262 6,631 Net income (loss) - - - 266 - 266 (99) 167
Return of capital to parent
company - - (271) - - (271) - (271)
Capital contributions from parent
company - - 10 - - 10 - 10 Other comprehensive income - - - - 40 40 - 40
Cash dividends on common
stock - - - (204) - (204) - (204)
Capital contributions from
noncontrolling interests - - - - - - 590 590
Distributions to noncontrolling
interests - - - - - - (351) (351) Other - - (15) 1 - (14) - (14) Balance at December 31, 2021 - $ - $
638 $ 1,585 $ (27) $ 2,196 $ 4,402 $ 6,598
(*)See Note 15 under "Southern Power" for additional information.
The accompanying notes are an integral part of these consolidated financial statements.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholder and the Board of Directors of Southern Company Gas and Subsidiary Companies
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Company Gas and subsidiary companies (Southern Company Gas) (a wholly-owned subsidiary of The Southern Company) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Southern Company Gas as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America. We did not audit the financial statements of Southern Natural Gas Company, L.L.C. (SNG), Southern Company Gas' investment which is accounted for by the use of the equity method. The accompanying consolidated financial statements of Southern Company Gas include its equity investment in SNG of $1,129 million and $1,167 million as of December 31, 2021 and December 31, 2020, respectively, and its earnings from its equity method investment in SNG of $127 million, $129 million, and $141 million for the years ended December 31, 2021, 2020, and 2019, respectively. Those statements were audited by other auditors whose reports (which express unqualified opinions on SNG's financial statements and contain an emphasis of matter paragraph calling attention to SNG's significant transactions with related parties) have been furnished to us, and our opinion, insofar as it relates to the amounts included for SNG, is based solely on the reports of the other auditors. Basis for Opinion These financial statements are the responsibility of Southern Company Gas' management. Our responsibility is to express an opinion on Southern Company Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Southern Company Gas in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Southern Company Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Southern Company Gas' internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the Audit Committee of Southern Company's Board of Directors and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Impact of Rate Regulation on the Financial Statements - Refer to Note 1 (Summary of Significant Accounting Policies - Regulatory Assets and Liabilities) and Note 2 (Regulatory Matters - Southern Company Gas) to the financial statements
Critical Audit Matter Description
Southern Company Gas' natural gas distribution utilities (the "regulated utility
subsidiaries"), which represent approximately 84% of Southern Company Gas'
consolidated revenues, are subject to rate regulation in Georgia, Illinois,
Tennessee, and Virginia by their respective state Public Service Commission or
other applicable state regulatory agencies (collectively, the "Commissions").
Management has determined it meets the requirements under accounting principles
generally accepted in the United States of America to prepare its financial
statements applying the specialized rules to account for the effects of
regulation. Accounting for the economics of rate regulation impacts multiple
financial statement line items and disclosures, including, but not limited to,
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property, plant, and equipment; other regulatory assets; other regulatory
liabilities; other cost of removal obligations; deferred charges and credits
related to income taxes; operating revenues; other operations and maintenance
expenses; and depreciation and amortization.
The Commissions set the rates the regulated utility subsidiaries are permitted
to charge customers. Rates are determined and approved in regulatory proceedings
based on an analysis of the applicable regulated utility subsidiary's costs to
provide utility service and a return on, and recovery of, its investment in the
utility business. Current and future regulatory decisions can have an impact on
the recovery of costs, the rate of return earned on investments, and the timing
and amount of assets to be recovered by rates. The Commissions' regulation of
rates is premised on the full recovery of prudently incurred costs and a
reasonable rate of return on invested capital. While Southern Company Gas'
regulated utility subsidiaries expect to recover costs from customers through
regulated rates, there is a risk that the Commissions will not approve: (1) full
recovery of the costs of providing utility service, or (2) full recovery of all
amounts invested in the utility business and a reasonable return on that
investment.
We identified the impact of rate regulation as a critical audit matter due to
the significant judgments made by management to support its assertions about
impacted account balances and disclosures and the high degree of subjectivity
involved in assessing the impact of future regulatory orders on the financial
statements. Management judgments include assessing the likelihood of (1)
recovery in future rates of incurred costs, (2) a disallowance of part of the
cost of recently completed plant or plant under construction, and/or (3) a
refund to customers. Given that management's accounting judgments are based on
assumptions about the outcome of future decisions by the Commissions, auditing
these judgments required specialized knowledge of accounting for rate regulation
and the rate setting process due to its inherent complexities and significant
auditor judgment to evaluate management estimates and the subjectivity of audit
evidence.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•We tested the effectiveness of management's controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management's controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates. •We read relevant regulatory orders issued by the Commissions for Southern Company Gas' regulated utility subsidiaries in Georgia, Illinois, Tennessee, and Virginia, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness. •For regulatory matters in process, we inspected filings with the Commissions by the regulated utility subsidiaries and other interested parties that may impact the regulated utility subsidiaries' future rates for any evidence that might contradict management's assertions.
•We evaluated regulatory filings for any evidence that intervenors are challenging full recovery of the cost of any capital projects. We tested selected costs included in the capitalized project costs for completeness and accuracy.
•We obtained representation from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities to assess management's assertion that amounts are probable of recovery or a future reduction in rates.
•We evaluated Southern Company Gas' disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
/s/ Deloitte & Touche LLP Atlanta, Georgia February 16, 2022
We have served as Southern Company Gas' auditor since 2016.
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Report of Independent Registered Public Accounting Firm
Board of Directors and Members Southern Natural Gas Company, L.L.C. Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Southern Natural Gas Company, LLC (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of income, members' equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on the Company's
consolidated financial statements based on our audits. We are a public
accounting firm registered with the Public Company Accounting Oversight Board
(United States) ("PCAOB") and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in
accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement, whether due to error or fraud. The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. As part of our audits we are required to
obtain an understanding of internal control over financial reporting but not for
the purpose of expressing an opinion on the effectiveness of the Company's
internal control over financial reporting. Accordingly, we express no such
opinion.
Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures
included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated
financial statements. We believe that our audits provide a reasonable basis for
our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the
current period audit of the consolidated financial statements that was
communicated or required to be communicated to the audit committee and that: (1)
relates to accounts or disclosures that are material to the consolidated
financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of the critical audit matter does not alter
in any way our opinion on the consolidated financial statements, taken as a
whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or
disclosures to which it relates.
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Postretirement Benefit Obligation
At December 31, 2021, the Company's postretirement benefit obligation was $19 million and the Company's plan assets were $73 million, resulting in a net asset position of $54 million. As described in Note 5 of the consolidated financial statements, the postretirement benefit obligation is primarily based on actuarial calculations, which include various significant assumptions. We identified the Company's estimate of the postretirement benefit obligation as a critical audit matter. Auditing the postretirement benefit obligation required complex auditor judgment due to the highly judgmental nature of the actuarial assumptions used in the calculation, which include the discount rate and the expected return on plan assets. These assumptions had a significant effect on the postretirement benefit obligation calculation.
The primary procedures we performed to address this critical audit matter included:
•Comparing the actuarial assumptions used by management with historical trends and evaluating the change in the postretirement benefit obligation from prior year due to changes in assumptions.
•Evaluating the appropriateness of management's methodology for determining the discount rate that reflects the maturity and duration of the benefit payments.
•Evaluating the expected return on plan assets by assessing whether management's assumptions were consistent with a range of returns for a portfolio of comparative investments that was determined based on publicly available information.
Emphasis of Matter - Significant Transactions with Related Parties
As discussed in Note 6 to the consolidated financial statements, the Company has entered into significant transactions with related parties.
/s/ BDO USA, LLP
We have served as the Company's auditor since 2018.
Houston, Texas
February 7, 2022
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CONSOLIDATED STATEMENTS OF INCOME For the Years Ended December 31, 2021, 2020, and 2019 Southern Company Gas and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Operating Revenues:Natural gas revenues (includes revenue taxes of
$122, $107, and $117, respectively) $ 4,369 $3,431 $ 3,793
Alternative revenue programs 11
3 (1)
Total operating revenues 4,380 3,434 3,792
Operating Expenses:
Cost of natural gas 1,619 972 1,319
Other operations and maintenance 1,072 966 888
Depreciation and amortization 536 500 487
Taxes other than income taxes 225 206 213
Impairment charges - - 115
Gain on dispositions, net (127) (22) -
Total operating expenses 3,325 2,622 3,022
Operating Income 1,055 812 770
Other Income and (Expense):
Earnings from equity method investments 50 141 157
Interest expense, net of amounts capitalized (238) (231) (232)
Other income (expense), net (53) 41 20
Total other income and (expense) (241) (49) (55)
Earnings Before Income Taxes 814
763 715
Income taxes 275 173 130
Net Income $ 539 $ 590 $ 585
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, 2021, 2020, and 2019 Southern Company Gas and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Net Income $ 539 $ 590 $ 585
Other comprehensive income (loss):
Qualifying hedges:
Changes in fair value, net of tax of $5, $(8), and
$(2), respectively 17 (21) (5)
Reclassification adjustment for amounts included in net income,
net of tax of $(5), $3, and $-, respectively (11) 7 2 Pension and other postretirement benefit plans: Benefit plan net gain (loss), net of tax of $17, $(3), and $(14), respectively 40 (15) (16) Total other comprehensive income (loss) 46 (29) (19) Comprehensive Income $ 585 $ 561 $ 566
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 2021, 2020, and 2019 Southern Company Gas and Subsidiary Companies 2021 Annual Report
2021 2020 2019
(in millions)
Operating Activities:
Consolidated net income $ 539 $ 590 $ 585
Adjustments to reconcile net income to net cash
provided from operating activities -
Depreciation and amortization, total 536 500 487
Deferred income taxes 259 56 213
Pension and postretirement funding - - (145)
Impairment charges 84 - 115
Gain on dispositions, net (127) (22) -
Mark-to-market adjustments 194 61 (56)
Natural gas cost under recovery - long-term (207) - -
Other, net (30) (29) (55)
Changes in certain current assets and liabilities -
-Receivables (143) (93) 467
-Natural gas for sale 8 18 44
-Prepaid income taxes (82) 19 40
-Natural gas cost under recovery (266) - -
-Other current assets (116) (10) 31
-Accounts payable 40 103 (520)
-Accrued taxes 45 13 (69)
-Accrued compensation 23 7 1
-Other current liabilities (94) (6) (71)
Net cash provided from operating activities 663 1,207 1,067
Investing Activities:
Property additions (1,421) (1,471) (1,408)
Cost of removal, net of salvage (106) (100) (82)
Change in construction payables, net (29) 20 24
Investments in unconsolidated subsidiaries (5) (79) (31)
Returned investment in unconsolidated subsidiaries 22 13 67
Proceeds from dispositions 150 211 32
Other investing activities 10 (11) 12
Net cash used for investing activities (1,379) (1,417) (1,386)
Financing Activities:
Increase (decrease) in notes payable, net 585 (326) -
Proceeds -
Senior notes 450 500 -
Short-term borrowings 300 - -
First mortgage bonds 200 325 300
Redemptions and repurchases -
Senior notes (300) - (300)
Medium-term notes (30) - -
First mortgage bonds - - (50)
Capital contributions from parent company 72 216 821
Payment of common stock dividends (530) (533) (471)
Other financing activities (2) (2) (2)
Net cash provided from financing activities 745 180 298
Net Change in Cash, Cash Equivalents, and Restricted Cash 29 (30) (21)
Cash, Cash Equivalents, and Restricted Cash at Beginning of Year
19 49 70
Cash, Cash Equivalents, and Restricted Cash at End of Year
$ 48 $ 19 $ 49
Supplemental Cash Flow Information:
Cash paid (received) during the period for -
Interest (net of $8, $7, and $6 capitalized,
respectively) $ 244 $ 232 $ 251
Income taxes, net 57 25 (41)
Noncash transactions - Accrued property additions at year-end
113 142 122
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company Gas and Subsidiary Companies 2021 Annual Report
Assets 2021 2020
(in millions)
Current Assets:
Cash and cash equivalents $ 45 $ 17
Receivables -
Energy marketing - 516
Customer accounts 462 353
Unbilled revenues 278 219
Other accounts and notes 49 55
Accumulated provision for uncollectible accounts (39) (40)
Natural gas for sale 362 460
Prepaid expenses 114 48
Assets from risk management activities, net of collateral 33 118
Natural gas cost under recovery 266 -
Other regulatory assets 136 102
Other current assets 49 38
Total current assets 1,755 1,886
Property, Plant, and Equipment:
In service 18,880 17,611
Less: Accumulated depreciation 5,067 4,821
Plant in service, net of depreciation 13,813 12,790
Construction work in progress 684 648
Total property, plant, and equipment 14,497 13,438
Other Property and Investments:
Goodwill 5,015 5,015
Equity investments in unconsolidated subsidiaries 1,173 1,290
Other intangible assets, net of amortization of $145 and $195, respectively
37 51
Miscellaneous property and investments 19 19
Total other property and investments 6,244 6,375
Deferred Charges and Other Assets:
Operating lease right-of-use assets, net of amortization 70 81
Prepaid pension costs 175 70
Other regulatory assets, deferred 689 615
Other deferred charges and assets 130 165
Total deferred charges and other assets 1,064 931
Total Assets $ 23,560 $ 22,630
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED BALANCE SHEETS
At December 31, 2021 and 2020
Southern Company Gas and Subsidiary Companies 2021 Annual Report
Liabilities and Stockholder's Equity 2021 2020
(in millions)
Current Liabilities:
Securities due within one year $ 47 $ 333
Notes payable 1,209 324
Energy marketing trade payables - 494
Accounts payable -
Affiliated 58 56
Other 361 373
Customer deposits 95 90
Accrued taxes 124 83
Accrued interest 59 58
Accrued compensation 110 106
Other regulatory liabilities 8 122
Other current liabilities 155 150
Total current liabilities 2,226 2,189
Long-term Debt 6,855 6,293
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,555 1,265
Deferred credits related to income taxes 816 847
Employee benefit obligations 176 283
Operating lease obligations 59 67
Other cost of removal obligations 1,683 1,649
Accrued environmental remediation 197 216
Other deferred credits and liabilities 77 54
Total deferred credits and other liabilities 4,563 4,381
Total Liabilities 13,644 12,863
Common Stockholder's Equity:
Common stock, par value $0.01 per share
(Authorized - 100 million shares; Outstanding - 100 shares) Paid-in capital
10,024 9,930
Accumulated deficit (132) (141)
Accumulated other comprehensive income (loss) 24 (22)
Total common stockholder's equity (See accompanying statements) 9,916 9,767 Total Liabilities and Stockholder's Equity
$ 23,560 $ 22,630
Commitments and Contingent Matters (See notes)
The accompanying notes are an integral part of these consolidated financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY For the Years Ended December 31, 2021, 2020, and 2019 Southern Company Gas and Subsidiary Companies 2021 Annual Report
Accumulated
Number of Retained Earnings Other
Common Shares Paid-In (Accumulated Comprehensive Income
Issued Common Stock Capital Deficit) (Loss) Total
(in millions)
Balance at December 31, 2018 - $ - $ 8,856 $ (312) $ 26 $ 8,570
Net income - - - 585 - 585
Capital contributions from
parent company - - 841 - - 841
Other comprehensive income
(loss) - - - - (19) (19)
Cash dividends on common stock - - - (471) - (471)
Balance at December 31, 2019 - - 9,697 (198) 7 9,506
Net income - - - 590 - 590
Capital contributions from
parent company - - 233 - - 233
Other comprehensive income
(loss) - - - - (29) (29)
Cash dividends on common stock - - - (533) - (533)
Balance at December 31, 2020 - - 9,930 (141) (22) 9,767
Net income - - - 539 - 539
Capital contributions from
parent company - - 94 - - 94
Other comprehensive income - - - - 46 46
Cash dividends on common stock - - - (530) - (530)
Balance at December 31, 2021 - $ - $ 10,024 $ (132) $ 24 $ 9,916
The accompanying notes are an integral part of these consolidated financial statements.
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COMBINED NOTES TO FINANCIAL STATEMENTS
Southern Company and Subsidiary Companies 2021 Annual Report
Notes to the Financial Statements
for
The Southern Company and Subsidiary Companies
Alabama Power Company
Georgia Power Company
Mississippi Power Company
Southern Power Company and Subsidiary Companies
Southern Company Gas and Subsidiary Companies
Index to the Combined Notes to Financial Statements
Note Page
1 Summary of Significant Accounting Policies II- 128
2 Regulatory Matters II- 143
3 Contingencies, Commitments, and Guarantees II- 165
4 Revenue from Contracts with Customers II- 171
5 Property, Plant, and Equipment II- 174
6 Asset Retirement Obligations II- 179
7 Consolidated Entities and Equity Method Investments II- 182
8 Financing II- 186
9 Leases II- 194
10 Income Taxes II- 204
11 Retirement Benefits II- 211
12 Stock Compensation II- 238
13 Fair Value Measurements II- 241
14 Derivatives II- 249
15 Acquisitions and Dispositions II- 260
16 Segment and Related Information II- 264
Index to Applicable Notes to Financial Statements by Registrant
The following notes to the financial statements are a combined presentation;
however, information contained herein relating to any individual Registrant is
filed by such Registrant on its own behalf and each Registrant makes no
representation as to information related to the other Registrants. The list
below indicates the Registrants to which each note applies.
Registrant Applicable Notes
Southern Company 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16
Alabama Power 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15
Georgia Power 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14
Mississippi Power 1, 2, 3, 4, 5, 6, 8, 9, 10, 11, 12, 13, 14
Southern Power 1, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15
Southern Company Gas 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16
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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Southern Company is the parent company of three traditional electric operating companies, as well as Southern Power, Southern Company Gas, SCS, Southern Linc, Southern Holdings, Southern Nuclear, PowerSecure, and other direct and indirect subsidiaries. The traditional electric operating companies - Alabama Power, Georgia Power, and Mississippi Power - are vertically integrated utilities providing electric service in three Southeastern states. Southern Power develops, constructs, acquires, owns, and manages power generation assets, including renewable energy projects, and sells electricity at market-based rates in the wholesale market. Southern Company Gas distributes natural gas through natural gas distribution utilities, including Nicor Gas (Illinois), Atlanta Gas Light (Georgia), Virginia Natural Gas, and Chattanooga Gas (Tennessee). Southern Company Gas is also involved in several other complementary businesses including gas pipeline investments and gas marketing services. Prior to the sale of Sequent on July 1, 2021, these businesses also included wholesale gas services. SCS, the system service company, provides, at cost, specialized services to Southern Company and its subsidiary companies. Southern Linc provides digital wireless communications for use by Southern Company and its subsidiary companies and also markets these services to the public and provides fiber optics services within the Southeast. Southern Holdings is an intermediate holding company subsidiary. Southern Nuclear operates and provides services to the Southern Company system's nuclear power plants, including Alabama Power's Plant Farley and Georgia Power's Plant Hatch and Plant Vogtle Units 1 and 2, and is currently managing construction and start-up of Plant Vogtle Units 3 and 4, which are co-owned by Georgia Power. PowerSecure develops distributed energy and resilience solutions and deploys microgrids for commercial, industrial, governmental, and utility customers. See Note 15 for information regarding the sale of Sequent. The Registrants' financial statements reflect investments in subsidiaries on a consolidated basis. Intercompany transactions have been eliminated in consolidation. The equity method is used for investments in entities in which a Registrant has significant influence but does not have control and for VIEs where a Registrant has an equity investment but is not the primary beneficiary. Southern Power has controlling ownership in certain legal entities for which the contractual provisions represent profit-sharing arrangements because the allocations of cash distributions and tax benefits are not based on fixed ownership percentages. For these arrangements, the noncontrolling interest is accounted for under a balance sheet approach utilizing the HLBV method. The HLBV method calculates each partner's share of income based on the change in net equity the partner can legally claim in a HLBV at the end of the period compared to the beginning of the period. See "Variable Interest Entities" herein and Note 7 for additional information. The traditional electric operating companies, Southern Power, certain subsidiaries of Southern Company Gas, and certain other subsidiaries are subject to regulation by the FERC, and the traditional electric operating companies and the natural gas distribution utilities are also subject to regulation by their respective state PSCs or other applicable state regulatory agencies. As such, the respective financial statements of the applicable Registrants reflect the effects of rate regulation in accordance with GAAP and comply with the accounting policies and practices prescribed by relevant state PSCs or other applicable state regulatory agencies. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates. Certain prior years' data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no impact on the Registrants' results of operations, financial position, or cash flows.
Recently Adopted Accounting Standards
In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848):
Facilitation of the Effects of Reference Rate Reform on Financial Reporting (ASU
2020-04) providing temporary guidance to ease the potential burden in accounting
for reference rate reform primarily resulting from the discontinuation of LIBOR,
which began phasing out on December 31, 2021. The amendments in ASU 2020-04 are
elective and apply to all entities that have contracts, hedging relationships,
and other transactions that reference LIBOR or another reference rate expected
to be discontinued. The new guidance (i) simplifies accounting analyses under
current GAAP for contract modifications; (ii) simplifies the assessment of hedge
effectiveness and allows hedging relationships affected by reference rate reform
to continue; and (iii) allows a one-time election to sell or transfer debt
securities classified as held to maturity that reference a rate affected by
reference rate reform. An entity may elect to apply the amendments prospectively
from March 12, 2020 through December 31, 2022 by accounting topic. The
Registrants have elected to apply the amendments to modifications of debt
arrangements that meet the scope of ASU 2020-04.
The Registrants currently reference LIBOR for certain debt and hedging
arrangements. In addition, certain provisions in PPAs at Southern Power include
references to LIBOR. Contract language has been, or is expected to be,
incorporated into each of these agreements to address the transition to an
alternative rate for agreements that will be in place at the transition date.
While no material impacts are expected from modifications to the arrangements
and effective hedging relationships are expected to
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continue, the Registrants will continue to evaluate the provisions of ASU 2020-04 and the impacts of transitioning to an alternative rate, and the ultimate outcome of the transition cannot be determined at this time. See Note 14 under "Interest Rate Derivatives" for additional information.
Affiliate Transactions
The traditional electric operating companies, Southern Power, and Southern
Company Gas have agreements with SCS under which certain of the following
services are rendered to them at direct or allocated cost: general executive and
advisory, general and design engineering, operations, purchasing, accounting,
finance, treasury, legal, tax, information technology, marketing, auditing,
insurance and pension administration, human resources, systems and procedures,
digital wireless communications, cellular tower space, and other services with
respect to business and operations, construction management, and Southern
Company power pool transactions. These costs are primarily included in other
operations and maintenance expenses or capitalized to property, plant, and
equipment. Costs for these services from SCS in 2021, 2020, and 2019 were as
follows:
Alabama Georgia Mississippi Southern
Power Power Power Power Southern Company Gas
(in millions)
2021 $ 504 $ 663 $ 120 $ 89 $ 239
2020 478 639 149 87 237
2019 527 704 118 90 183
Alabama Power and Georgia Power also have agreements with Southern Nuclear under
which Southern Nuclear renders the following nuclear-related services at cost:
general executive and advisory services; general operations, management, and
technical services; administrative services including procurement, accounting,
employee relations, systems, and procedures services; strategic planning and
budgeting services; other services with respect to business and operations; and,
for Georgia Power, construction management. These costs are primarily included
in other operations and maintenance expenses or capitalized to property, plant,
and equipment. Costs for these services in 2021, 2020, and 2019 amounted to $258
million, $262 million, and $256 million, respectively, for Alabama Power and
$906 million, $883 million, and $760 million, respectively, for Georgia Power.
See Note 2 under "Georgia Power - Nuclear Construction" for additional
information regarding Southern Nuclear's construction management of Plant Vogtle
Units 3 and 4 for Georgia Power.
Cost allocation methodologies used by SCS and Southern Nuclear prior to the
repeal of the Public Utility Holding Company Act of 1935, as amended, were
approved by the SEC. Subsequently, additional cost allocation methodologies have
been reported to the FERC and management believes they are reasonable. The FERC
permits services to be rendered at cost by system service companies.
Alabama Power's and Georgia Power's power purchases from affiliates through the
Southern Company power pool are included in purchased power, affiliates on their
respective statements of income. Mississippi Power's and Southern Power's power
purchases from affiliates through the Southern Company power pool are included
in purchased power on their respective statements of income and were as follows:
Mississippi Southern
Power Power
(in millions)
2021 $ 9 $ 15
2020 4 8
2019 3 14
Georgia Power has entered into several PPAs with Southern Power for capacity and
energy. Georgia Power's total expenses associated with these PPAs were $132
million, $141 million, and $177 million in 2021, 2020, and 2019, respectively.
Southern Power's total revenues from all PPAs with Georgia Power, included in
wholesale revenue affiliates on Southern Power's consolidated statements of
income, were $139 million, $139 million, and $174 million for 2021, 2020, and
2019, respectively. Included within these revenues were affiliate PPAs accounted
for as operating leases, which totaled $112 million, $115 million, and $116
million for 2021, 2020, and 2019, respectively. See Note 9 for additional
information.
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SCS (as agent for Alabama Power, Georgia Power, and Southern Power) and Southern
Company Gas have long-term interstate natural gas transportation agreements with
SNG that are governed by the terms and conditions of SNG's natural gas tariff
and are subject to FERC regulation. See Note 7 under "Southern Company Gas -
Equity Method Investments" for additional information. Transportation costs
under these agreements in 2021, 2020, and 2019 were as follows:
Alabama Georgia Southern
Power Power Power Southern Company Gas
(in millions)
2021 $ 14 $ 108 $ 31 $ 29
2020 15 108 29 29
2019 17 99 28 31
In 2018, SNG purchased the natural gas lateral pipeline serving Plant McDonough
Units 4 through 6 from Georgia Power at net book value, as approved by the
Georgia PSC. In 2020, SNG paid Georgia Power $142 million, which included $71
million contributed to SNG by Southern Company Gas for its proportionate share.
During the interim period, Georgia Power received a discounted shipping rate to
reflect the deferred consideration and SNG constructed an extension to the
pipeline.
SCS, as agent for the traditional electric operating companies and Southern
Power, has agreements with certain subsidiaries of Southern Company Gas to
purchase natural gas. Natural gas purchases made under these agreements were
immaterial for Alabama Power, Georgia Power, and Mississippi Power for all
periods presented and $18 million, $26 million, and $64 million for Southern
Power in 2021, 2020, and 2019, respectively.
Alabama Power and Mississippi Power jointly own Plant Greene County. The companies have an agreement under which Alabama Power operates Plant Greene County and Mississippi Power reimburses Alabama Power for its proportionate share of non-fuel operations and maintenance expenses, which totaled $10 million, $9 million, and $9 million in 2021, 2020, and 2019, respectively. See Note 5 under "Joint Ownership Agreements" for additional information.
Alabama Power and Georgia Power each have agreements with PowerSecure for equipment purchases and/or services related to utility infrastructure construction, distributed energy, and energy efficiency projects. Costs under these agreements were immaterial for all periods presented.
See Note 7 under "SEGCO" for information regarding Alabama Power's and Georgia Power's equity method investment in SEGCO and related affiliate purchased power costs, as well as Alabama Power's gas pipeline ownership agreement with SEGCO. Southern Power has several agreements with SCS for transmission services, which are billed to Southern Power based on the Southern Company Open Access Transmission Tariff as filed with the FERC. Transmission services purchased by Southern Power from SCS totaled $28 million, $15 million, and $15 million for 2021, 2020, and 2019, respectively, and were charged to other operations and maintenance expenses in Southern Power's consolidated statements of income. The traditional electric operating companies and Southern Power may jointly enter into various types of wholesale energy, natural gas, and certain other contracts, either directly or through SCS as agent. Each participating company may be jointly and severally liable for the obligations incurred under these agreements. See Note 14 under "Contingent Features" for additional information. Southern Power and the traditional electric operating companies generally settle amounts related to the above transactions on a monthly basis in the month following the performance of such services or the purchase or sale of electricity. See "Revenues - Southern Power" herein for additional information. The traditional electric operating companies, Southern Power, and Southern Company Gas provide incidental services to and receive such services from other Southern Company subsidiaries which are generally minor in duration and amount. Except as described herein, the traditional electric operating companies, Southern Power, and Southern Company Gas neither provided nor received any material services to or from affiliates in any year presented.
Regulatory Assets and Liabilities
The traditional electric operating companies and the natural gas distribution
utilities are subject to accounting requirements for the effects of rate
regulation. Regulatory assets represent probable future revenues associated with
certain costs that are expected to be recovered from customers through the
ratemaking process. Regulatory liabilities represent costs recovered that are
expected to be incurred in the future or probable future reductions in revenues
associated with amounts that are expected to be credited to customers through
the ratemaking process.
In the event that a portion of a traditional electric operating company's or a
natural gas distribution utility's operations is no longer subject to applicable
accounting rules for rate regulation, such company would be required to write
off to income or reclassify to
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AOCI related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the traditional electric operating company or the natural gas distribution utility would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 2 for additional information including details of regulatory assets and liabilities reflected in the balance sheets for Southern Company, the traditional electric operating companies, and Southern Company Gas. Revenues The Registrants generate revenues from a variety of sources which are accounted for under various revenue accounting guidance, including revenue from contracts with customers, lease, derivative, and regulatory accounting. See Notes 4, 9, and 14 for additional information.
Traditional Electric Operating Companies
The majority of the revenues of the traditional electric operating companies are generated from contracts with retail electric customers. These revenues, generated from the integrated service to deliver electricity when and if called upon by the customer, are recognized as a single performance obligation satisfied over time, at a tariff rate, and as electricity is delivered to the customer during the month. Unbilled revenues related to retail sales are accrued at the end of each fiscal period. Retail rates may include provisions to adjust revenues for fluctuations in fuel costs, fuel hedging, the energy component of purchased power costs, and certain other costs. Revenues are adjusted for differences between these actual costs and amounts billed in current regulated rates. Under or over recovered regulatory clause revenues are recorded in the balance sheets and are recovered from or returned to customers, respectively, through adjustments to the billing factors. See Note 2 for additional information regarding regulatory matters of the traditional electric operating companies. Wholesale capacity revenues from PPAs are recognized in amounts billable under the contract terms. Energy and other revenues are generally recognized as services are provided. The contracts for capacity and energy in a wholesale PPA have multiple performance obligations where the contract's total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, the traditional electric operating companies recognize revenue as the performance obligations are satisfied over time as electricity is delivered to the customer or as generation capacity is available to the customer. For both retail and wholesale revenues, the traditional electric operating companies have elected to recognize revenue for their sales of electricity and capacity using the invoice practical expedient as they generally have a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of the Registrants' performance obligation.
Southern Power
Southern Power sells capacity and energy at rates specified under contractual terms in long-term PPAs. These PPAs are accounted for as leases, non-derivatives, or normal sale derivatives. Capacity revenues from PPAs classified as operating leases are recognized on a straight-line basis over the term of the agreement. Energy revenues are recognized in the period the energy is delivered. Capacity revenues from PPAs classified as sales-type leases are recognized by accounting for interest income on the net investment in the lease. Southern Power's non-lease contracts commonly include capacity and energy which are considered separate performance obligations. In these contracts, the total transaction price is allocated to each performance obligation based on the standalone selling price. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Power recognizes revenue as the performance obligations are satisfied over time, as electricity is delivered to the customer or as generation capacity is made available to the customer. Southern Power generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Power's performance obligation.
When multiple contracts exist with the same counterparty, the revenues from each contract are accounted for as separate arrangements.
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Southern Power may also enter into contracts to sell short-term capacity in the wholesale electricity markets. These sales are generally classified as mark-to-market derivatives and net unrealized gains and losses on such contracts are recorded in wholesale revenues. See Note 14 and "Financial Instruments" herein for additional information.
Southern Company Gas
Gas Distribution Operations
Southern Company Gas records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the state regulatory agencies of the natural gas distribution utilities. Atlanta Gas Light operates in a deregulated natural gas market whereby Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. As required by the Georgia PSC, Atlanta Gas Light bills Marketers in equal monthly installments for each residential, commercial, and industrial end-use customer's distribution costs as well as for capacity costs utilizing a seasonal rate design for the calculation of each residential end-use customer's annual straight-fixed-variable charge, which reflects the historic volumetric usage pattern for the entire residential class. The majority of the revenues of Southern Company Gas are generated from contracts with natural gas distribution customers. Revenues from this integrated service to deliver gas when and if called upon by the customer are recognized as a single performance obligation satisfied over time and are recognized at a tariff rate as gas is delivered to the customer during the month. The standalone selling price is primarily determined by the price charged to customers for the specific goods or services transferred with the performance obligations. Generally, Southern Company Gas recognizes revenue as the performance obligations are satisfied over time as natural gas is delivered to the customer. The performance obligations related to wholesale gas services are satisfied, and revenue is recognized, at a point in time when natural gas is delivered to the customer. Southern Company Gas has elected to recognize revenue for sales of gas using the invoice practical expedient as it generally has a right to consideration in an amount that corresponds directly with the value to the customer of the performance completed to date and that may be invoiced. Payment for goods and services rendered is typically due in the subsequent month following satisfaction of Southern Company Gas' performance obligation. With the exception of Atlanta Gas Light, the natural gas distribution utilities have rate structures that include volumetric rate designs that allow the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries through the end of the period. The tariffs for the natural gas distribution utilities include provisions which allow for the recognition of certain revenues prior to the time such revenues are billed to customers. These provisions are referred to as alternative revenue programs and provide for the recognition of certain revenues prior to billing, as long as the amounts recognized will be collected from customers within 24 months of recognition. These programs are as follows: •Weather normalization adjustments - reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs for Virginia Natural Gas and Chattanooga Gas; •Revenue normalization mechanisms - mitigate the impact of conservation and declining customer usage and are contained in the tariffs for Virginia Natural Gas and Nicor Gas (effective November 1, 2019); and •Revenue true-up adjustment - included within the provisions of the GRAM program in which Atlanta Gas Light participates as a short-term alternative to formal rate case filings, the revenue true-up feature provides for a positive (or negative) adjustment to record revenue in the amount of any variance to budgeted revenues, which are submitted and approved annually as a requirement of GRAM. Such adjustments are reflected in customer billings in a subsequent program year.
Wholesale Gas Services
Prior to the sale of Sequent on July 1, 2021, Southern Company Gas netted
revenues from energy and risk management activities with the associated costs.
Profits from sales between segments were eliminated and recognized as goods or
services sold to end-use customers. Southern Company Gas recorded wholesale gas
services' transactions that qualified as derivatives at fair value with changes
in fair value recognized in earnings in the period of change and characterized
as unrealized gains or losses. Gains
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and losses on derivatives held for energy trading purposes were presented on a net basis in revenue. See Note 15 under "Southern Company Gas" for additional information on the sale of Sequent.
Gas Marketing Services
Southern Company Gas recognizes revenues from natural gas sales and transportation services in the same period in which the related volumes are delivered to customers and recognizes sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. Southern Company Gas also recognizes unbilled revenues for estimated deliveries of gas not yet billed to these customers from the most recent meter reading date to the end of the accounting period. For other commercial and industrial customers and for all wholesale customers, revenues are based on actual deliveries during the period.
Southern Company Gas recognizes revenues on 12-month utility-bill management contracts as the lesser of cumulative earned or cumulative billed amounts.
Concentration of Revenue
Southern Company, Alabama Power, Georgia Power, Mississippi Power (with the exception of its full requirements cost-based MRA electric tariffs described below), Southern Power, and Southern Company Gas each have a diversified base of customers and no single customer or industry comprises 10% or more of each company's revenues. Mississippi Power provides service under long-term contracts with rural electric cooperative associations and a municipality located in southeastern Mississippi under full requirements cost-based MRA electric tariffs, which are subject to regulation by the FERC. The contracts with these wholesale customers represented 14.3% of Mississippi Power's total operating revenues in 2021 and are generally subject to 10-year rolling cancellation notices. Historically, these wholesale customers have acted as a group and any changes in contractual relationships for one customer are likely to be followed by the other wholesale customers.
Fuel Costs
Fuel costs for the traditional electric operating companies and Southern Power are expensed as the fuel is used. Fuel expense generally includes fuel transportation costs and the cost of purchased emissions allowances as they are used. For Alabama Power and Georgia Power, fuel expense also includes the amortization of the cost of nuclear fuel. For the traditional electric operating companies, fuel costs also include gains and/or losses from fuel-hedging programs as approved by their respective state PSCs.
Cost of Natural Gas
Excluding Atlanta Gas Light, which does not sell natural gas to end-use
customers, Southern Company Gas charges its utility customers for natural gas
consumed using natural gas cost recovery mechanisms set by the applicable state
regulatory agencies. Under these mechanisms, all prudently-incurred natural gas
costs are passed through to customers without markup, subject to regulatory
review. Southern Company Gas defers or accrues the difference between the actual
cost of natural gas and the amount of commodity revenue earned in a given period
such that no operating income is recognized related to these costs. The deferred
or accrued amount is either billed or refunded to customers prospectively
through adjustments to the commodity rate. Deferred and accrued natural gas
costs are included in the balance sheets as regulatory assets and regulatory
liabilities, respectively.
Southern Company Gas' gas marketing services' customers are charged for actual
or estimated natural gas consumed. Within cost of natural gas, Southern Company
Gas also includes costs of lost and unaccounted for gas, adjustments to reduce
the value of inventories to market value, and gains and losses associated with
certain derivatives.
Income Taxes
The Registrants use the liability method of accounting for deferred income taxes
and provide deferred income taxes for all significant income tax temporary
differences. In accordance with regulatory requirements, deferred federal ITCs
for the traditional electric operating companies are deferred and amortized over
the average life of the related property, with such amortization normally
applied as a credit to reduce depreciation and amortization in the statements of
income. Southern Power's and the natural gas distribution utilities' deferred
federal ITCs, as well as certain state ITCs for Nicor Gas, are deferred and
amortized to income tax expense over the life of the respective asset.
Under current tax law, certain projects at Southern Power related to the
construction of renewable facilities are eligible for federal ITCs. Southern
Power estimates eligible costs which, as they relate to acquisitions, may not be
finalized until the allocation of the purchase price to assets has been
finalized. Southern Power applies the deferred method to ITCs, whereby the ITCs
are recorded as a deferred credit and amortized to income tax expense over the
life of the respective asset. Furthermore, the tax basis of the asset is reduced
by 50% of the ITCs received, resulting in a net deferred tax asset. Southern
Power has elected to recognize the tax
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benefit of this basis difference as a reduction to income tax expense in the year in which the plant reaches commercial operation. State ITCs are recognized as an income tax benefit in the period in which the credits are generated. In addition, certain projects are eligible for federal and state PTCs, which are recognized as an income tax benefit based on KWH production. Federal ITCs and PTCs, as well as state ITCs and other state tax credits available to reduce income taxes payable, were not fully utilized in 2021 and will be carried forward and utilized in future years. In addition, Southern Company is expected to have various state net operating loss (NOL) carryforwards for certain of its subsidiaries, including Mississippi Power and Southern Power, which would result in income tax benefits in the future, if utilized. See Note 10 under "Current and Deferred Income Taxes - Tax Credit Carryforwards" and " - Net Operating Loss Carryforwards" for additional information. The Registrants recognize tax positions that are "more likely than not" of being sustained upon examination by the appropriate taxing authorities. See Note 10 under "Unrecognized Tax Benefits" for additional information.
Other Taxes
Taxes imposed on and collected from customers on behalf of governmental agencies are presented net on the Registrants' statements of income and are excluded from the transaction price in determining the revenue related to contracts with a customer. Southern Company Gas is taxed on its gas revenues by various governmental authorities, but is allowed to recover these taxes from its customers. Revenue taxes imposed on the natural gas distribution utilities are recorded at the amount charged to customers, which may include a small administrative fee, as operating revenues, and the related taxes imposed on Southern Company Gas are recorded as operating expenses on the statements of income. Revenue taxes included in operating expenses were $119 million, $104 million, and $114 million in 2021, 2020, and 2019, respectively.
Allowance for Funds Used During Construction and Interest Capitalized
The traditional electric operating companies and the natural gas distribution utilities record AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. The equity component of AFUDC is not taxable.
Interest related to financing the construction of new facilities at Southern Power and new facilities not included in the traditional electric operating companies' and Southern Company Gas' regulated rates is capitalized in accordance with standard interest capitalization requirements.
Total AFUDC and interest capitalized for the Registrants in 2021, 2020, and 2019
was as follows:
Alabama Georgia Mississippi Southern
Southern Company Power Power(*) Power Power Southern Company Gas
(in millions)
2021 $ 282 $ 68 $ 190 $ - $ 6 $ 18
2020 230 61 138 1 11 18
2019 202 71 103 - 15 13
(*)See Note 2 under "Georgia Power - Nuclear Construction" for information on
the inclusion of a portion of construction costs related to Plant Vogtle Units 3
and 4 in Georgia Power's rate base.
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The average AFUDC composite rates for 2021, 2020, and 2019 for the traditional
electric operating companies and the natural gas distribution utilities were as
follows:
2021 2020 2019
Alabama Power 7.9 % 8.1 % 8.4 %
Georgia Power(*) 7.2 % 6.9 % 6.9 %
Mississippi Power 2.5 % 5.4 % 7.3 %
Southern Company Gas:
Atlanta Gas Light 7.7 % 7.7 % 7.8 %
Chattanooga Gas 7.1 % 7.1 % 7.1 %
Nicor Gas 0.1 % 0.7 % 2.3 %
(*)Excludes AFUDC related to the construction of Plant Vogtle Units 3 and 4. See Note 2 under "Georgia Power - Nuclear Construction" for additional information.
Impairment of Long-Lived Assets
The Registrants evaluate long-lived assets and finite-lived intangible assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on either a specific regulatory disallowance, a sales transaction price that is less than the asset group's carrying value, or an estimate of undiscounted future cash flows attributable to the asset group, as compared with the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by either the amount of regulatory disallowance or by estimating the fair value of the assets and recording a loss if the carrying value is greater than the fair value. For assets identified as held for sale, the carrying value is compared to the estimated fair value less the cost to sell in order to determine if an impairment loss is required. Until the assets are disposed of, their estimated fair value is re-evaluated when circumstances or events change. See Notes 7 and 9 under "Southern Company Gas" and "Southern Company Leveraged Lease," respectively, and Note 15 under "Southern Company" and "Southern Company Gas" for information regarding impairment charges recorded during the periods presented.
Goodwill and Other Intangible Assets and Liabilities
Southern Power's intangible assets consist primarily of certain PPAs acquired, which are amortized over the term of the respective PPA. Southern Company Gas' goodwill and other intangible assets and liabilities primarily relate to its 2016 acquisition by Southern Company. In addition to these items, Southern Company's goodwill and other intangible assets also relate to its 2016 acquisition of PowerSecure. Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. Southern Company and Southern Company Gas each evaluated its goodwill in the fourth quarter 2021 and determined no impairment was required. See Note 15 under "Southern Company" for information regarding impairments to goodwill and other intangible assets recorded in 2019.
At December 31, 2021 and 2020, goodwill was as follows:
Goodwill
(in millions)
Southern Company $ 5,280
Southern Company Gas:
Gas distribution operations $ 4,034
Gas marketing services 981
Southern Company Gas total $ 5,015
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At December 31, 2021 and 2020, other intangible assets were as follows:
At December 31, 2021 At December 31, 2020
Other Other
Gross Carrying Accumulated Intangible Gross Carrying Accumulated Intangible
Amount Amortization Assets, Net Amount Amortization Assets, Net
(in millions) (in millions)
Southern Company
Other intangible assets subject to
amortization:
Customer relationships $ 212 $ (150) $ 62 $ 212 $ (135) $ 77
Trade names 64 (38) 26 64 (31) 33
Storage and transportation
contracts(*) - - - 64 (64) -
PPA fair value adjustments 390 (109) 281 390 (89) 301
Other 11 (10) 1 10 (9) 1
Total other intangible assets
subject to amortization $ 677 $ (307) $ 370 $ 740 $ (328) $ 412
Other intangible assets not
subject to amortization:
Federal Communications Commission
licenses 75 - 75 75 - 75
Total other intangible assets $ 752 $ (307) $
445 $ 815 $ (328) $ 487
Southern Power Other intangible assets subject to amortization: PPA fair value adjustments $ 390 $ (109) $ 281 $ 390 $ (89) $ 301 Southern Company Gas Other intangible assets subject to amortization: Gas marketing services Customer relationships $ 156 $ (130) $ 26 $ 156 $ (119) $ 37 Trade names 26 (15) 11 26 (12) 14 Wholesale gas services Storage and transportation contracts(*) - - - 64 (64) - Total other intangible assets subject to amortization $ 182 $ (145) $
37 $ 246 $ (195) $ 51
(*)See Note 15 under "Southern Company Gas" for information regarding the sale of Sequent.
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Amortization associated with other intangible assets in 2021, 2020, and 2019 was
as follows:
2021 2020 2019
(in millions)
Southern Company(a) $ 44 $ 49 $ 61
Southern Power(b) 20 20 19
Southern Company Gas:
Gas marketing services $ 15 $ 17 $ 23
Wholesale gas services(b) - 2 8
Southern Company Gas total $ 15 $ 19 $ 31
(a)Includes $20 million, $22 million, and $27 million in 2021, 2020, and 2019, respectively, recorded as a reduction to operating revenues.
(b)Recorded as a reduction to operating revenues.
At December 31, 2021, the estimated amortization associated with other intangible assets for the next five years is as follows:
2022 2023 2024 2025 2026
(in millions)Southern Company $ 39 $ 37 $ 35 $ 32 $ 27 Southern Power
20 20 20 20 20
Southern Company Gas 11 9 7 6 3
Intangible liabilities of $91 million recorded under acquisition accounting for transportation contracts at Southern Company Gas were fully amortized at December 31, 2019.
Acquisition Accounting
At the time of an acquisition, management will assess whether acquired assets and activities meet the definition of a business. For acquisitions that meet the definition of a business, operating results from the date of acquisition are included in the acquiring entity's financial statements. The purchase price, including any contingent consideration, is allocated based on the fair value of the identifiable assets acquired and liabilities assumed (including any intangible assets). Assets acquired that do not meet the definition of a business are accounted for as an asset acquisition. The purchase price of each asset acquisition is allocated based on the relative fair value of assets acquired. Determining the fair value of assets acquired and liabilities assumed requires management judgment and management may engage independent valuation experts to assist in this process. Fair values are determined by using market participant assumptions and typically include the timing and amounts of future cash flows, incurred construction costs, the nature of acquired contracts, discount rates, power market prices, and expected asset lives. Any due diligence or transition costs incurred for potential or successful acquisitions are expensed as incurred. Historically, contingent consideration primarily relates to fixed amounts due to the seller once an acquired construction project is placed in service. For contingent consideration with variable payments, management fair values the arrangement with any changes recorded in the statements of income. See Note 13 for additional fair value information.
Development Costs
For Southern Power, development costs are capitalized once a project is probable of completion, primarily based on a review of its economics and operational feasibility, as well as the status of power off-take agreements and regulatory approvals, if applicable. Southern Power's capitalized development costs are included in CWIP on the balance sheets. All of Southern Power's development costs incurred prior to the determination that a project is probable of completion are expensed as incurred and included in other operations and maintenance expense in the statements of income. If it is determined that a project is no longer probable of completion, any of Southern Power's capitalized development costs are expensed and included in other operations and maintenance expense in the statements of income.
Long-Term Service Agreements
The traditional electric operating companies and Southern Power have entered
into LTSAs for the purpose of securing maintenance support for certain of their
generating facilities. The LTSAs cover all planned inspections on the covered
equipment,
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which generally includes the cost of all labor and materials. The LTSAs also obligate the counterparties to cover the costs of unplanned maintenance on the covered equipment subject to limits and scope specified in each contract. Payments made under the LTSAs for the performance of any planned inspections or unplanned capital maintenance are recorded in the statements of cash flows as investing activities. Receipts of major parts into materials and supplies inventory prior to planned inspections are treated as noncash transactions in the statements of cash flows. Any payments made prior to the work being performed are recorded as prepayments in other current assets and noncurrent assets on the balance sheets. At the time work is performed, an appropriate amount is accrued for future payments or transferred from the prepayment and recorded as property, plant, and equipment or expensed.
Transmission Receivables/Prepayments
As a result of Southern Power's acquisition and construction of generating facilities, Southern Power has transmission receivables and/or prepayments representing the portion of interconnection network and transmission upgrades that will be reimbursed to Southern Power. Upon completion of the related project, transmission costs are generally reimbursed by the interconnection provider within a five-year period and the receivable/prepayments are reduced as payments or services are received.
Cash, Cash Equivalents, and Restricted Cash
For purposes of the financial statements, temporary cash investments are considered cash equivalents. Temporary cash investments are securities with original maturities of 90 days or less.
The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the balance sheets that total to the amount shown in the statements of cash flows for the applicable Registrants:
Southern Southern
Company Southern Power Company Gas
December 31, December 31, December 31,
2021 2020 2021 December 31, 2021 December 31, 2020
(in millions) (in millions) (in millions)
Cash and cash equivalents $ 1,798 $ 1,065 $ 107 $ 45 $ 17
Restricted cash(a):
Other current assets 2 2 - 2 2
Other deferred charges and
assets 29 - 29 - -
Total cash, cash equivalents,
and restricted cash(b) $ 1,829 $ 1,068 $ 135 $ 48 $ 19
(a)For Southern Power, reflects restricted cash of $19 million related to tax
equity contributions restricted until the Garland battery energy storage
facility achieves final contracted capacity and $10 million held to fund
estimated construction completion costs at the Deuel Harvest wind facility. See
Note 15 under "Southern Power" for additional information. For Southern Company
Gas, reflects restricted cash held as collateral for workers' compensation, life
insurance, and long-term disability insurance.
(b)Total may not add due to rounding.
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Storm Damage Reserves
Each traditional electric operating company maintains a reserve to cover or is
allowed to defer and recover the cost of damages from major storms to its
transmission and distribution lines and, for Mississippi Power, the cost of
uninsured damages to its generation facilities and other property. Alabama Power
also has authority from the Alabama PSC to accrue certain additional amounts as
circumstances warrant. Alabama Power recorded additional accruals of
$65 million, $100 million, and $84 million in 2021, 2020, and 2019,
respectively. In accordance with their respective state PSC orders, the
traditional electric operating companies accrued the following amounts related
to storm damage recovery in 2021, 2020, and 2019:
Southern Alabama Georgia Mississippi
Company(a)(b) Power(a) Power Power(b)
(in millions)
2021 $ 286 $ 75 $ 213 $ (2)
2020 326 112 213 1
2019 170 139 30 1
(a)Includes $39 million applied in 2019 to Alabama Power's NDR from its remaining excess deferred income tax regulatory liability balance in accordance with an Alabama PSC order.
(b)Mississippi Power's net accrual includes carrying costs, as well as amortization of related excess deferred income tax benefits.
See Note 2 under "Alabama Power - Rate NDR," "Georgia Power - Storm Damage Recovery," and "Mississippi Power - System Restoration Rider" for additional information regarding each company's storm damage reserve.
Materials and Supplies
Materials and supplies for the traditional electric operating companies generally includes the average cost of transmission, distribution, and generating plant materials. Materials and supplies for Southern Company Gas generally includes propane gas inventory, fleet fuel, and other materials and supplies. Materials and supplies for Southern Power generally includes the average cost of generating plant materials.
Materials are recorded to inventory when purchased and then expensed or capitalized to property, plant, and equipment, as appropriate, at weighted average cost when installed. In addition, certain major parts are recorded as inventory when acquired and then capitalized at cost when installed to property, plant, and equipment. Fuel Inventory Fuel inventory for the traditional electric operating companies includes the average cost of coal, natural gas, oil, transportation, and emissions allowances. Fuel inventory for Southern Power, which is included in other current assets, includes the average cost of oil, natural gas, and emissions allowances. Fuel is recorded to inventory when purchased and then expensed, at weighted average cost, as used. Emissions allowances granted by the EPA are included in inventory at zero cost. The traditional electric operating companies recover fuel expense through fuel cost recovery rates approved by each state PSC or, for wholesale rates, the FERC.
Natural Gas for Sale
With the exception of Nicor Gas, Southern Company Gas records natural gas
inventories on a WACOG basis. In Georgia's deregulated, competitive environment,
Marketers sell natural gas to firm end-use customers at market-based prices. On
a monthly basis, Atlanta Gas Light assigns to Marketers the majority of the
pipeline storage services that it has under contract, along with a corresponding
amount of inventory. Atlanta Gas Light retains and manages a portion of its
pipeline storage assets and related natural gas inventories for system balancing
and to serve system demand.
Nicor Gas' natural gas inventory is carried at cost on a LIFO basis. Inventory
decrements occurring during the year that are restored prior to year end are
charged to cost of natural gas at the estimated annual replacement cost.
Inventory decrements that are not restored prior to year end are charged to cost
of natural gas at the actual LIFO cost of the inventory layers liquidated. The
cost of natural gas, including inventory costs, is recovered from customers
under a purchased gas recovery mechanism adjusted for differences between actual
costs and amounts billed; therefore, LIFO liquidations have no impact on
Southern Company's or Southern Company Gas' net income. At December 31, 2021,
the Nicor Gas LIFO inventory balance was $166 million. Based on the average cost
of gas purchased in December 2021, the estimated replacement cost of Nicor Gas'
inventory at December 31, 2021 was $470 million.
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Southern Company Gas' gas marketing services, wholesale gas services (until the sale of Sequent on July 1, 2021), and all other segments record inventory at LOCOM, with cost determined on a WACOG basis. For these segments, Southern Company Gas evaluates the weighted average cost of its natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, Southern Company Gas records LOCOM adjustments to cost of natural gas to reduce the value of its natural gas inventories to market value. LOCOM adjustments for wholesale gas services were $1 million, $1 million, and $21 million during 2021, 2020, and 2019, respectively, and were immaterial for all of Southern Company Gas' other segments.
Energy Marketing Receivables and Payables
Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' wholesale gas services provided services to retail gas marketers, wholesale gas marketers, utility companies, and industrial customers. These counterparties utilized netting agreements that enabled wholesale gas services to net receivables and payables by counterparty upon settlement. Southern Company Gas' wholesale gas services also netted across product lines and against cash collateral, provided the netting and cash collateral agreements included such provisions. While the amounts due from, or owed to, wholesale gas services' counterparties were settled net, they were recorded on a gross basis in the balance sheets as energy marketing receivables and energy marketing payables. Southern Company Gas' wholesale gas services used established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security was most often in the form of cash or letters of credit from an investment-grade financial institution, but could also include cash or U.S. government securities held by a trustee. When more than one derivative transaction with the same counterparty was outstanding and a legally enforceable netting agreement existed with that counterparty, the "net" mark-to-market exposure represented a reasonable measure of Southern Company Gas' credit risk with that counterparty. Southern Company Gas' wholesale gas services also used other netting agreements with certain counterparties with whom it conducted significant transactions.
Provision for Uncollectible Accounts
The customers of the traditional electric operating companies and the natural gas distribution utilities are billed monthly. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the company is aware of a specific customer's inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount reasonably expected to be collected. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers' accounts are written off once they are deemed to be uncollectible. For all periods presented, uncollectible accounts averaged less than 1% of revenues for each Registrant. Credit risk exposure at Nicor Gas is mitigated by a bad debt rider approved by the Illinois Commission. The bad debt rider provides for the recovery from (or refund to) customers of the difference between Nicor Gas' actual bad debt experience on an annual basis and the benchmark bad debt expense used to establish its base rates for the respective year.
See Note 2 for information regarding recovery of incremental bad debt expense related to the COVID-19 pandemic at certain of the traditional electric operating companies and natural gas distribution utilities.
Concentration of Credit Risk
Concentration of credit risk occurs at Atlanta Gas Light for amounts billed for
services and other costs to its customers, which consist of 16 Marketers in
Georgia (including SouthStar). The credit risk exposure to the Marketers varies
seasonally, with the lowest exposure in the non-peak summer months and the
highest exposure in the peak winter months. Marketers are responsible for the
retail sale of natural gas to end-use customers in Georgia. The functions of the
retail sale of gas include the purchase and sale of natural gas, customer
service, billings, and collections. The provisions of Atlanta Gas Light's tariff
allow Atlanta Gas Light to obtain credit security support in an amount equal to
a minimum of two times a Marketer's highest month's estimated bill from Atlanta
Gas Light.
Financial Instruments
The traditional electric operating companies and Southern Power use derivative
financial instruments to limit exposure to fluctuations in interest rates, the
prices of certain fuel purchases, electricity purchases and sales, and
occasionally foreign currency exchange rates. Southern Company Gas uses
derivative financial instruments to limit exposure to fluctuations in natural
gas prices, weather, interest rates, and commodity prices. All derivative
financial instruments are recognized as either assets or liabilities on the
balance sheets (included in "Other" or shown separately as "Risk Management
Activities") and are measured at
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fair value. See Note 13 for additional information regarding fair value. Substantially all of the traditional electric operating companies' and Southern Power's bulk energy purchases and sales contracts that meet the definition of a derivative are excluded from fair value accounting requirements because they qualify for the "normal" scope exception, and are accounted for under the accrual method. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the traditional electric operating companies' and the natural gas distribution utilities' fuel-hedging programs result in the deferral of related gains and losses in AOCI or regulatory assets and liabilities, respectively, until the hedged transactions occur. Other derivative contracts that qualify as fair value hedges are marked to market through current period income and are recorded on a net basis in the statements of income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 14 for additional information regarding derivatives. The Registrants offset fair value amounts recognized for multiple derivative instruments executed with the same counterparty under netting arrangements. The Registrants had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2021. The Registrants are exposed to potential losses related to financial instruments in the event of counterparties' nonperformance. The Registrants have established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk.
Southern Company Gas
Southern Company Gas enters into weather derivative contracts as economic hedges of natural gas revenues in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in natural gas revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are also reflected in natural gas revenues in the statements of income. Prior to the sale of Sequent on July 1, 2021, wholesale gas services purchased natural gas for storage when the market price paid to buy and transport natural gas plus the cost to store and finance the natural gas was less than the market price that could be received in the future, resulting in positive net natural gas revenues. NYMEX futures and OTC contracts were used to sell natural gas at that future price to substantially protect the natural gas revenues that would ultimately be realized when the stored natural gas was sold. Southern Company Gas enters into transactions to secure transportation capacity between delivery points in order to serve its customers and various markets. NYMEX futures and OTC contracts are used to capture the price differential or spread between the locations served by the capacity to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between delivery points occurs. These contracts generally meet the definition of derivatives and are carried at fair value on the balance sheets, with changes in fair value recorded in natural gas revenues on the statements of income in the period of change. These contracts are not designated as hedges for accounting purposes. The purchase, transportation, storage, and sale of natural gas are accounted for on a weighted average cost or accrual basis, as appropriate, rather than on the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized on the statements of income in the period they are incurred. This difference in accounting methods can result in volatility in reported earnings, even though the economic margin is substantially unchanged from the dates the transactions were consummated.
Comprehensive Income
The objective of comprehensive income is to report a measure of all changes in
common stock equity of an enterprise that result from transactions and other
economic events of the period other than transactions with owners. Comprehensive
income consists of net income attributable to the Registrant, changes in the
fair value of qualifying cash flow hedges, and reclassifications for amounts
included in net income. Comprehensive income also consists of certain changes in
pension and other postretirement benefit plans for Southern Company, Southern
Power, and Southern Company Gas.
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AOCI (loss) balances, net of tax effects, for Southern Company, Southern Power, and Southern Company Gas were as follows:
Pension and Other Accumulated Other
Qualifying Postretirement Comprehensive
Hedges Benefit Plans Income (Loss)(*)
(in millions)
Southern Company
Balance at December 31, 2020 $ (209) $ (187) $ (395)
Current period change 47 111 158
Balance at December 31, 2021 $ (162) $ (76) $ (237)
Southern Power
Balance at December 31, 2020 $ (21) $ (47) $ (67)
Current period change 22 18 40
Balance at December 31, 2021 $ 1 $ (29) $ (27)
Southern Company Gas
Balance at December 31, 2020 $ (20) $ (2) $ (22)
Current period change 6 40 46
Balance at December 31, 2021 $ (14) $ 38 $ 24
(*)May not add due to rounding.
Variable Interest Entities
The Registrants may hold ownership interests in a number of business ventures
with varying ownership structures. Partnership interests and other variable
interests are evaluated to determine if each entity is a VIE. The primary
beneficiary of a VIE is required to consolidate the VIE when it has both the
power to direct the activities of the VIE that most significantly impact the
VIE's economic performance and the obligation to absorb losses or the right to
receive benefits from the VIE that could potentially be significant to the VIE.
See Note 7 for additional information regarding VIEs.
At December 31, 2020, Alabama Power had a wholly-owned trust to issue preferred
securities; however, since Alabama Power was not considered the primary
beneficiary of the trust, the related investment at December 31, 2020 is
reflected as other investments and the related loan from the trust is reflected
as long-term debt in Alabama Power's balance sheet. See Note 8 under "Long-term
Debt" for additional information.
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2. REGULATORY MATTERS
Regulatory Assets and Liabilities
Details of regulatory assets and (liabilities) reflected in the balance sheets at December 31, 2021 and 2020 are provided in the following tables:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Company Gas
(in millions)
At December 31, 2021
AROs(a)(u) $ 5,685 $ 1,576 $ 3,866 $ 236 $ -
Retiree benefit plans(b)(u) 2,998 747 962 145 95
Remaining net book value of retired assets(c) 1,050 574 455 21 -
Deferred income tax charges(d) 829 240 555 31 -
Under recovered regulatory clause revenues(e) 806 225 - 49 532
Environmental remediation(f)(u) 302 - 35 - 267
Loss on reacquired debt(g) 281 42 231 6 2
Vacation pay(h)(u) 207 81 102 10 14
Regulatory clauses(i) 142 142 - - -
Storm damage(j) 97 - 48 49 -
Long-term debt fair value adjustment(k) 79 - - - 79
Nuclear outage(l) 75 41 34 - -
Software and cloud computing costs(m) 73 35 33 - 5
Kemper County energy facility assets, net(n) 35 - - 35 -
Plant Daniel Units 3 and 4(o) 28 - - 28 -
Other regulatory assets(p) 168 38 29 7 94
Deferred income tax credits(d) (5,636) (1,968) (2,537) (288) (816)
Other cost of removal obligations(a) (1,826) (192) 278 (195) (1,683)
Customer refunds(q) (189) (181) (8) - -
Fuel-hedging (realized and unrealized) gains(r) (176) (50) (72) (54) -
Storm/property damage reserves(s) (133) (103) - (30) -
Over recovered regulatory clause revenues(e) (63) (1) (59) - (3)
Other regulatory liabilities(t) (121) (29) (24) (4) (57)
Total regulatory assets (liabilities), net $ 4,711 $ 1,217 $ 3,928 $
46 $ (1,471)
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Southern Southern
Company Alabama Power Georgia Power Mississippi Power Company Gas
(in millions)
At December 31, 2020
AROs(a)(u) $ 5,147 $ 1,470 $ 3,457 $ 212 $ -
Retiree benefit plans(b)(u) 4,958 1,265 1,647 238 187
Remaining net book value of retired assets(c) 1,183 632 527 24 -
Deferred income tax charges(d) 801 235 531 32 -
Environmental remediation(f)(u) 310 - 41 - 269
Loss on reacquired debt(g) 304 47 248 6 3
Storm damage(j) 262 - 262 - -
Vacation pay(h)(u) 207 80 104 10 13
Under recovered regulatory clause revenues(e) 185 58 - 52 75
Regulatory clauses(i) 142 142 - - -
Nuclear outage(l) 101 61 40 - -
Long-term debt fair value adjustment(k) 92 - - - 92
Kemper County energy facility assets, net(n) 50 - - 50 -
Plant Daniel Units 3 and 4(o) 32 - - 32 -
Software and cloud computing costs(m) 31 17 12 - 2
Other regulatory assets(p) 174 35 56 4 79
Deferred income tax credits(d) (6,016) (2,016) (2,805) (320) (847)
Other cost of removal obligations(a) (1,999) (335) 212 (194) (1,649)
Over recovered regulatory clause revenues(e) (185) (46) (44) - (95)
Storm/property damage reserves(s) (81) (77) - (4) -
Customer refunds(q) (56) (50) (6) - -
Other regulatory liabilities(t) (149) (37) (30) (6) (54)
Total regulatory assets (liabilities), net $ 5,493 $ 1,481 $ 4,252 $
136 $ (1,925)
Unless otherwise noted, the following recovery and amortization periods for these regulatory assets and (liabilities) have been approved by the respective state PSC or regulatory agency:
(a)AROs and other cost of removal obligations generally are recorded over the related property lives, which may range up to 53 years for Alabama Power, 60 years for Georgia Power, 55 years for Mississippi Power, and 80 years for Southern Company Gas. AROs and cost of removal obligations will be settled and trued up following completion of the related activities. Effective January 1, 2020, Georgia Power is recovering CCR AROs, including past under recovered costs and estimated annual compliance costs, over three-year periods ending December 31, 2022, 2023, and 2024 through its ECCR tariff, as discussed further under "Georgia Power - Rate Plans" herein. See Note 6 for additional information on AROs. (b)Recovered and amortized over the average remaining service period, which may range up to 13 years for Alabama Power, Georgia Power, and Mississippi Power and up to 14 years for Southern Company Gas. Southern Company's balances also include amounts at SCS and Southern Nuclear that are allocated to the applicable regulated utilities. See Note 11 for additional information. (c)Alabama Power: Primarily represents the net book value of Plant Gorgas Units 8, 9, and 10 ($533 million at December 31, 2021) being amortized over remaining periods not exceeding 16 years (through 2037). Georgia Power: Net book values of Plant Hammond Units 1 through 4 and Plant Branch Units 3 and 4 (totaling $445 million at December 31, 2021) are being amortized over remaining periods of between two and 14 years (between 2023 and 2035) and the net book values of Plant Branch Unit 2, Plant McIntosh Unit 1, and Plant Mitchell Unit 3 (totaling $10 million at December 31, 2021) are being amortized through 2022. Mississippi Power: Represents net book value of certain environmental compliance projects associated with Plant Watson and Plant Greene County being amortized over a 10-year period through 2030. See "Mississippi Power - Environmental Compliance Overview Plan" herein for additional information. (d)Deferred income tax charges are recovered and deferred income tax credits are amortized over the related property lives, which may range up to 53 years for Alabama Power, 60 years for Georgia Power, 55 years for Mississippi Power, and 80 years for Southern Company Gas. See Note 10 for additional information. Included in the deferred income tax charges are amounts ($7 million and $4 million for Alabama Power and Georgia Power, respectively, at December 31, 2021) for the retiree Medicare drug subsidy, which are being recovered and amortized through 2027 and 2022 for Alabama Power and Georgia Power, respectively. As a result of the Tax Reform Legislation, these accounts include certain deferred income tax assets and liabilities not subject to normalization, as described further below:
Alabama Power: Related amounts are being recovered and amortized ratably over the related property lives.
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Georgia Power: Related amounts at December 31, 2021 include $145 million of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 and approximately $220 million of deferred income tax liabilities. The recovery of deferred income tax assets related to CWIP for Plant Vogtle Units 3 and 4 is expected to be determined in a future regulatory proceeding. Effective January 1, 2020, the deferred income tax liabilities are being amortized through 2022. Mississippi Power: Related amounts at December 31, 2021 include $46 million of retail deferred income tax liabilities generally being amortized over three years (through 2023). See "Mississippi Power - 2019 Base Rate Case" herein for additional information.
Southern Company Gas: Related amounts at December 31, 2021 include $3 million of deferred income tax liabilities being amortized through 2024. See "Southern Company Gas - Rate Proceedings" herein for additional information.
(e)Alabama Power: Balances are recorded monthly and expected to be recovered or returned within eight years. Recovery periods could change based on several factors including changes in cost estimates, load forecasts, and timing of rate adjustments. See "Alabama Power - Rate CNP PPA," " - Rate CNP Compliance," and " - Rate ECR" herein for additional information.
Georgia Power: Balances are recorded monthly and expected to be recovered or returned within two years. See "Georgia Power - Rate Plans" herein for additional information.
Mississippi Power: At December 31, 2021, $24 million is being amortized over a three-year period through 2023 and the remaining $25 million is expected to be recovered through various rate recovery mechanisms over a period to be determined in future rate filings. See "Mississippi Power - Ad Valorem Tax Adjustment" herein for additional information. Southern Company Gas: Balances are recorded and recovered or amortized over periods generally not exceeding four years. In addition to natural gas cost recovery mechanisms, the natural gas distribution utilities have various other cost recovery mechanisms for the recovery of costs, including those related to infrastructure replacement programs. The significant change during 2021 was primarily driven by an increase in the cost of gas purchased in February 2021 resulting from Winter Storm Uri.
(f)Georgia Power is recovering $12 million annually for environmental remediation under the 2019 ARP. Southern Company Gas' costs are recovered through environmental cost recovery mechanisms when the remediation work is performed. See Note 3 under "Environmental Remediation" for additional information.
(g)Recovered over either the remaining life of the original issue or, if refinanced, over the remaining life of the new issue. At December 31, 2021, the remaining amortization periods do not exceed 26 years for Alabama Power, 31 years for Georgia Power, 20 years for Mississippi Power, and six years for Southern Company Gas.
(h)Recorded as earned by employees and recovered as paid, generally within one year. Includes both vacation and banked holiday pay, if applicable.
(i)Will be amortized concurrently with the effective date of Alabama Power's next depreciation study, which is expected to occur no later than 2023.
(j)Georgia Power is recovering approximately $213 million annually for storm damage under the 2019 ARP. See "Georgia Power - Storm Damage Recovery" herein for additional information. Mississippi Power's balance represents deferred storm costs associated with Hurricanes Ida and Zeta to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. See "Mississippi Power - System Restoration Rider" herein for additional information. Also see Note 1 under "Storm Damage Reserves" for additional information.
(k)Recovered over the remaining lives of the original debt issuances at acquisition, which range up to 17 years at December 31, 2021.
(l)Nuclear outage costs are deferred to a regulatory asset when incurred and amortized over a subsequent period of 18 months for Alabama Power and up to 24 months for Georgia Power. See Note 5 for additional information. (m)Represents certain deferred operations and maintenance costs associated with software and cloud computing projects. For Alabama Power, costs are amortized ratably over the life of the related software, which ranges up to 10 years. See "Alabama Power - Software Accounting Order" herein for additional information. For Georgia Power, the recovery period will be determined in its next base rate case. For Southern Company Gas, costs will be amortized ratably beginning in July 2022 over the life of the related software, which ranges up to 10 years. (n)Includes $44 million of regulatory assets and $9 million of regulatory liabilities at December 31, 2021. The retail portion includes $33 million of regulatory assets and $9 million of regulatory liabilities that are expected to be fully amortized by 2023 and 2024, respectively. The wholesale portion includes $11 million of regulatory assets that are expected to be fully amortized by 2029. (o)Represents the difference between Mississippi Power's revenue requirement for Plant Daniel Units 3 and 4 under purchase accounting and operating lease accounting. At December 31, 2021, consists of the $19 million retail portion, which is being amortized over the remaining life of the units through 2041, and the $9 million wholesale portion, which is expected to be amortized over a period to be determined in a future wholesale rate filing. (p)Except as otherwise noted, comprised of numerous immaterial components with remaining amortization periods generally not exceeding 23 years for Alabama Power, 10 years for Georgia Power, six years for Mississippi Power, and 20 years for Southern Company Gas at December 31, 2021. Balances at December 31, 2021 and 2020 include deferred COVID-19 costs (except for Alabama Power), as discussed further under "Deferral of Incremental COVID-19 Costs" for each applicable Registrant herein. (q)Primarily includes approximately $181 million and $50 million at December 31, 2021 and 2020, respectively, for Alabama Power and $5 million at December 31, 2021 for Georgia Power as a result of each company exceeding its allowed retail return range. Georgia Power's balances also include immaterial amounts related to refunds for transmission service customers. See "Alabama Power - Rate RSE" and "Georgia Power - Rate Plans" herein for additional information. (r)Fuel-hedging assets and liabilities are recorded over the life of the underlying hedged purchase contracts. Upon final settlement, actual costs incurred are recovered through the applicable traditional electric operating company's fuel cost recovery mechanism. Purchase contracts generally do not exceed three and a half years for Alabama Power, three years for Georgia Power, and three years for Mississippi Power. Immaterial amounts at December 31, 2020 are included in other regulatory assets and liabilities.
(s)Amortized as related expenses are incurred. See "Alabama Power - Rate NDR" and "Mississippi Power - System Restoration Rider" herein for additional information.
(t)Comprised of numerous immaterial components with remaining amortization periods generally not exceeding 16 years for Alabama Power, 11 years for Georgia Power, three years for Mississippi Power, and 20 years for Southern Company Gas at December 31, 2021.
(u)Generally not earning a return as they are excluded from rate base or are offset in rate base by a corresponding asset or liability.
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Alabama Power
Alabama Power's revenues from regulated retail operations are collected through various rate mechanisms subject to the oversight of the Alabama PSC. Alabama Power currently recovers its costs from the regulated retail business primarily through Rate RSE, Rate CNP, Rate ECR, and Rate NDR. In addition, the Alabama PSC issues accounting orders to address current events impacting Alabama Power.
Certificates of Convenience and Necessity
In August 2020, the Alabama PSC issued its order regarding Alabama Power's 2019 petition for a CCN, which authorized Alabama Power to (i) construct an approximately 720-MW combined cycle facility at Alabama Power's Plant Barry (Plant Barry Unit 8) that is expected to be placed in service by the end of 2023, (ii) complete the acquisition of the Central Alabama Generating Station, which occurred in August 2020, (iii) purchase approximately 240 MWs of combined cycle generation under a long-term PPA, which began in September 2020, and (iv) pursue up to approximately 200 MWs of cost-effective demand-side management and distributed energy resource programs. Alabama Power's petition for a CCN was predicated on the results of Alabama Power's 2019 IRP provided to the Alabama PSC, which identified an approximately 2,400-MW resource need for Alabama Power, driven by the need for additional winter reserve capacity. See Note 15 under "Alabama Power" for additional information on the acquisition of the Central Alabama Generating Station. The Alabama PSC authorized the recovery of actual costs for the construction of Plant Barry Unit 8 up to 5% above the estimated in-service cost of $652 million. In so doing, it recognized the potential for developments that could cause the project costs to exceed the capped amount, in which case Alabama Power would provide documentation to the Alabama PSC to explain and justify potential recovery of the additional costs. At December 31, 2021, project expenditures associated with Plant Barry Unit 8 included in CWIP totaled approximately $304 million. The Alabama PSC further directed that additional solar generation of approximately 400 MWs proposed in the 2019 CCN petition, coupled with battery energy storage systems (solar/battery systems), be evaluated under an existing Renewable Generation Certificate (RGC). The contracts originally proposed expired in July 2020. See "Renewable Generation Certificate" herein for additional information. Alabama Power expects to recover costs associated with Plant Barry Unit 8 pursuant to its Rate CNP New Plant. Alabama Power is recovering all costs associated with the Central Alabama Generating Station through the inclusion in Rate RSE of revenues from the existing power sales agreement and, on expiration of that agreement, expects to recover costs pursuant to Rate CNP New Plant. The recovery of costs associated with laws, regulations, and other such mandates directed at the utility industry are expected to be recovered through Rate CNP Compliance. Alabama Power expects to recover the capacity-related costs associated with the PPAs through its Rate CNP PPA. In addition, fuel and energy-related costs are expected to be recovered through Rate ECR. Any remaining costs associated with Plant Barry Unit 8 and the acquisition of the Central Alabama Generating Station are expected to be recovered through Rate RSE. On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates a 743-MW winter peak, simple-cycle, combustion turbine generation facility in Calhoun County, Alabama (Calhoun Generating Station). The total purchase price associated with the acquisition is approximately $180 million, subject to working capital adjustments. The completion of the acquisition is subject to the satisfaction and waiver of certain conditions, including, among other customary conditions, approval by the Alabama PSC and the FERC. On October 28, 2021, Alabama Power filed a petition for a CCN with the Alabama PSC to procure additional generating capacity through this acquisition. Completion of the acquisition and certain operating conditions would enable Alabama Power to retire Plant Barry Unit 5 as early as 2023. A decision from the Alabama PSC is expected by the third quarter 2022. Pending certification, Alabama Power expects to recover costs associated with the Calhoun Generating Station through its existing rate structure, primarily Rate CNP New Plant, Rate CNP Compliance, Rate ECR, and Rate RSE.
Alabama Power expects to complete the transaction by September 30, 2022; however, the ultimate outcome of these matters cannot be determined at this time.
Renewable Generation Certificate
Through the issuance of a RGC, the Alabama PSC has authorized Alabama Power to
procure up to 500 MWs of renewable capacity and energy by September 16, 2027 and
to market the related energy and environmental attributes to customers and other
third parties. Through December 31, 2021, Alabama Power has procured
approximately 250 MWs through five projects approved
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under the RGC. Alabama Power owns two of the projects, totaling 18 MWs, with the remaining MWs expected to be served through three PPAs, two of which will commence in the first quarter 2024.
Rate RSE
The Alabama PSC has adopted Rate RSE that provides for periodic annual adjustments based upon Alabama Power's projected weighted common equity return (WCER) compared to an allowable range. Rate RSE adjustments are based on forward-looking information for the applicable upcoming calendar year. Rate RSE adjustments for any two-year period, when averaged together, cannot exceed 4.0% and any annual adjustment is limited to 5.0%. When the projected WCER is under the allowed range, there is an adjusting point of 5.98% and eligibility for a performance-based adder of seven basis points, or 0.07%, to the WCER adjusting point if Alabama Power (i) has an "A" credit rating equivalent with at least one of the recognized rating agencies or (ii) is in the top one-third of a designated customer value benchmark survey.
Alabama Power continues to reduce growth in total debt by increasing equity, with corresponding reductions in debt issuances, thereby de-leveraging its capital structure. Alabama Power's goal is to achieve an equity ratio of approximately 55% by the end of 2025. At both December 31, 2021 and 2020, Alabama Power's equity ratio was approximately 51.6%.
Effective for January 2019, the Alabama PSC approved modifications to Rate RSE. These modifications reduced the top of the allowed WCER range from 6.21% to 6.15% and modified the refund mechanism applicable to prior year actual results to allow Alabama Power to retain a portion of the revenue that causes the actual WCER for a given year to exceed the allowed range. These modifications were designed to position Alabama Power to address the growing pressure on its credit quality resulting from the Tax Reform Legislation, without increasing retail rates under Rate RSE in the near term. Generally, during a year without a Rate RSE upward adjustment, if Alabama Power's actual WCER is between 6.15% and 7.65%, customers will receive 25% of the amount between 6.15% and 6.65%, 40% of the amount between 6.65% and 7.15%, and 75% of the amount between 7.15% and 7.65%. Customers will receive all amounts in excess of an actual WCER of 7.65%. During a year with a Rate RSE upward adjustment, if Alabama Power's actual WCER exceeds 6.15%, customers receive 50% of the amount between 6.15% and 6.90% and all amounts in excess of an actual WCER of 6.90%. There is no provision for additional customer billings should the actual retail return fall below the WCER range. In conjunction with these modifications to Rate RSE, Alabama Power consented to a moratorium on any upward adjustments under Rate RSE for 2019 and 2020 and to return $50 million to customers through bill credits in 2019. Retail rates under Rate RSE remained unchanged for 2019 and 2020 and increased by 4.09%, or approximately $228 million annually, effective with the billing month of January 2021. At December 31, 2019, 2020, and 2021, Alabama Power's WCER exceeded 6.15%, resulting in Alabama Power establishing a current regulatory liability of $53 million, $50 million, and $181 million, respectively, for Rate RSE refunds. The 2019 and 2020 refunds were issued to customers through bill credits in April of the following year. In accordance with an Alabama PSC order issued on February 1, 2022, Alabama Power will apply $126 million of the 2021 refund to reduce the Rate ECR under recovered balance and the remaining $55 million will be refunded to customers through bill credits in July 2022. See "Rate ECR" herein for additional information. On December 1, 2021, Alabama Power made its required annual Rate RSE submission to the Alabama PSC of projected data for calendar year 2022. Projected earnings were within the specified range; therefore, retail rates under Rate RSE remain unchanged for 2022. Rate CNP New Plant Rate CNP New Plant allows for recovery of Alabama Power's retail costs associated with newly developed or acquired certificated generating facilities placed into retail service. No adjustments to Rate CNP New Plant occurred during the period 2019 through 2021. See "Certificates of Convenience and Necessity" herein for additional information.
Rate CNP PPA
Rate CNP PPA allows for the recovery of Alabama Power's retail costs associated
with certificated PPAs. Revenues for Rate CNP PPA, as recorded on the financial
statements, are adjusted for differences in actual recoverable costs and amounts
billed in current regulated rates. Accordingly, changes in the billing factor
will have no significant effect on Southern Company's or Alabama Power's
revenues or net income but will affect annual cash flow. No adjustments to Rate
CNP PPA occurred during the period 2019 through 2021 and no adjustment is
expected for 2022. At December 31, 2021 and 2020, Alabama Power had an under
recovered Rate CNP PPA balance of $84 million and $58 million, respectively,
which is included in other regulatory assets, deferred on the balance sheet.
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Rate CNP Compliance
Rate CNP Compliance allows for the recovery of Alabama Power's retail costs associated with laws, regulations, and other such mandates directed at the utility industry involving the environment, security, reliability, safety, sustainability, or similar considerations impacting Alabama Power's facilities or operations. Rate CNP Compliance is based on forward-looking information and provides for the recovery of these costs pursuant to factors that are calculated and submitted to the Alabama PSC by December 1 with rates effective for the following calendar year. Compliance costs to be recovered include operations and maintenance expenses, depreciation, and a return on certain invested capital. Revenues for Rate CNP Compliance, as recorded on the financial statements, are adjusted for differences in actual recoverable costs and amounts billed in current regulated rates. Accordingly, changes in the billing factor will have no significant effect on Southern Company's or Alabama Power's revenues or net income, but will affect annual cash flow. Changes in Rate CNP Compliance-related operations and maintenance expenses and depreciation generally will have no effect on net income. In November 2019, 2020, and 2021, Alabama Power submitted calculations associated with its cost of complying with governmental mandates for the following calendar year, as provided under Rate CNP Compliance. The 2019 filing reflected a projected over recovered retail revenue requirement, which resulted in a rate decrease of approximately $68 million that became effective for the billing month of January 2020. Both the 2020 and 2021 filings reflected a projected under recovered retail revenue requirement of approximately $59 million. In December 2020 and on December 7, 2021, the Alabama PSC issued consent orders that Alabama Power leave the 2020 Rate CNP Compliance factors in effect for 2021 and 2022, respectively, with any prior year under collected amount deemed recovered before any current year amounts are recovered. Any remaining under recovered amount will be reflected in the 2022 filing. At December 31, 2021, Alabama Power had an under recovered Rate CNP Compliance balance of $16 million included in other regulatory assets, deferred on the balance sheet. At December 31, 2020, Alabama Power had an over recovered Rate CNP Compliance balance of $28 million included in other regulatory liabilities, current on the balance sheet.
Rate ECR
Rate ECR recovers Alabama Power's retail energy costs based on an estimate of future energy costs and the current over or under recovered balance. Revenues recognized under Rate ECR and recorded on the financial statements are adjusted for the difference in actual recoverable fuel costs and amounts billed in current regulated rates. The difference in the recoverable fuel costs and amounts billed gives rise to the over or under recovered amounts recorded as regulatory assets or liabilities. Alabama Power, along with the Alabama PSC, continually monitors the over or under recovered cost balance to determine whether an adjustment to billing rates is required. Changes in the Rate ECR factor have no significant effect on Southern Company's or Alabama Power's net income but will impact operating cash flows. The Alabama PSC may approve billing rates under Rate ECR of up to 5.910 cents per KWH.
In 2019, the Alabama PSC approved a decrease to Rate ECR from 2.353 cents per KWH to 2.160 cents per KWH, equal to 1.82%, or approximately $102 million annually, that became effective for the billing month of January 2020.
In October 2020, Alabama Power reduced its over-collected fuel balance by $94 million in accordance with an August 2020 Alabama PSC order and returned that amount to customers in the form of bill credits.
In December 2020, the Alabama PSC approved a decrease to Rate ECR from 2.160 cents per KWH to 1.960 cents per KWH, equal to 1.84%, or approximately $103 million annually, that became effective for the billing month of January 2021.
On December 7, 2021, the Alabama PSC issued a consent order that Alabama Power leave the 2021 Rate ECR factors in effect for 2022. The rate will adjust to 5.910 cents per KWH in January 2023 absent a further order from the Alabama PSC.
At December 31, 2021, Alabama Power's under recovered fuel costs totaled $126
million and is included in other regulatory assets, deferred on the balance
sheet. In accordance with an Alabama PSC order issued on February 1, 2022,
Alabama Power will apply $126 million of its 2021 Rate RSE refund to reduce the
Rate ECR under recovered balance. See "Rate RSE" herein for additional
information. At December 31, 2020, Alabama Power's over recovered fuel costs
totaled $18 million and is included in other regulatory liabilities, current on
the balance sheet. These classifications are based on estimates, which include
such factors as weather, generation availability, energy demand, and the price
of energy. A change in any of these factors could have a significant impact on
the timing of any recovery or return of fuel costs.
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Software Accounting Order
In 2019, the Alabama PSC approved an accounting order that authorizes Alabama Power to establish a regulatory asset for operations and maintenance costs associated with software implementation projects. The regulatory asset will be amortized ratably over the life of the related software. At December 31, 2021 and 2020, the regulatory asset balance totaled $35 million and $17 million, respectively, and is included in other regulatory assets, deferred on the balance sheet.
Plant Greene County
Alabama Power jointly owns Plant Greene County with an affiliate, Mississippi Power. See Note 5 under "Joint Ownership Agreements" for additional information. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. Mississippi Power's 2021 IRP included a schedule to retire Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 in December 2025 and 2026, respectively, consistent with each unit's remaining useful life. The Plant Greene County unit retirements identified by Mississippi Power require the completion of transmission and system reliability improvements, as well as agreement by Alabama Power. Alabama Power will continue to monitor the status of the transmission and system reliability improvements. Currently, Alabama Power plans to retire Plant Greene County Units 1 and 2 at the dates indicated. The ultimate outcome of this matter cannot be determined at this time. Rate NDR Based on an order from the Alabama PSC, Alabama Power maintains a reserve for operations and maintenance expenses to cover the cost of damages from major storms to its transmission and distribution facilities. The order approves a separate monthly Rate NDR charge to customers consisting of two components. The first component is intended to establish and maintain a reserve balance for future storms and is an on-going part of customer billing. When the reserve balance falls below $50 million, a reserve establishment charge will be activated (and the on-going reserve maintenance charge concurrently suspended) until the reserve balance reaches $75 million. The second component of the Rate NDR charge is intended to allow recovery of any existing deferred storm-related operations and maintenance costs and any future reserve deficits over a 24-month period. The Alabama PSC order gives Alabama Power authority to record a deficit balance in the NDR when costs of storm damage exceed any established reserve balance. Absent further Alabama PSC approval, the maximum total Rate NDR charge consisting of both components is $10 per month per non-residential customer account and $5 per month per residential customer account. Alabama Power has the authority, based on an order from the Alabama PSC, to accrue certain additional amounts as circumstances warrant. The order allows for reliability-related expenditures to be charged against the additional accruals when the NDR balance exceeds $75 million. Alabama Power may designate a portion of the NDR to reliability-related expenditures as a part of an annual budget process for the following year or during the current year for identified unbudgeted reliability-related expenditures that are incurred. Accruals that have not been designated can be used to offset storm charges. Additional accruals to the NDR enhance Alabama Power's ability to mitigate the financial effects of future natural disasters, promote system reliability, and offset costs retail customers would otherwise bear. Alabama Power made additional accruals of $65 million, $100 million, and $84 million in 2021, 2020, and 2019, respectively. Alabama Power collected approximately $6 million, $5 million, and $16 million in 2021, 2020, and 2019, respectively, under Rate NDR. At December 31, 2021 and 2020, the NDR balance was $103 million and $77 million, respectively, and is included in other regulatory liabilities, deferred on the balance sheets. Beginning with June 2022 billings, the reserve establishment charge will be suspended and the reserve maintenance charge will be activated as a result of the NDR balance exceeding $75 million. Alabama Power expects to collect $8 million in 2022 and approximately $3 million annually beginning in 2023 under Rate NDR unless the NDR balance falls below $50 million.
As revenue from the Rate NDR charge is recognized, an equal amount of operations and maintenance expenses related to the NDR will also be recognized. As a result, the Rate NDR charge will not have an effect on net income but will impact operating cash flows.
Environmental Accounting Order
Based on an order from the Alabama PSC (Environmental Accounting Order), Alabama
Power is authorized to establish a regulatory asset to record the unrecovered
investment costs, including the unrecovered plant asset balance and the
unrecovered costs associated with site removal and closure associated with
future unit retirements caused by environmental regulations. The regulatory
asset is amortized and recovered over the affected unit's remaining useful life,
as established prior to the decision regarding early retirement, through Rate
CNP Compliance.
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Georgia Power
Georgia Power's revenues from regulated retail operations are collected through
various rate mechanisms subject to the oversight of the Georgia PSC. Georgia
Power currently recovers its costs from the regulated retail business through
the 2019 ARP, which includes traditional base tariffs, Demand-Side Management
(DSM) tariffs, the ECCR tariff, and Municipal Franchise Fee (MFF) tariffs. In
addition, financing costs on certified construction costs of Plant Vogtle Units
3 and 4 are being collected through the NCCR tariff and fuel costs are collected
through a fuel cost recovery tariff, both under separate regulatory proceedings.
See "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding" herein for
information regarding the approved recovery through retail base rates of certain
costs related to Plant Vogtle Unit 3 and the common facilities shared between
Plant Vogtle Units 3 and 4 (Common Facilities) that will become effective the
month after Unit 3 is placed in service. As costs are included in retail base
rates, the related financing costs will no longer be recovered through the NCCR
tariff. See "Nuclear Construction" herein for additional information on Plant
Vogtle Units 3 and 4.
Rate Plans
2019 ARP
In 2019, the Georgia PSC voted to approve the 2019 ARP, under which Georgia
Power increased its rates on January 1, 2020. In December 2020 and on November
18, 2021, the Georgia PSC approved tariff adjustments effective January 1, 2021
and 2022, respectively. Details of tariff adjustments are provided in the table
below:
Tariff 2020 2021 2022
(in millions)
Traditional base $ - $ 120 $ 192
ECCR(*) 318 2 (12)
DSM 12 (15) (25)
MFF 12 4 2
Total $ 342 $ 111 $ 157
(*) Effective January 1, 2020, CCR AROs are being recovered through the ECCR tariff.
In 2019, the Georgia PSC voted to approve Georgia Power's modified triennial IRP
(Georgia Power 2019 IRP), including Georgia Power's proposed environmental
compliance strategy associated with ash pond and certain landfill closures and
post-closure care in compliance with the CCR Rule and the related state rule. In
the 2019 ARP, the Georgia PSC approved recovery of the estimated under recovered
balance of these compliance costs at December 31, 2019 over a three-year period
ending December 31, 2022 and recovery of estimated compliance costs for 2020,
2021, and 2022 over three-year periods ending December 31, 2022, 2023, and 2024,
respectively, with recovery of construction contingency beginning in the year
following actual expenditure. The ECCR tariff is revised for actual expenditures
and updated estimates through annual compliance filings. Effective January 1,
2021 and 2022, Georgia Power adjusted its amortization of costs associated with
CCR AROs by an approximate decrease of $90 million and increase of $10 million,
respectively, as approved by the Georgia PSC in conjunction with Georgia Power's
annual compliance filings. See "Integrated Resource Plan" herein for additional
information.
In February 2020, the Georgia PSC denied a motion for reconsideration filed by
the Sierra Club regarding the Georgia PSC's decision in the 2019 ARP allowing
Georgia Power to recover compliance costs for CCR AROs. The Superior Court of
Fulton County subsequently affirmed the Georgia PSC's decision and, on October
25, 2021, the Georgia Court of Appeals affirmed the Superior Court of Fulton
County's order. On December 6, 2021, the Sierra Club filed a petition for writ
of certiorari to the Georgia Supreme Court. The ultimate outcome of this matter
cannot be determined at this time. See Note 6 for additional information
regarding Georgia Power's AROs.
Under the 2019 ARP, Georgia Power's retail ROE is set at 10.50%, and earnings
will be evaluated against a retail ROE range of 9.50% to 12.00%. Any retail
earnings above 12.00% will be shared, with 40% being applied to reduce
regulatory assets, 40% directly refunded to customers, and the remaining 20%
retained by Georgia Power. There will be no recovery of any earnings shortfall
below 9.50% on an actual basis. However, if at any time during the term of the
2019 ARP, Georgia Power projects that its retail earnings will be below 9.50%
for any calendar year, it could petition the Georgia PSC for implementation of
the Interim Cost Recovery (ICR) tariff to adjust Georgia Power's retail rates to
achieve a 9.50% ROE. The Georgia PSC would have 90 days to rule on Georgia
Power's request. The ICR tariff would expire at the earlier of January 1, 2023
or the end of the calendar year in which the ICR tariff becomes effective. In
lieu of requesting implementation of an ICR tariff, or if the Georgia PSC
chooses not to implement the ICR tariff, Georgia Power may file a full rate
case. In 2020, Georgia Power's retail ROE was within the allowed
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retail ROE range. In 2021, Georgia Power's retail ROE exceeded 12.00%, and Georgia Power reduced regulatory assets by approximately $5 million and accrued approximately $5 million to refund to customers in 2022, subject to review and approval by the Georgia PSC. Additionally, under the 2019 ARP and pursuant to the sharing mechanism approved in the 2013 ARP whereby two-thirds of any earnings above the top of the allowed ROE range are shared with Georgia Power's customers, (i) Georgia Power used 50% (approximately $50 million) of the customer share of earnings above the band in 2018 to reduce regulatory assets and refunded 50% (approximately $50 million) to customers in 2020 and (ii) Georgia Power agreed to forego its share of 2019 earnings in excess of the earnings band so 50% (approximately $60 million) of all earnings over the 2019 band were refunded to customers in 2020 and 50% (approximately $60 million) were used to reduce regulatory assets. Georgia Power is required to file a general base rate case by July 1, 2022, in response to which the Georgia PSC would be expected to determine whether the 2019 ARP should be continued, modified, or discontinued.
2013 ARP
Georgia Power's retail ROE under the 2013 ARP was set at 10.95% and earnings were evaluated against a retail ROE range of 10.00% to 12.00%. Two-thirds of any earnings above 12.00% were to be directly refunded to customers, with the remaining one-third retained by Georgia Power. In 2019 and 2018, Georgia Power's retail ROE exceeded 12.00% and, under the modified sharing mechanism pursuant to the 2019 ARP, Georgia Power reduced regulatory assets by a total of approximately $110 million and accrued approximately $110 million for retail customer refunds through bill credits that were completed in 2020. See "2019 ARP" herein for additional information.
Plant Vogtle Unit 3 and Common Facilities Rate Proceeding
On June 15, 2021, Georgia Power filed an application with the Georgia PSC to adjust retail base rates to include the portion of costs related to its investment in Plant Vogtle Unit 3 and Common Facilities previously deemed prudent by the Georgia PSC, as well as the related costs of operation. On November 2, 2021, the Georgia PSC voted to approve Georgia Power's application as filed, with the following modifications pursuant to a stipulated agreement between Georgia Power and the staff of the Georgia PSC. Georgia Power will include in rate base an allocation of $2.1 billion to Unit 3 and Common Facilities from the $3.6 billion of Plant Vogtle Units 3 and 4 previously deemed prudent by the Georgia PSC and will recover the related depreciation expense through retail base rates effective the month after Unit 3 is placed in service. Financing costs on the remaining portion of the total Unit 3 and the Common Facilities construction costs will continue to be recovered through the NCCR tariff or deferred. Georgia Power will defer as a regulatory asset the remaining depreciation expense (approximately $38 million annually) until Unit 4 costs are placed in retail base rates. In addition, the stipulated agreement clarified that following the prudency review, the remaining amount to be placed in retail base rates will be net of the proceeds from the Guarantee Settlement Agreement and will not be used to offset imprudent costs, if any. The related increase in annual retail base rates of approximately $302 million also includes recovery of all projected operations and maintenance expenses for Unit 3 and the Common Facilities and other related costs of operation, partially offset by the related production tax credits, and will become effective the month after Unit 3 is placed in service. This increase is partially offset by a decrease in the NCCR tariff of approximately $78 million effective January 1, 2022. As approved by the Georgia PSC, the increase in annual retail base rates will be adjusted based on the actual in-service date of Plant Vogtle Unit 3.
See "Nuclear Construction" herein for additional information on Plant Vogtle Units 3 and 4.
Integrated Resource Plan
In 2021, as authorized in its 2019 IRP, Georgia Power requested and received
certification from the Georgia PSC for 970 MWs of utility-scale PPAs for solar
generation resources, which are expected to be in operation by the end of 2023.
On January 31, 2022, Georgia Power filed its triennial IRP (2022 IRP). The
filing included a request to decertify and retire Plant Wansley Units 1 and 2
(926 MWs based on 53.5% ownership) by August 31, 2022; Plant Bowen Units 1 and 2
(1,400 MWs) by December 31, 2027; and Plant Scherer Unit 3 (614 MWs based on 75%
ownership) and Plant Gaston Units 1 through 4 (500 MWs based on 50% ownership
through SEGCO) by December 31, 2028. See Note 7 under "SEGCO" for additional
information.
In the 2022 IRP, Georgia Power requested approval to reclassify the remaining
net book value of Plant Wansley Units 1 and 2 (approximately $610 million at
December 31, 2021), Plant Bowen Units 1 and 2 (approximately $937 million at
December 31, 2021), and Plant Scherer Unit 3 (approximately $622 million at
December 31, 2021) and any remaining unusable materials and supplies inventories
upon each unit's respective retirement dates to a regulatory asset, with
recovery periods to be determined in future base rate cases.
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In addition, the 2022 IRP includes requests for approval of the following:
•Capital, operations and maintenance, and CCR ARO costs associated with ash pond and landfill closures and post-closure care. The recovery of these costs is expected to be determined in future base rate cases;
•Installation of environmental controls at Plant Bowen Units 3 and 4 (1,760 MWs) and Plant Scherer Units 1 and 2 (137 MWs based on 8.4% ownership) for compliance with ELG rules;
•Investments related to the hydro operations of Plants Sinclair (45 MWs), North Highlands (30 MWs), and Burton (6 MWs);
•Establishment of a request for proposals (RFP) process for 2,300 MWs of renewable resources by 2029. Georgia Power expects to request an additional 3,700 MWs by 2035 through future IRP proceedings;
•Procurement of 1,000 MWs of Georgia Power-owned storage resources by 2030, including the development of a 265-MW battery energy storage facility beginning in 2026;
•Related transmission costs necessary to support the proposed retirements and renewable resources previously described;
•Certification of six PPAs (including five affiliate PPAs with Southern Power that are also subject to approval by the FERC) with capacities of 1,567 MWs beginning in 2024, 380 MWs beginning in 2025, and 228 MWs beginning in 2028, procured through RFPs approved through the 2019 IRP; and
•Certification of approximately 88 MWs of wholesale capacity to be placed in retail rate base between January 1, 2024 and January 1, 2025.
A decision from the Georgia PSC on the 2022 IRP is expected in July 2022. The ultimate outcome of these matters cannot be determined at this time.
Deferral of Incremental COVID-19 Costs
In April 2020 and June 2020, in response to the COVID-19 pandemic, the Georgia
PSC approved orders directing Georgia Power to continue its previous, voluntary
suspension of customer disconnections through July 14, 2020 and to defer the
resulting incremental bad debt as a regulatory asset. In June 2020 and July
2020, the Georgia PSC approved orders establishing a methodology for identifying
incremental bad debt and allowing the deferral of other incremental costs
associated with the COVID-19 pandemic. At December 31, 2020, the incremental
costs deferred totaled approximately $38 million (including approximately
$23 million of incremental bad debt costs and $15 million of other incremental
costs). Since June 2021, Georgia Power has continued a review of bad debt
amounts deferred under the Georgia PSC-approved methodology, including
consideration of actual amounts repaid by customers from arrears and installment
plans after the disconnection moratorium period ended. As a result, Georgia
Power's incremental costs deferred at December 31, 2021 totaled approximately
$21 million, including an immaterial amount of incremental bad debt costs. The
period over which these costs will be recovered is expected to be determined in
Georgia Power's next base rate case. The ultimate outcome of this matter cannot
be determined at this time.
Fuel Cost Recovery
Georgia Power has established fuel cost recovery rates approved by the Georgia
PSC. In May 2020, the Georgia PSC approved a stipulation agreement among Georgia
Power, the staff of the Georgia PSC, and certain intervenors to lower total fuel
billings by approximately $740 million over a two-year period effective June 1,
2020. In addition, Georgia Power further lowered fuel billings by approximately
$44 million under an interim fuel rider effective June 1, 2020 through September
30, 2020. During the second half of 2021, the price of natural gas rose
significantly and resulted in an under recovered fuel balance exceeding $200
million. Therefore, on November 18, 2021, the Georgia PSC voted to approve
Georgia Power's interim fuel rider, which increased fuel rates by 15%, or
approximately $252 million annually, effective January 1, 2022. Georgia Power
continues to be allowed to adjust its fuel cost recovery rates under an interim
fuel rider prior to the next fuel case if the over recovered fuel balance
exceeds $200 million. Georgia Power is scheduled to file its next fuel case no
later than February 28, 2023.
Georgia Power's under recovered fuel balance totaled $410 million at
December 31, 2021 and is included in other deferred charges and assets on
Southern Company's balance sheet and deferred under recovered fuel clause
revenues on Georgia Power's balance sheet. At December 31, 2020, Georgia Power's
over recovered fuel balance totaled $113 million and is included in other
current liabilities on Southern Company's balance sheet and over recovered fuel
clause revenues on Georgia Power's balance sheet.
Georgia Power's fuel cost recovery mechanism includes costs associated with a
natural gas hedging program, as revised and approved by the Georgia PSC,
allowing the use of an array of derivative instruments within a 36-month time
horizon.
Fuel cost recovery revenues as recorded on the financial statements are adjusted
for differences in actual recoverable fuel costs and amounts billed in current
regulated rates. Accordingly, changes in the billing factor will not have a
significant effect on Southern Company's or Georgia Power's revenues or net
income but will affect operating cash flows.
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Storm Damage Recovery
Georgia Power defers and recovers certain costs related to damages from major storms as mandated by the Georgia PSC. Beginning January 1, 2020, Georgia Power is recovering $213 million annually under the 2019 ARP. At December 31, 2021 and 2020, the balance in the regulatory asset related to storm damage was $48 million and $262 million, respectively, with $48 million and $213 million, respectively, included in other regulatory assets, current on Southern Company's balance sheets and regulatory assets - storm damage on Georgia Power's balance sheets and $49 million at December 31, 2020 included in other regulatory assets, deferred on Southern Company's and Georgia Power's balance sheets. The rate of storm damage cost recovery is expected to be adjusted in future regulatory proceedings as necessary. As a result of this regulatory treatment, costs related to storms are not expected to have a material impact on Southern Company's or Georgia Power's financial statements.
Nuclear Construction
In 2009, the Georgia PSC certified construction of Plant Vogtle Units 3 and 4, in which Georgia Power holds a 45.7% ownership interest. In 2012, the NRC issued the related combined construction and operating licenses, which allowed full construction of the two AP1000 nuclear units (with electric generating capacity of approximately 1,100 MWs each) and related facilities to begin. Until March 2017, construction on Plant Vogtle Units 3 and 4 continued under the Vogtle 3 and 4 Agreement, which was a substantially fixed price agreement. In connection with the EPC Contractor's bankruptcy filing in March 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into several transitional arrangements to allow construction to continue. In July 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, entered into the Vogtle Services Agreement, whereby Westinghouse provides facility design and engineering services, procurement and technical support, and staff augmentation on a time and materials cost basis. The Vogtle Services Agreement provides that it will continue until the start-up and testing of Plant Vogtle Units 3 and 4 are complete and electricity is generated and sold from both units. The Vogtle Services Agreement is terminable by the Vogtle Owners upon 30 days' written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Vogtle Owners, executed the Bechtel Agreement, a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Vogtle Owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Vogtle Owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Vogtle Owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs, and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Vogtle Owner suspensions of work, certain breaches of the Bechtel Agreement by the Vogtle Owners, Vogtle Owner insolvency, and certain other events.
See Note 8 under "Long-term Debt - DOE Loan Guarantee Borrowings" for information on the Amended and Restated Loan Guarantee Agreement, including applicable covenants, events of default, and mandatory prepayment events.
Cost and Schedule
Georgia Power's approximate proportionate share of the remaining estimated capital cost to complete Plant Vogtle Units 3 and 4, including contingency, through the end of the first quarter 2023 and the fourth quarter 2023, respectively, is as follows:
(in millions)
Base project capital cost forecast(a)(b) $ 10,251
Construction contingency estimate 150
Total project capital cost forecast(a)(b) 10,401
Net investment at December 31, 2021(b) (8,442)
Remaining estimate to complete $ 1,959
(a)Includes approximately $590 million of costs that are not shared with the
other Vogtle Owners and approximately $440 million of incremental costs under
the cost-sharing and tender provisions of the joint ownership agreements
described below. Excludes financing costs expected to be capitalized through
AFUDC of approximately $375 million, of which $195 million had been accrued
through December 31, 2021.
(b)Net of $1.7 billion received from Toshiba under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds.
Georgia Power estimates that its financing costs for construction of Plant Vogtle Units 3 and 4 will total approximately $3.4 billion, of which $2.9 billion had been incurred through December 31, 2021.
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As part of its ongoing processes, Southern Nuclear continues to evaluate cost
and schedule forecasts on a regular basis to incorporate current information
available, particularly in the areas of engineering support, commodity
installation, system turnovers and related test results, and workforce
statistics. Southern Nuclear establishes aggressive target values for monthly
construction production and system turnover activities, which are reflected in
the site work plans.
In mid-March 2020, Southern Nuclear began implementing policies and procedures
designed to mitigate the risk of transmission of COVID-19 at the construction
site, including worker distancing measures; isolating individuals who tested
positive for COVID-19, showed symptoms consistent with COVID-19, were being
tested for COVID-19, or were in close contact with such persons; requiring
self-quarantine; and adopting additional precautionary measures. Since March
2020, the number of active cases at the site has fluctuated consistent with the
surrounding area and impacted productivity levels and pace of activity
completion, with the site experiencing peaks in the number of active cases in
January 2021, August 2021, and January 2022. Georgia Power estimates the
productivity impacts of the COVID-19 pandemic have consumed approximately three
to four months of schedule margin previously embedded in the site work plan for
Unit 3 and Unit 4. Georgia Power's proportionate share of the estimated
incremental cost associated with COVID-19 mitigation actions and impacts on
construction productivity is currently estimated to be between $160 million and
$200 million and is included in the total project capital cost forecast. The
continuing effects of the COVID-19 pandemic could further disrupt or delay
construction and testing activities at Plant Vogtle Units 3 and 4.
During 2021, Southern Nuclear performed additional construction remediation work
necessary to ensure quality and design standards are met and support system
turnovers necessary for Unit 3 hot functional testing, which was completed in
July 2021, and fuel load. As a result of Unit 3 challenges including, but not
limited to, construction productivity, construction remediation work, the pace
of system turnovers, spent fuel pool repairs, and the timeframe and duration for
hot functional and other testing, at the end of each of the second and third
quarters 2021, Southern Nuclear further extended certain milestone dates,
including fuel load for Unit 3, from those established in January 2021. Through
the fourth quarter 2021, the project continued to face these and other
challenges related to the completion of documentation, including inspection
records, necessary to submit the remaining ITAACs and begin fuel load. As a
result, at the end of the fourth quarter 2021, Southern Nuclear further extended
certain milestone dates, including fuel load for Unit 3, from those established
at the end of the third quarter 2021. The site work plan currently targets fuel
load for Unit 3 in the second quarter 2022 and an in-service date during the
third quarter 2022 and primarily depends on significant improvements in overall
construction productivity and production levels, the volume of construction
remediation work, the pace of system and area turnovers, and the progression of
startup and other testing. As the site work plan includes minimal margin to
these milestone dates, an in-service date during the fourth quarter 2022 or the
first quarter 2023 for Unit 3 is projected, although any further delays could
result in a later in-service date.
As the result of productivity challenges and temporarily diverting some Unit 4
craft and support resources to Unit 3 construction efforts, at the end of each
of the second and third quarters 2021, Southern Nuclear also further extended
milestone dates for Unit 4 from those established in January 2021. The temporary
diversion of Unit 4 resources to support Unit 3 has continued into the first
quarter 2022; therefore, at the end of the fourth quarter 2021, Southern Nuclear
further extended milestone dates for Unit 4 from those established at the end of
the third quarter 2021. The site work plan targets an in-service date during the
first quarter 2023 for Unit 4 and primarily depends on overall construction
productivity and production levels significantly improving as well as
appropriate levels of craft laborers, particularly electricians and pipefitters,
being added and maintained. As the site work plan includes minimal margin to the
milestone dates, an in-service date during the third or fourth quarter 2023 for
Unit 4 is projected, although any further delays could result in a later
in-service date.
During 2021, established construction contingency and additional costs totaling
$1.3 billion were assigned to the base capital cost forecast for costs primarily
associated with schedule extensions, construction productivity, the pace of
system turnovers, and support resources for Units 3 and 4. Georgia Power also
increased its total capital cost forecast as of December 31, 2021 by $99 million
to replenish construction contingency.
After considering the significant level of uncertainty that exists regarding the
future recoverability of these costs since the ultimate outcome of these matters
is subject to the outcome of future assessments by management, as well as
Georgia PSC decisions in future regulatory proceedings, Georgia Power recorded
pre-tax charges to income in the first quarter 2021, the second quarter 2021,
the third quarter 2021, and the fourth quarter 2021 of $48 million ($36 million
after tax), $460 million ($343 million after tax), $264 million ($197 million
after tax), and $480 million ($358 million after tax), respectively, for the
increases in the total project capital cost forecast. Georgia Power may request
the Georgia PSC to evaluate those expenditures for rate recovery during the
prudence review following the Unit 4 fuel load pursuant to the twenty-fourth VCM
stipulation described below. In addition, Georgia Power recorded a pre-tax
charge to income in the fourth quarter 2021 of approximately $440 million ($328
million after tax) for incremental costs, which will not be recovered from
retail customers, associated with the cost-sharing and tender provisions of the
joint ownership agreements described below.
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As Unit 3 completes system turnover from construction and moves to testing and transition to operations, ongoing and potential future challenges include completion of construction remediation work, completion of work packages, including inspection records, and other documentation necessary to submit the remaining ITAACs and begin fuel load, and final component and pre-operational tests. As Unit 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical installation, availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit 3 construction efforts, and the pace of work package closures and system turnovers. As construction, including subcontract work, continues on both Units 3 and 4, ongoing or future challenges include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; and procurement and related installation. New challenges may arise, particularly as Units 3 and 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures, or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale). The ongoing and potential future challenges described above may change the projected schedule and estimated cost. There have been technical and procedural challenges to the construction and licensing of Plant Vogtle Units 3 and 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the NRC that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project's construction quality programs and, where needed, is implementing improvement plans consistent with these processes. On November 17, 2021, the NRC issued the final significance report on its special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans with two findings of low to moderate safety significance. Southern Nuclear had already identified and self-reported many of the issues in this report to the NRC and implemented corrective-action plans to resolve these issues. The NRC will conduct a follow-up inspection on these findings at a future date. Findings resulting from this or other inspections could require additional remediation and/or further NRC oversight. In addition, certain license amendment requests have been filed and approved or are pending before the NRC. The site work plan currently targets fuel load for Units 3 and 4 in the second quarter 2022 and the fourth quarter 2022, respectively. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the ITAAC documentation for each unit and the related reviews and approvals by the NRC necessary to support NRC authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections and ITAACs, are not resolved in a timely manner, there may be delays in the project schedule that could result in increased costs. The ultimate outcome of these matters cannot be determined at this time. However, any extension of the in-service date beyond the first quarter 2023 for Unit 3 or the fourth quarter 2023 for Unit 4, including the current level of cost sharing described below, is estimated to result in additional base capital costs for Georgia Power of up to $60 million per month for Unit 3 and $40 million per month for Unit 4, as well as the related AFUDC and any additional related construction, support resources, or testing costs. While Georgia Power is not precluded from seeking retail recovery of any future capital cost forecast increase other than the amounts related to the cost-sharing and tender provisions of the joint ownership agreements described below, management will ultimately determine whether or not to seek recovery. Any further changes to the capital cost forecast that are not expected to be recoverable through regulated rates will be required to be charged to income and such charges could be material.
Joint Owner Contracts
In November 2017, the Vogtle Owners entered into an amendment to their joint
ownership agreements for Plant Vogtle Units 3 and 4 to provide for, among other
conditions, additional Vogtle Owner approval requirements. Effective in August
2018, the Vogtle Owners further amended the joint ownership agreements to
clarify and provide procedures for certain provisions of the joint ownership
agreements related to adverse events that require the vote of the holders of at
least 90% of the ownership interests in Plant Vogtle Units 3 and 4 to continue
construction (as amended, and together with the November 2017 amendment, the
Vogtle Joint Ownership Agreements). The Vogtle Joint Ownership Agreements also
confirm that the Vogtle Owners' sole recourse against Georgia Power or Southern
Nuclear for any action or inaction in connection with their performance as agent
for the Vogtle Owners is limited to removal of Georgia Power and/or Southern
Nuclear as agent, except in cases of willful misconduct.
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Amendments to the Vogtle Joint Ownership Agreements
In connection with a September 2018 vote by the Vogtle Owners to continue
construction, Georgia Power entered into (i) a binding term sheet (Vogtle Owner
Term Sheet) with the other Vogtle Owners and MEAG Power's wholly-owned
subsidiaries MEAG Power SPVJ, LLC (MEAG SPVJ), MEAG Power SPVM, LLC (MEAG SPVM),
and MEAG Power SPVP, LLC (MEAG SPVP) to take certain actions which partially
mitigate potential financial exposure for the other Vogtle Owners, including
additional amendments to the Vogtle Joint Ownership Agreements and the purchase
of PTCs from the other Vogtle Owners at pre-established prices, and (ii) a term
sheet (MEAG Term Sheet) with MEAG Power and MEAG SPVJ to provide up to $300
million of funding with respect to MEAG SPVJ's ownership interest in Plant
Vogtle Units 3 and 4 under certain circumstances. In January 2019, Georgia
Power, MEAG Power, and MEAG SPVJ entered into an agreement to implement the
provisions of the MEAG Term Sheet. In February 2019, Georgia Power, the other
Vogtle Owners, and MEAG Power's wholly-owned subsidiaries MEAG SPVJ, MEAG SPVM,
and MEAG SPVP entered into certain amendments to the Vogtle Joint Ownership
Agreements to implement the provisions of the Vogtle Owner Term Sheet (Global
Amendments).
Pursuant to the Global Amendments: (i) each Vogtle Owner must pay its
proportionate share of qualifying construction costs for Plant Vogtle Units 3
and 4 based on its ownership percentage up to the estimated cost at completion
(EAC) for Plant Vogtle Units 3 and 4 which formed the basis of Georgia Power's
forecast of $8.4 billion in the nineteenth VCM plus $800 million; (ii) Georgia
Power will be responsible for 55.7% of actual qualifying construction costs
between $800 million and $1.6 billion over the EAC in the nineteenth VCM
(resulting in $80 million of potential additional costs to Georgia Power), with
the remaining Vogtle Owners responsible for 44.3% of such costs pro rata in
accordance with their respective ownership interests; and (iii) Georgia Power
will be responsible for 65.7% of qualifying construction costs between $1.6
billion and $2.1 billion over the EAC in the nineteenth VCM (resulting in a
further $100 million of potential additional costs to Georgia Power), with the
remaining Vogtle Owners responsible for 34.3% of such costs pro rata in
accordance with their respective ownership interests. If the EAC is revised and
exceeds the EAC in the nineteenth VCM by more than $2.1 billion, each of the
other Vogtle Owners will have a one-time option at the time the project budget
forecast is so revised to tender a portion of its ownership interest to Georgia
Power in exchange for Georgia Power's agreement to pay 100% of such Vogtle
Owner's remaining share of total construction costs in excess of the EAC in the
nineteenth VCM plus $2.1 billion.
In addition, pursuant to the Global Amendments, the holders of at least 90% of
the ownership interests in Plant Vogtle Units 3 and 4 must vote to continue
construction if certain adverse events occur, including, among other events: (i)
the bankruptcy of Toshiba; (ii) the termination or rejection in bankruptcy of
certain agreements, including the Vogtle Services Agreement, the Bechtel
Agreement, or the agency agreement with Southern Nuclear; (iii) Georgia Power's
public announcement of its intention not to submit for rate recovery any portion
of its investment in Plant Vogtle Units 3 and 4 or the Georgia PSC determines
that any of Georgia Power's costs relating to the construction of Plant Vogtle
Units 3 and 4 will not be recovered in retail rates, excluding any additional
amounts paid by Georgia Power on behalf of the other Vogtle Owners pursuant to
the Global Amendments described above and the first 6% of costs during any
six-month VCM reporting period that are disallowed by the Georgia PSC for
recovery, or for which Georgia Power elects not to seek cost recovery, through
retail rates; and (iv) an incremental extension of one year or more from the
seventeenth VCM report estimated in-service dates of November 2021 and November
2022 for Units 3 and 4, respectively. The latest schedule extension triggers the
requirement that the holders of at least 90% of the ownership interests in Plant
Vogtle Units 3 and 4 must vote to continue construction by March 8, 2022.
Georgia Power has voted to continue construction. In addition, if the holders of
at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 do not
vote to continue construction, the DOE may require Georgia Power to prepay all
outstanding borrowings under the FFB Credit Facilities over a period of five
years. See Note 8 under "Long-term Debt - DOE Loan Guarantee Borrowings" for
additional information.
Georgia Power and the other Vogtle Owners do not agree on either the starting
dollar amount for the determination of cost increases subject to the
cost-sharing and tender provisions of the Global Amendments or the extent to
which COVID-19-related costs impact the calculation. Based on the definition in
the Global Amendments, Georgia Power believes the starting dollar amount is
$18.38 billion and the current project capital cost forecast has triggered the
cost-sharing provisions. The other Vogtle Owners have asserted that the project
cost increases have reached the cost-sharing thresholds and have triggered the
tender provisions under the Global Amendments. Georgia Power recorded an
additional pre-tax charge to income in the fourth quarter 2021 of approximately
$440 million ($328 million after tax) associated with these cost-sharing and
tender provisions, which is included in the total project capital cost forecast.
Georgia Power may be required to record further pre-tax charges to income of up
to approximately $460 million associated with these provisions based on the
current project capital cost forecast. The incremental charges associated with
these provisions will not be recovered from retail customers. On October 29,
2021, Georgia Power and the other Vogtle Owners entered into an agreement to
clarify the process for the tender provisions of the Global Amendments to
provide for a decision between 120 and 180 days after the tender option is
triggered, which the other Vogtle Owners assert occurred on February 14, 2022.
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Georgia Power's ownership interest in Plant Vogtle Units 3 and 4 continues to be 45.7%; however, it could increase if one or more of the other Vogtle Owners exercise the option to tender a portion of their ownership interest to Georgia Power and require Georgia Power to pay 100% of the remaining share of the costs necessary to complete Plant Vogtle Units 3 and 4. Georgia Power's incremental ownership interest would be calculated and conveyed to Georgia Power after Plant Vogtle Units 3 and 4 are placed in service.
The ultimate outcome of these matters cannot be determined at this time.
Regulatory Matters
In 2009, the Georgia PSC voted to certify construction of Plant Vogtle Units 3
and 4 with a certified capital cost of $4.418 billion. In addition, in 2009 the
Georgia PSC approved inclusion of the Plant Vogtle Units 3 and 4 related CWIP
accounts in rate base, and the State of Georgia enacted the Georgia Nuclear
Energy Financing Act, which allows Georgia Power to recover financing costs for
Plant Vogtle Units 3 and 4. Financing costs are recovered on all applicable
certified costs through annual adjustments to the NCCR tariff up to the
certified capital cost of $4.418 billion. At December 31, 2021, Georgia Power
had recovered approximately $2.7 billion of financing costs. Financing costs
related to capital costs above $4.418 billion are being recognized through AFUDC
and are expected to be recovered through retail rates over the life of Plant
Vogtle Units 3 and 4; however, Georgia Power is not recording AFUDC related to
any capital costs in excess of the total deemed reasonable by the Georgia PSC
(currently $7.3 billion) and not requested for rate recovery. On November 18,
2021, the Georgia PSC approved Georgia Power's request to decrease the NCCR
tariff by $78 million annually, effective January 1, 2022.
Georgia Power is required to file semi-annual VCM reports with the Georgia PSC
by February 28 and August 31 of each year. In 2013, in connection with the
eighth VCM report, the Georgia PSC approved a stipulation between Georgia Power
and the staff of the Georgia PSC to waive the requirement to amend the Plant
Vogtle Units 3 and 4 certificate in accordance with the 2009 certification order
until the completion of Plant Vogtle Unit 3, or earlier if deemed appropriate by
the Georgia PSC and Georgia Power.
In 2016, the Georgia PSC voted to approve a settlement agreement (Vogtle Cost
Settlement Agreement) resolving certain prudency matters in connection with the
fifteenth VCM report. In December 2017, the Georgia PSC voted to approve (and
issued its related order on January 11, 2018) Georgia Power's seventeenth VCM
report and modified the Vogtle Cost Settlement Agreement. The Vogtle Cost
Settlement Agreement, as modified by the January 11, 2018 order, resolved the
following regulatory matters related to Plant Vogtle Units 3 and 4: (i) none of
the $3.3 billion of costs incurred through December 31, 2015 and reflected in
the fourteenth VCM report should be disallowed from rate base on the basis of
imprudence; (ii) the Contractor Settlement Agreement was reasonable and prudent
and none of the $0.3 billion paid pursuant to the Contractor Settlement
Agreement should be disallowed from rate base on the basis of imprudence; (iii)
(a) capital costs incurred up to $5.68 billion would be presumed to be
reasonable and prudent with the burden of proof on any party challenging such
costs, (b) Georgia Power would have the burden to show that any capital costs
above $5.68 billion were prudent, and (c) a revised capital cost forecast of
$7.3 billion (after reflecting the impact of payments received under the
Guarantee Settlement Agreement and related customer refunds) was found
reasonable; (iv) construction of Plant Vogtle Units 3 and 4 should be completed,
with Southern Nuclear serving as project manager and Bechtel as primary
contractor; (v) approved and deemed reasonable Georgia Power's revised schedule
placing Plant Vogtle Units 3 and 4 in service in November 2021 and November
2022, respectively; (vi) confirmed that the revised cost forecast does not
represent a cost cap and that a prudence proceeding on cost recovery will occur
following Unit 4 fuel load, consistent with applicable Georgia law; (vii)
reduced the ROE used to calculate the NCCR tariff (a) from 10.95% (the ROE rate
setting point authorized by the Georgia PSC in the 2013 ARP) to 10.00% effective
January 1, 2016, (b) from 10.00% to 8.30%, effective January 1, 2020, and (c)
from 8.30% to 5.30%, effective January 1, 2021 (provided that the ROE in no case
will be less than Georgia Power's average cost of long-term debt); (viii)
reduced the ROE used for AFUDC equity for Plant Vogtle Units 3 and 4 from 10.00%
to Georgia Power's average cost of long-term debt, effective January 1, 2018;
and (ix) agreed that effective the first month after Unit 3 reaches commercial
operation, retail base rates would be adjusted to include the costs related to
Unit 3 and common facilities deemed prudent in the Vogtle Cost Settlement
Agreement (see "Plant Vogtle Unit 3 and Common Facilities Rate Proceeding"
herein for additional information). The January 11, 2018 order also stated that
if Plant Vogtle Units 3 and 4 are not commercially operational by June 1, 2021
and June 1, 2022, respectively, the ROE used to calculate the NCCR tariff will
be further reduced by 10 basis points each month (but not lower than Georgia
Power's average cost of long-term debt) until the respective Unit is
commercially operational. The ROE reductions negatively impacted earnings by
approximately $270 million, $150 million, and $75 million in 2021, 2020, and
2019, respectively, and are estimated to have negative earnings impacts of
approximately $300 million and $265 million in 2022 and 2023, respectively. In
its January 11, 2018 order, the Georgia PSC also stated if other conditions
change and assumptions upon which Georgia Power's seventeenth VCM report are
based do not materialize, the Georgia PSC reserved the right to reconsider the
decision to continue construction.
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The Georgia PSC has approved 24 VCM reports covering periods through December 31, 2020, including total construction capital costs incurred through December 31, 2020 of $7.3 billion (net of $1.7 billion of payments received under the Guarantee Settlement Agreement and approximately $188 million in related customer refunds). In the August 24, 2021 order approving the twenty-fourth VCM report, the Georgia PSC also approved a stipulation addressing the following matters: (i) beginning with its twenty-fifth VCM report, Georgia Power will continue to report to the Georgia PSC all costs incurred during the period for review and will request for approval costs up to the $7.3 billion determined to be reasonable in the Georgia PSC's seventeenth VCM order and (ii) Georgia Power will not seek rate recovery of the $0.7 billion increase to the base capital cost forecast included in the nineteenth VCM report and charged to income by Georgia Power in the second quarter 2018. In addition, the stipulation confirms Georgia Power may request verification and approval of costs above $7.3 billion for inclusion in rate base at a later time, but no earlier than the prudence review contemplated by the seventeenth VCM order described previously. The Georgia PSC is scheduled to vote on the twenty-fifth VCM report on February 17, 2022. Georgia Power also expects to file its twenty-sixth VCM report with the Georgia PSC on February 17, 2022, which will reflect the revised capital cost forecast described above.
The ultimate outcome of these matters cannot be determined at this time.
Mississippi Power
Mississippi Power's rates and charges for service to retail customers are subject to the regulatory oversight of the Mississippi PSC. Mississippi Power's rates are a combination of base rates and several separate cost recovery clauses for specific categories of costs. These separate cost recovery clauses address such items as fuel and purchased power, ad valorem taxes, property damage, and the costs of compliance with environmental laws and regulations. Costs not addressed through one of the specific cost recovery clauses are expected to be recovered through Mississippi Power's base rates.
2019 Base Rate Case
In March 2020, the Mississippi PSC approved a settlement agreement between Mississippi Power and the Mississippi Public Utilities Staff related to Mississippi Power's base rate case filed in 2019 (Mississippi Power Rate Case Settlement Agreement).
Under the terms of the Mississippi Power Rate Case Settlement Agreement, annual retail rates decreased approximately $16.7 million, or 1.85%, effective for the first billing cycle of April 2020, based on a test year period of January 1, 2020 through December 31, 2020, a 53% average equity ratio, an allowed maximum actual equity ratio of 55% by the end of 2020, and a 7.57% return on investment. Additionally, the Mississippi Power Rate Case Settlement Agreement: (i) established common amortization periods of four years for regulatory assets and three years for regulatory liabilities included in the approved revenue requirement, including those related to unprotected deferred income taxes; (ii) established new depreciation rates reflecting an annual increase in depreciation of approximately $10 million; and (iii) excluded certain compensation costs totaling approximately $3.9 million. It also eliminated separate rates for costs associated with Plant Ratcliffe and energy efficiency initiatives and includes such costs in the PEP, ECO Plan, and ad valorem tax adjustment factor, as applicable.
Performance Evaluation Plan
Mississippi Power's retail base rates generally are set under the PEP, a rate
plan approved by the Mississippi PSC. In recognition that Mississippi Power's
long-term financial success is dependent upon how well it satisfies its
customers' needs, PEP includes performance indicators that directly tie customer
service indicators to Mississippi Power's allowed ROE. PEP measures Mississippi
Power's performance on a 10-point scale as a weighted average of results in
three areas: average customer price, as compared to prices of other regional
utilities (weighted at 40%); service reliability, measured in percentage of time
customers had electric service (40%); and customer satisfaction, measured in a
survey of residential customers (20%). Typically, two PEP filings are made for
each calendar year: the PEP projected filing and the PEP lookback filing. In
July 2020, the Mississippi PSC approved Mississippi Power's revisions to the PEP
compliance rate clause as agreed to in the Mississippi Power Rate Case
Settlement Agreement. These revisions include, among other things, changing the
filing date for the annual PEP rate projected filing from November of the
immediately preceding year to March of the current year, utilizing a historic
test year adjusted for "known and measurable" changes, using discounted cash
flow and regression formulas to determine base ROE, and moving all embedded ad
valorem property taxes currently collected in PEP to the ad valorem tax
adjustment clause. The PEP lookback filing will continue to be filed after the
end of the year and allows for review of the actual revenue requirement.
Pursuant to a Mississippi PSC-approved settlement agreement between Mississippi
Power and the MPUS, Mississippi Power was not required to make any PEP filings
for regulatory years 2019 and 2020. On June 8, 2021, the Mississippi PSC
approved Mississippi Power's annual retail PEP filing for 2021, resulting in an
annual increase in revenues of approximately $16 million, or 1.8%, which became
effective with the first billing cycle of April 2021.
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Integrated Resource Plan
In 2019, Mississippi Power updated its proposed Reserve Margin Plan (RMP), originally filed in 2018, as required by the Mississippi PSC. In 2018, Mississippi Power had proposed alternatives to reduce its reserve margin and lower or avoid operating costs. In December 2020, the Mississippi PSC issued an order concluding the RMP docket and requiring Mississippi Power to incorporate into its 2021 IRP a schedule of early or anticipated retirement of 950 MWs of fossil-steam generation by year-end 2027 to reduce Mississippi Power's excess reserve margin. The order stated that Mississippi Power will be allowed to defer any retirement-related costs as regulatory assets for future recovery. On September 9, 2021, the Mississippi PSC issued an order confirming the conclusion of its review of Mississippi Power's 2021 IRP with no deficiencies identified. The 2021 IRP included a schedule to retire Plant Watson Unit 4 (268 MWs) and Mississippi Power's 40% ownership interest in Plant Greene County Units 1 and 2 (103 MWs each) in December 2023, 2025, and 2026, respectively, consistent with each unit's remaining useful life in the most recent approved depreciation studies. In addition, the schedule reflects the early retirement of Mississippi Power's 50% undivided ownership interest in Plant Daniel Units 1 and 2 (502 MWs) by the end of 2027. The Plant Greene County unit retirements require the completion by Alabama Power of transmission and system reliability improvements, as well as agreement by Alabama Power. The remaining net book value of Plant Daniel Units 1 and 2 was approximately $515 million at December 31, 2021 and Mississippi Power is continuing to depreciate these units using the current approved rates through the end of 2027. Mississippi Power expects to reclassify the net book value remaining at retirement, which is expected to total approximately $386 million, to a regulatory asset to be amortized over a period to be determined by the Mississippi PSC in future proceedings, consistent with the December 2020 order. The Plant Watson and Greene County units are expected to be fully depreciated upon retirement. The ultimate outcome of these matters cannot be determined at this time. See Note 3 under "Other Matters - Mississippi Power" for additional information on Plant Daniel Units 1 and 2.
Environmental Compliance Overview Plan
In accordance with a 2011 accounting order from the Mississippi PSC, Mississippi Power has the authority to defer in a regulatory asset for future recovery all plant retirement- or partial retirement-related costs resulting from environmental regulations. In accordance with a Mississippi PSC-approved settlement agreement between Mississippi Power and the MPUS, Mississippi Power was not required to make any ECO Plan filings for 2019 and 2020, and any necessary adjustments were reflected in Mississippi Power's 2019 base rate case. In 2019, the Mississippi PSC approved Mississippi Power's request for a CPCN to complete certain environmental compliance projects, primarily associated with the Plant Daniel coal units co-owned 50% with Gulf Power. The total estimated cost is approximately $125 million, with Mississippi Power's share of approximately $67 million being proposed for recovery through its ECO Plan. As of December 31, 2021, approximately $20 million of Mississippi Power's share is included in plant in service, approximately $14 million is included in CWIP, and approximately $13 million associated with ash pond closure is reflected in Mississippi Power's ARO liabilities. See Note 6 for additional information on AROs and Note 3 under "Other Matters - Mississippi Power" for additional information on Gulf Power's ownership in Plant Daniel. On June 8, 2021, the Mississippi PSC approved Mississippi Power's ECO Plan filing for 2021, resulting in a decrease in revenues of approximately $9 million annually, primarily due to a change in the amortization periods of certain regulatory assets and liabilities. The rate decrease became effective with the first billing cycle of July 2021.
Fuel Cost Recovery
Mississippi Power annually establishes and is required to file for an adjustment
to the retail fuel cost recovery factor that is approved by the Mississippi PSC.
The Mississippi PSC approved decreases of $35 million and $24 million effective
in February 2019 and 2020, respectively, and increases of $2 million and
$43 million effective in February 2021 and 2022, respectively. At December 31,
2021, under recovered retail fuel costs totaled approximately $4 million and
were included in other customer accounts receivable on Southern Company's and
Mississippi Power's balance sheets. At December 31, 2020, over recovered retail
fuel costs totaled $24 million and were included in other current liabilities on
Southern Company's balance sheet and over recovered regulatory clause
liabilities on Mississippi Power's balance sheet.
Mississippi Power has wholesale MRA and Market Based (MB) fuel cost recovery
factors. Effective with the first billing cycles for January 2020, 2021, and
2022, annual revenues under the wholesale MRA fuel rate increased $1 million,
decreased $5 million, and increased $11 million, respectively. The wholesale MB
fuel rate did not change materially in any period presented. At December 31,
2021, under recovered wholesale fuel costs were immaterial. At December 31,
2020, over recovered
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wholesale fuel costs totaled approximately $10 million and were included in other current liabilities on Southern Company's balance sheet and over recovered regulatory clause liabilities on Mississippi Power's balance sheet.
Mississippi Power's operating revenues are adjusted for differences in actual recoverable fuel cost and amounts billed in accordance with the currently approved cost recovery rate. Accordingly, changes in the billing factor should have no significant effect on Mississippi Power's revenues or net income but will affect operating cash flows.
Ad Valorem Tax Adjustment
Mississippi Power establishes annually an ad valorem tax adjustment factor that is approved by the Mississippi PSC to collect the ad valorem taxes paid by Mississippi Power. In 2020 and 2019, the annual revenues collected through the ad valorem tax adjustment factor increased by $10 million and decreased by $2 million, respectively. On April 6, 2021, the Mississippi PSC approved Mississippi Power's annual ad valorem tax adjustment filing for 2021, which requested an annual increase in revenues of approximately $28 million, including approximately $19 million of ad valorem taxes previously recovered through PEP in accordance with the Mississippi Power Rate Case Settlement Agreement. The rate increase became effective with the first billing cycle of May 2021.
System Restoration Rider
Mississippi Power carries insurance for the cost of certain types of damage to generation plants and general property. However, Mississippi Power is self-insured for the cost of storm, fire, and other uninsured casualty damage to its property, including transmission and distribution facilities. As permitted by the Mississippi PSC and the FERC, Mississippi Power accrues for the cost of such damage through an annual expense accrual which is credited to regulatory liability accounts for the retail and wholesale jurisdictions. The cost of repairing actual damage resulting from such events that individually exceed $50,000 is charged to the reserve. Every year, the Mississippi PSC, the MPUS, and Mississippi Power agree on SRR revenue level(s). Mississippi Power's net retail SRR accrual, which includes carrying costs and amortization of related excess deferred income tax benefits, was $(1.8) million in 2021, $0.8 million 2020, and $1.4 million in 2019. At December 31, 2020, the retail property damage reserve balance was $4 million. On October 14, 2021, the Mississippi PSC issued an accounting order giving Mississippi Power the authority to reclassify the retail costs associated with Hurricanes Zeta and Ida (approximately $49 million) to a regulatory asset to be recovered through PEP over a period to be determined in Mississippi Power's 2022 PEP proceeding. At December 31, 2021, the retail property damage reserve balance was $31 million, which reflects the impact of the reclassification. On December 7, 2021, the Mississippi PSC approved Mississippi Power's annual SRR filing, which requested an increase in retail revenues of approximately $9 million annually effective with the first billing cycle of March 2022. The Mississippi PSC also established $8 million as the minimum annual accrual amount until a target property damage reserve balance of $75 million is met. In the event the expected annual charges exceed the annual accrual or the target balance has been met, Mississippi Power and the Mississippi PSC will determine the appropriate change to the annual accrual. Additionally, if PEP earnings are above a certain threshold, Mississippi Power has the ability to apply any required PEP refund as an additional accrual to the property damage reserve in lieu of customer refunds.
Municipal and Rural Associations Tariff
Mississippi Power provides wholesale electric service to Cooperative Energy, East Mississippi Electric Power Association, and the City of Collins, all located in southeastern Mississippi, under a long-term, cost-based, FERC-regulated MRA tariff.
In 2017, Mississippi Power and Cooperative Energy executed, and the FERC accepted, a Shared Service Agreement (SSA), as part of the MRA tariff, under which Mississippi Power and Cooperative Energy share in providing electricity to the Cooperative Energy delivery points under the tariff. The SSA may be cancelled by Cooperative Energy with 10 years notice. Cooperative Energy has the option to decrease its use of Mississippi Power's generation services under the MRA tariff up to 2.5% annually, with required notice, with a remaining total reduction of 8%, or approximately $8 million in cumulative annual base revenues.
In June 2020, the FERC accepted Mississippi Power's requested $2 million annual increase in MRA base rates effective June 1, 2020, as agreed upon in a settlement agreement reached with its wholesale customers.
Southern Company Gas
Utility Regulation and Rate Design
The natural gas distribution utilities are subject to regulation and oversight
by their respective state regulatory agencies. Rates charged to customers vary
according to customer class (residential, commercial, or industrial) and rate
jurisdiction. These
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agencies approve rates designed to provide the opportunity to generate revenues to recover all prudently-incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable ROE.
As a result of operating in a deregulated environment, Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are set by the Georgia PSC and adjusted periodically. The Marketers add these fixed charges when billing customers. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light's revenues since the monthly fixed charge is not volumetric or directly weather dependent. With the exception of Atlanta Gas Light, the earnings of the natural gas distribution utilities can be affected by customer consumption patterns that are largely a function of weather conditions and price levels for natural gas. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. Southern Company Gas has various mechanisms, such as weather and revenue normalization mechanisms and weather derivative instruments, that limit exposure to weather changes within typical ranges in these utilities' respective service territories. In addition to natural gas cost recovery mechanisms, other cost recovery mechanisms and regulatory riders, which vary by utility, allow recovery of certain costs, such as those related to infrastructure replacement programs as well as environmental remediation, energy efficiency plans, and bad debts. In traditional rate designs, utilities recover a significant portion of the fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by customers. With the exception of Chattanooga Gas, the natural gas distribution utilities have decoupled regulatory mechanisms that Southern Company Gas believes encourage conservation by separating the recoverable amount of these fixed costs from the amounts of natural gas used by customers. See "Rate Proceedings" herein for additional information. Also see "Infrastructure Replacement Programs and Capital Projects" herein for additional information regarding infrastructure replacement programs at certain of the natural gas distribution utilities.
The following table provides regulatory information for Southern Company Gas' natural gas distribution utilities:
Nicor Gas Atlanta Gas Light Virginia Natural Gas Chattanooga Gas
Authorized ROE(a) 9.75% 10.25% 9.50% 9.80%
Weather normalization mechanisms(b) ü ü
Decoupled, including straight-fixed-variable
rates(c) ü ü ü
Regulatory infrastructure program rates(d) ü ü ü ü
Bad debt rider(e) ü ü ü
Energy efficiency plan(f) ü ü
Annual base rate adjustment mechanism(g) ü ü
Year of last base rate case decision(h) 2021 2019 2021 2018
(a)Represents the authorized ROE at December 31, 2021.
(b)Designed to help stabilize operating results by allowing recovery of costs in the event of unseasonal weather, but are not direct offsets to the potential impacts on earnings of weather and customer consumption. (c)Allows for recovery of fixed customer service costs separately from assumed natural gas volumes used by customers and provides a benchmark level of revenue for recovery.
(d)Programs that update or expand distribution systems and LNG facilities. Atlanta Gas Light's infrastructure program, System Reinforcement Rider, is effective for 2022 through 2024. See "Rate Proceedings - Atlanta Gas Light" herein for additional information. Chattanooga Gas' pipeline replacement program costs are recovered through its annual base rate review mechanism.
(e)The recovery (refund) of bad debt expense over (under) an established benchmark expense. The gas portion of bad debt expense is recovered through purchased gas adjustment mechanisms. Nicor Gas also has a rider to recover the non-gas portion of bad debt expense.
(f)Recovery of costs associated with plans to achieve specified energy savings goals.
(g)Regulatory mechanism allowing annual adjustments to base rates up or down based on authorized ROE and/or ROE range.
(h)Annual GRAM filing required at Atlanta Gas Light.
Infrastructure Replacement Programs and Capital Projects
In addition to capital expenditures recovered through base rates by each of the natural gas distribution utilities, Nicor Gas and Virginia Natural Gas have separate rate riders that provide timely recovery of capital expenditures for specific infrastructure replacement programs. Total capital expenditures incurred during 2021 for gas distribution operations were $1.5 billion.
The following table and discussions provide updates on the infrastructure replacement programs and capital projects at the natural gas distribution utilities at December 31, 2021. These programs are risk-based and designed to update and replace cast iron, bare
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steel, and mid-vintage plastic materials or expand Southern Company Gas'
distribution systems to improve reliability and meet operational flexibility and
growth.
Pipe
Expenditures in Expenditures Since Installed Since Scope of Last
Utility Program Recovery 2021 Project Inception Project Inception Program Program Duration Year of Program
(in millions) (miles) (miles) (years)
Nicor Gas Investing in Illinois(*) Rider $ 408 $ 2,508 1,153 1,394 9 2023
Virginia Natural Gas Steps to Advance
Virginia's Energy (SAVE) Rider 51 342 470 640 13 2024
Atlanta Gas Light System Reinforcement
Rider Rider - - N/A N/A 3 2024
Chattanooga Gas Pipeline Replacement
Program Rate Base 2 2 5 73 7 2027
Total $ 461 $ 2,852 1,628 2,107
(*)Includes replacement of pipes, compressors, and transmission mains along with
other improvements such as new meters. Scope of program miles is an estimate and
subject to change. Recovery of program costs is described under "Nicor Gas"
herein.
Nicor Gas
Illinois legislation allows Nicor Gas to provide more widespread safety and reliability enhancements to its distribution system and stipulates that rate increases to customers as a result of any infrastructure investments shall not exceed a cumulative annual average of 4.0% or, in any given year, 5.5% of base rate revenues. In 2014, the Illinois Commission approved the nine-year regulatory infrastructure program, Investing in Illinois, subject to annual review. In accordance with orders from the Illinois Commission, Nicor Gas recovers program costs incurred through a separate rider and base rates. The Illinois Commission's approval of Nicor Gas' rate case on November 18, 2021 included recovery of program costs through December 31, 2021. See "Rate Proceedings - Nicor Gas" herein for additional information. Nicor Gas' capital expenditures related to qualifying projects under the Investing in Illinois program totaled $389 million and $396 million in 2020 and 2019, respectively.
Virginia Natural Gas
In 2019, the Virginia Commission approved amendments to and extension of the
Steps to Advance Virginia's Energy (SAVE) program, an accelerated infrastructure
replacement program. The extension allows Virginia Natural Gas to continue
replacing aging pipeline infrastructure through 2024 and increases its
authorized investment under the previously-approved plan from $35 million to $40
million in 2019 with additional annual investments of $50 million in 2020, $60
million in 2021, $70 million in each year from 2022 through 2024, and a total
potential variance of up to $5 million allowed for the program, for a maximum
total investment over the six-year term (2019 through 2024) of $365 million.
Virginia Natural Gas' capital expenditures under the SAVE program totaled
$49 million and $45 million in 2020 and 2019, respectively.
The SAVE program is subject to annual review by the Virginia Commission. In
accordance with the base rate case approved by the Virginia Commission in 2021,
Virginia Natural Gas is recovering program costs incurred prior to November 1,
2020 through base rates. Program costs incurred subsequent to November 1, 2020
are currently being recovered through a separate rider and are subject to future
base rate case proceedings.
Atlanta Gas Light
In 2019, the Georgia PSC approved the continuation of GRAM as part of Atlanta
Gas Light's 2019 rate case order. Various infrastructure programs previously
authorized by the Georgia PSC, including the Integrated Vintage Plastic
Replacement Program to replace aging plastic pipe and the Integrated System
Reinforcement Program to upgrade Atlanta Gas Light's distribution system and LNG
facilities in Georgia, continue under GRAM and the recovery of and return on the
infrastructure program investments are included in annual base rate adjustments.
The amounts to be recovered through rates related to allowed, but not incurred,
costs have been recognized in an unrecognized ratemaking amount that is not
reflected on the balance sheets. These allowed costs are primarily the equity
return on the capital investment under the infrastructure programs in place
prior to GRAM and are being recovered through GRAM and base rates until the
earlier of the full recovery of the related under recovered amount or December
31, 2025. The under recovered balance at December 31, 2021 was $91 million,
including $47 million of unrecognized equity return. The Georgia PSC reviews
Atlanta Gas Light's performance annually under GRAM. See "Unrecognized
Ratemaking Amounts" herein for additional information.
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Atlanta Gas Light and the staff of the Georgia PSC previously agreed to a variation of the Integrated Customer Growth Program to extend pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. A separate tariff provides recovery of up to $15 million annually for strategic economic development projects approved by the Georgia PSC.
See "Rate Proceedings - Atlanta Gas Light" herein for additional information regarding the Georgia PSC's November 18, 2021 approval of Atlanta Gas Light's GRAM filing and Integrated Capacity and Delivery Plan. The Georgia PSC also approved a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects, which is expected to recover related capital investments totaling $286 million for the years 2022 through 2024. Chattanooga Gas In June 2021, the Tennessee Public Utilities Commission approved Chattanooga Gas' pipeline replacement program to replace approximately 73 miles of distribution main over a seven-year period. The estimated total cost of the program is $118 million, which will be recovered through Chattanooga Gas' annual base rate review mechanism. Natural Gas Cost Recovery With the exception of Atlanta Gas Light, the natural gas distribution utilities are authorized by the relevant regulatory agencies in the states in which they serve to use natural gas cost recovery mechanisms that adjust rates to reflect changes in the wholesale cost of natural gas and ensure recovery of all costs prudently incurred in purchasing natural gas for customers. The natural gas distribution utilities defer or accrue the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. Changes in the billing factor will not have a significant effect on Southern Company's or Southern Company Gas' net income, but will affect cash flows. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost through recovery mechanisms approved by the Georgia PSC. At December 31, 2021, the under recovered balance was $473 million, $266 million of which was included in natural gas cost under recovery and $207 million of which was included in other regulatory assets, deferred on Southern Company's and Southern Company Gas' balance sheets. At December 31, 2020, the over recovered balance was $88 million, which was included in other regulatory liabilities on Southern Company's and Southern Company Gas' balance sheets.
Rate Proceedings
Nicor Gas
In 2019, the Illinois Commission approved a $168 million annual base rate increase effective October 8, 2019. The base rate increase included $65 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.73% and an equity ratio of 54.2%. Additionally, the Illinois Commission approved a volume balancing adjustment, a revenue decoupling mechanism for residential customers that provides a benchmark level of revenue per rate class for recovery. On November 18, 2021, the Illinois Commission approved a $240 million annual base rate increase effective November 24, 2021. The base rate increase included $94 million related to the recovery of program costs under the Investing in Illinois program and was based on a ROE of 9.75% and an equity ratio of 54.5%.
Atlanta Gas Light
In 2019, the Georgia PSC approved a $65 million annual base rate increase,
effective January 1, 2020, based on a ROE of 10.25% and an equity ratio of 56%.
Earnings will be evaluated against a ROE range of 10.05% to 10.45%, with
disposition of any earnings above 10.45% to be determined by the Georgia PSC.
Additionally, the Georgia PSC approved continuation of the previously authorized
inclusion in base rates of the recovery of and return on the infrastructure
program investments, including, but not limited to, GRAM adjustments, and a
reauthorization and continuation of GRAM until terminated by the Georgia PSC.
GRAM filing rate adjustments will be based on the authorized ROE of 10.25%. GRAM
adjustments for 2021 could not exceed 5% of 2020 base rates. The 5% limitation
does not set a precedent in any future rate proceedings by Atlanta Gas Light.
In July 2020, Atlanta Gas Light filed its annual GRAM filing with the Georgia
PSC requesting an annual base rate increase of $37.6 million based on the
projected 12-month period beginning January 1, 2021, which did not exceed the 5%
limitation established by the Georgia PSC. Rates went into effect on January 1,
2021 in accordance with Atlanta Gas Light's 2019 rate case order.
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On February 16, 2021, the Georgia PSC approved a stipulation between Atlanta Gas Light and the Georgia PSC staff establishing a long-range comprehensive planning process. Under the terms of the stipulation, Atlanta Gas Light was required to develop and file at least triennially an Integrated Capacity and Delivery Plan (i-CDP). Each i-CDP will include a 10-year forecast of interstate and intrastate capacity asset requirements, including a detailed plan for the first three years consistent with Atlanta Gas Light's current capacity supply plan, and a 10-year projection of capital budgets and related operations and maintenance spending. Recovery of the related revenue requirements will be included in either subsequent annual GRAM filings or a new System Reinforcement Rider for authorized large pressure improvement and system reliability projects. On April 28, 2021, Atlanta Gas Light filed its first i-CDP with the Georgia PSC, which includes a series of ongoing and proposed pipeline safety, reliability, and growth programs for the next 10 years (2022 through 2031), as well as the required capital investments and related costs to implement the programs. The i-CDP reflected capital investments totaling approximately $0.5 billion to $0.6 billion annually. On November 18, 2021, the Georgia PSC approved an October 14, 2021 joint stipulation agreement between Atlanta Gas Light and the staff of the Georgia PSC, under which, for the years 2022 through 2024, Atlanta Gas Light will incrementally reduce its combined GRAM and System Reinforcement Rider request by 10% through Atlanta Gas Light's GRAM mechanism, or $5 million for 2022. The stipulation agreement also provides for $1.7 billion of total capital investment for the years 2022 through 2024. Also on November 18, 2021, the Georgia PSC approved Atlanta Gas Light's amended annual GRAM filing, which resulted in an annual rate increase of $43 million effective January 1, 2022. Virginia Natural Gas On September 14, 2021, the Virginia Commission approved a stipulation agreement related to Virginia Natural Gas' June 2020 general rate case filing, which allows for a $43 million increase in annual base rate revenues, including $14 million related to the recovery of investments under the SAVE program, based on a ROE of 9.5% and an equity ratio of 51.9%. Interim rate adjustments became effective as of November 1, 2020, subject to refund, based on Virginia Natural Gas' original request for an increase of approximately $50 million. Refunds to customers related to the difference between the approved rates and the interim rates were completed during the fourth quarter 2021.
Deferral of Incremental COVID-19 Costs
As discussed under "Utility Regulation and Rate Design," the natural gas distribution utilities have various regulatory mechanisms to recover bad debt expense, which helped mitigate potential increases in bad debt expense as a result of the COVID-19 pandemic. Deferred incremental costs related to the COVID-19 pandemic were immaterial for Virginia Natural Gas.
Atlanta Gas Light
In April 2020, in response to the COVID-19 pandemic, the Georgia PSC approved orders directing Atlanta Gas Light to continue its previous, voluntary suspension of customer disconnections. In June 2020, the Georgia PSC ordered Atlanta Gas Light to resume customer disconnections beginning July 2020, with exceptions for customers still covered by a shelter-in-place order. All suspensions for customer disconnections were lifted in October 2020. The orders provide the Marketers, including SouthStar, with a mechanism to receive credits from Atlanta Gas Light for the base rates it charged to the Marketers of non-paying customers during the suspension. Atlanta Gas Light will begin recovering these credits through GRAM rates effective January 1, 2023.
Nicor Gas
In March 2020, in response to the COVID-19 pandemic, the Illinois Commission
issued an order directing utilities to cease disconnections for non-payment and
to suspend the imposition of late payment fees or penalties. In June 2020, the
Illinois Commission approved a stipulation pursuant to which Nicor Gas and other
utilities in Illinois would provide more flexible credit and collection
procedures to assist customers with financial hardship and which authorizes a
special purpose rider for recovery of the following COVID-19 pandemic-related
impacts: incremental costs directly associated with the COVID-19 pandemic, net
of the offset for COVID-19 pandemic-related credits received, foregone late
fees, foregone reconnection charges, and the costs associated with a bill
payment assistance program. Nicor Gas resumed late payment fees in July 2020
and, on October 1, 2020, began recovery of the COVID-19 pandemic-related impacts
through the special purpose rider, which will continue over a 24-month period.
On March 18, 2021, the Illinois Commission approved a phased-in schedule for
disconnections related to non-payment. Nicor Gas began certain disconnections in
late April 2021 and resumed normal disconnections in June 2021. At December 31,
2021 and 2020, Nicor Gas' related regulatory asset was $5 million and
$9 million, respectively.
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Unrecognized Ratemaking Amounts
The following table illustrates Southern Company Gas' authorized ratemaking
amounts that are not recognized on its balance sheets. These amounts are
primarily composed of an allowed equity rate of return on assets associated with
certain regulatory infrastructure programs. These amounts will be recognized as
revenues in Southern Company Gas' financial statements in the periods they are
billable to customers, the majority of which will be recovered by 2025.
December 31, 2021 December 31, 2020
(in millions)
Atlanta Gas Light $ 47 $ 59
Virginia Natural Gas 10 10
Chattanooga Gas 4 2
Nicor Gas - 3
Total $ 61 $ 74
3. CONTINGENCIES, COMMITMENTS, AND GUARANTEES
General Litigation Matters
The Registrants are involved in various matters being litigated and regulatory matters. The ultimate outcome of such pending or potential litigation or regulatory matters against each Registrant and any subsidiaries cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on such Registrant's financial statements. The Registrants believe the pending legal challenges discussed below have no merit; however, the ultimate outcome of these matters cannot be determined at this time. Southern Company In February 2017, Jean Vineyard and Judy Mesirov each filed a shareholder derivative lawsuit in the U.S. District Court for the Northern District of Georgia. Each of these lawsuits names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. In 2017, these two shareholder derivative lawsuits were consolidated in the U.S. District Court for the Northern District of Georgia. The complaints allege that the defendants caused Southern Company to make false or misleading statements regarding the Kemper County energy facility cost and schedule. Further, the complaints allege that the defendants were unjustly enriched and caused the waste of corporate assets and also allege that the individual defendants violated their fiduciary duties. In May 2017, Helen E. Piper Survivor's Trust filed a shareholder derivative lawsuit in the Superior Court of Gwinnett County, Georgia that names as defendants Southern Company, certain of its directors, certain of its current and former officers, and certain former Mississippi Power officers. The complaint alleges that the individual defendants, among other things, breached their fiduciary duties in connection with schedule delays and cost overruns associated with the construction of the Kemper County energy facility. The complaint further alleges that the individual defendants authorized or failed to correct false and misleading statements regarding the Kemper County energy facility schedule and cost and failed to implement necessary internal controls to prevent harm to Southern Company. In August 2019, the court granted a motion filed by the plaintiff in July 2019 to substitute a new named plaintiff, Martin J. Kobuck, in place of Helen E. Piper Survivor's Trust. The plaintiffs in each of these cases seek to recover, on behalf of Southern Company, unspecified actual damages and, on each plaintiff's own behalf, attorneys' fees and costs in bringing the lawsuit. The plaintiffs also seek certain changes to Southern Company's corporate governance and internal processes. On January 21, 2022, the plaintiffs in the federal court action filed a motion for preliminary approval of settlement, together with an executed stipulation of settlement, which applies to both the federal and state actions. The terms of the settlement are not expected to have a material impact on Southern Company's financial statements.
Georgia Power
In 2011, plaintiffs filed a putative class action against Georgia Power in the
Superior Court of Fulton County, Georgia alleging that Georgia Power's
collection in rates of amounts for municipal franchise fees (which fees are paid
to municipalities) exceeded the amounts allowed in orders of the Georgia PSC and
alleging certain state law claims. This case has been ruled upon and appealed
numerous times over the last several years. In October 2019, the Georgia PSC
issued an order that found Georgia Power
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has appropriately implemented the municipal franchise fee schedule. On March 16, 2021, the Superior Court of Fulton County granted class certification and Georgia Power's motion for summary judgment. On March 22, 2021, the plaintiffs filed a notice of appeal, and, on April 2, 2021, Georgia Power filed a notice of cross appeal on the issue of class certification. On December 1, 2021, the Georgia Court of Appeals affirmed the Superior Court's ruling that granted summary judgment to Georgia Power and dismissed Georgia Power's cross appeal on the issue of class certification as moot. On December 21, 2021, the plaintiffs filed a petition for writ of certiorari to the Georgia Supreme Court. The amount of any possible losses cannot be estimated at this time because, among other factors, it is unknown whether any losses would be subject to recovery from any municipalities. In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. On November 11, 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. The amount of any possible losses from these matters cannot be estimated at this time.
Mississippi Power
In 2018, Ray C. Turnage and 10 other individual plaintiffs filed a putative class action complaint against Mississippi Power and the three then-serving members of the Mississippi PSC in the U.S. District Court for the Southern District of Mississippi, which was amended in March 2019 to include four additional plaintiffs. Mississippi Power received Mississippi PSC approval in 2013 to charge a mirror CWIP rate premised upon including in its rate base pre-construction and construction costs for the Kemper IGCC prior to placing the Kemper IGCC into service. The Mississippi Supreme Court reversed that approval and ordered Mississippi Power to refund the amounts paid by customers under the previously-approved mirror CWIP rate. The plaintiffs allege that the initial approval process, and the amount approved, were improper and make claims for gross negligence, reckless conduct, and intentional wrongdoing. They also allege that Mississippi Power underpaid customers by up to $23.5 million in the refund process by applying an incorrect interest rate. The plaintiffs seek to recover, on behalf of themselves and their putative class, actual damages, punitive damages, pre-judgment interest, post-judgment interest, attorney's fees, and costs. The district court dismissed the amended complaint; however, in March 2020, the plaintiffs filed a motion seeking to name the new members of the Mississippi PSC, the Mississippi Development Authority, and Southern Company as additional defendants and add a cause of action against all defendants based on a dormant commerce clause theory under the U.S. Constitution. In July 2020, the plaintiffs filed a motion for leave to file a third amended complaint, which included the same federal claims as the proposed second amended complaint, as well as several additional state law claims based on the allegation that Mississippi Power failed to disclose the annual percentage rate of interest applicable to refunds. In November 2020, the court denied each of the plaintiffs' pending motions and entered final judgment in favor of Mississippi Power. On January 22, 2021, the court denied further motions by the plaintiffs to vacate the judgment and to file a revised second amended complaint. On February 19, 2021, the plaintiffs filed a notice of appeal with the U.S. Court of Appeals for the Fifth Circuit. An adverse outcome in this proceeding could have a material impact on Mississippi Power's financial statements.
Environmental Remediation
The Southern Company system must comply with environmental laws and regulations
governing the handling and disposal of waste and releases of hazardous
substances. Under these various laws and regulations, the Southern Company
system could incur substantial costs to clean up affected sites. The traditional
electric operating companies and the natural gas distribution utilities conduct
studies to determine the extent of any required cleanup and have recognized the
estimated costs to clean up known impacted sites in the financial statements. A
liability for environmental remediation costs is recognized only when a loss is
determined to be probable and reasonably estimable and is reduced as
expenditures are incurred. The traditional electric operating companies and the
natural gas distribution utilities in Illinois and Georgia have each received
authority from their respective state PSCs or other applicable state regulatory
agencies to recover approved environmental remediation costs through regulatory
mechanisms. Any difference between the liabilities accrued and costs recovered
through rates is deferred as a regulatory asset or liability. These regulatory
mechanisms are adjusted annually or as necessary within limits approved by the
state PSCs or other applicable state regulatory agencies.
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Georgia Power has been designated or identified as a potentially responsible
party at sites governed by the Georgia Hazardous Site Response Act and/or by the
federal Comprehensive Environmental Response, Compensation, and Liability Act,
and assessment and potential cleanup of such sites is expected. For 2021, 2020,
and 2019, Georgia Power recovered approximately $12 million, $12 million, and $2
million, respectively, through the ECCR tariff for environmental remediation.
Southern Company Gas is subject to environmental remediation liabilities
associated with 40 former MGP sites in four different states. Southern Company
Gas' accrued environmental remediation liability at December 31, 2021 and 2020
was based on the estimated cost of environmental investigation and remediation
associated with these sites.
At December 31, 2021 and 2020, the environmental remediation liability and the
balance of under recovered environmental remediation costs were reflected in the
balance sheets of Southern Company, Georgia Power, and Southern Company Gas as
shown in the table below. At December 31, 2021 and 2020, Alabama Power did not
have environmental remediation liabilities and Mississippi Power's balance was
immaterial.
Georgia Southern Company
Southern Company Power Gas
(in millions)
December 31, 2021:
Environmental remediation liability:
Other current liabilities $ 69 $ 17 $ 52
Accrued environmental remediation 197 - 197
Under recovered environmental remediation costs:
Other regulatory assets, current $ 71 $ 12 $ 59
Other regulatory assets, deferred 231 23 208
December 31, 2020:
Environmental remediation liability:
Other current liabilities $ 44 $ 15 $ 29
Accrued environmental remediation 216 - 216
Under recovered environmental remediation costs:
Other regulatory assets, current $ 46 $ 12 $ 34
Other regulatory assets, deferred 265 29 236
The ultimate outcome of these matters cannot be determined at this time;
however, as a result of the regulatory treatment for environmental remediation
expenses described above, the final disposition of these matters is not expected
to have a material impact on the financial statements of the applicable
Registrants.
Nuclear Fuel Disposal Costs
Acting through the DOE and pursuant to the Nuclear Waste Policy Act of 1982, the
U.S. government entered into contracts with Alabama Power and Georgia Power that
required the DOE to dispose of spent nuclear fuel generated at Plants Farley,
Hatch, and Vogtle Units 1 and 2 beginning no later than January 31, 1998. The
DOE has yet to commence the performance of its contractual and statutory
obligation to dispose of spent nuclear fuel. Consequently, Alabama Power and
Georgia Power pursued and continue to pursue legal remedies against the U.S.
government for its partial breach of contract.
In 2014, Alabama Power and Georgia Power filed lawsuits against the U.S.
government for the costs of continuing to store spent nuclear fuel at Plants
Farley, Hatch, and Vogtle Units 1 and 2 for the period from January 1, 2011
through December 31, 2013. The damage period was subsequently extended to
December 31, 2014. In 2019, the Court of Federal Claims granted Alabama Power's
and Georgia Power's motion for summary judgment on damages not disputed by the
U.S. government, awarding those undisputed damages to Alabama Power and Georgia
Power. However, those undisputed damages are not collectible until the court
enters final judgment on the remaining damages.
In 2017, Alabama Power and Georgia Power filed additional lawsuits against the
U.S. government in the Court of Federal Claims for the costs of continuing to
store spent nuclear fuel at Plants Farley, Hatch, and Vogtle Units 1 and 2 for
the period from January
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1, 2015 through December 31, 2017. In August 2020, Alabama Power and Georgia Power filed amended complaints in each of the lawsuits adding damages from January 1, 2018 to December 31, 2019 to the claim period.
The outstanding claims for the period January 1, 2011 through December 31, 2019 total $110 million and $132 million for Alabama Power and Georgia Power (based on its ownership interests), respectively. Damages will continue to accumulate until the issue is resolved, the U.S. government disposes of Alabama Power's and Georgia Power's spent nuclear fuel pursuant to its contractual obligations, or alternative storage is otherwise provided. No amounts have been recognized in the financial statements as of December 31, 2021 for any potential recoveries from the pending lawsuits. The final outcome of these matters cannot be determined at this time. However, Alabama Power and Georgia Power expect to credit any recoveries for the benefit of customers in accordance with direction from their respective PSC; therefore, no material impact on Southern Company's, Alabama Power's, or Georgia Power's net income is expected. On-site dry spent fuel storage facilities are operational at all three plants and can be expanded to accommodate spent fuel through the expected life of each plant. Nuclear Insurance Under the Price-Anderson Amendments Act (Act), Alabama Power and Georgia Power maintain agreements of indemnity with the NRC that, together with private insurance, cover third-party liability arising from any nuclear incident occurring at the companies' nuclear power plants. The Act provides funds up to $13.5 billion for public liability claims that could arise from a single nuclear incident. Each nuclear plant is insured against this liability to a maximum of $450 million by American Nuclear Insurers (ANI), with the remaining coverage provided by a mandatory program of deferred premiums that could be assessed, after a nuclear incident, against all owners of commercial nuclear reactors. A company could be assessed up to $138 million per incident for each licensed reactor it operates but not more than an aggregate of $20 million per incident to be paid in a calendar year for each reactor. Such maximum assessment, excluding any applicable state premium taxes, for Alabama Power and Georgia Power, based on its ownership and buyback interests in all licensed reactors, is $275 million and $267 million, respectively, per incident, but not more than an aggregate of $41 million and $40 million, respectively, to be paid for each incident in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than November 1, 2023. See Note 5 under "Joint Ownership Agreements" for additional information on joint ownership agreements. Alabama Power and Georgia Power are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurer established to provide property damage insurance in an amount up to $1.5 billion for members' operating nuclear generating facilities. Additionally, both companies have NEIL policies that currently provide decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that would be incurred in obtaining replacement power during a prolonged accidental outage at a member's nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. Alabama Power and Georgia Power each purchase limits based on the projected full cost of replacement power, subject to ownership limitations, and have each elected a 12-week deductible waiting period for each nuclear plant.
A builders' risk property insurance policy has been purchased from NEIL for the construction of Plant Vogtle Units 3 and 4. This policy provides the Vogtle Owners up to $2.75 billion for accidental property damage occurring during construction.
Under each of the NEIL policies, members are subject to assessments each year if
losses exceed the accumulated funds available to the insurer. The maximum annual
assessments for Alabama Power and Georgia Power as of December 31, 2021 under
the NEIL policies would be $52 million and $83 million, respectively.
Claims resulting from terrorist acts and cyber events are covered under both the
ANI and NEIL policies (subject to normal policy limits). The maximum aggregate
that NEIL will pay for all claims resulting from terrorist acts and cyber events
in any 12-month period is $3.2 billion each, plus such additional amounts NEIL
can recover through reinsurance, indemnity, or other sources.
For all on-site property damage insurance policies for commercial nuclear power
plants, the NRC requires that the proceeds of such policies shall be dedicated
first for the sole purpose of placing the reactor in a safe and stable condition
after an accident. Any remaining proceeds are to be applied next toward the
costs of decontamination and debris removal operations ordered by the NRC, and
any further remaining proceeds are to be paid either to the applicable company
or to its debt trustees as may be appropriate under the policies and applicable
trust indentures. In the event of a loss, the amount of insurance available
might not be adequate to cover property damage and other expenses incurred.
Uninsured losses and other expenses, to the extent not
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recovered from customers, would be borne by Alabama Power or Georgia Power, as applicable, and could have a material effect on Southern Company's, Alabama Power's, and Georgia Power's financial condition and results of operations.
All retrospective assessments, whether generated for liability, property, or replacement power, may be subject to applicable state premium taxes.
Other Matters Mississippi Power Kemper County Energy Facility In 2019, 2020, and 2021, Mississippi Power recorded charges to income associated with abandonment and related closure costs and ongoing period costs, net of salvage proceeds, for the mine and gasifier-related assets at the Kemper County energy facility. These charges, including related tax impacts, totaled $24 million pre-tax and after tax in 2019, $4 million pre-tax ($3 million after tax) in 2020, and $11 million pre-tax ($8 million after tax) in 2021. The pre-tax charges are included in other operations and maintenance expenses on the statements of income. Dismantlement of the abandoned gasifier-related assets and site restoration activities are expected to be completed by 2026. Additional pre-tax period costs associated with dismantlement and site restoration activities, including related costs for compliance and safety, ARO accretion, and property taxes, net of salvage, are estimated to total $10 million to $20 million annually through 2025. Mississippi Power owns the lignite mine located around the Kemper County energy facility site. As a result of the abandonment of the Kemper IGCC, final mine reclamation began in 2018 and was substantially completed in 2020, with monitoring expected to continue through 2028. As the mining permit holder, Liberty Fuels Company, LLC, a wholly-owned subsidiary of The North American Coal Corporation, has a legal obligation to perform mine reclamation and Mississippi Power has a contractual obligation to fund all reclamation activities. See Note 6 for additional information. In 2010, the DOE, through a cooperative agreement with SCS, agreed to fund $270 million of the Kemper County energy facility through the grants awarded to the project by the DOE under the Clean Coal Power Initiative Round 2. In 2016, additional DOE grants in the amount of $137 million were awarded to the Kemper County energy facility. In 2018, Mississippi Power filed with the DOE its request for property closeout certification under the contract related to the $387 million of total grants received. In September 2020, Mississippi Power and Southern Company executed an agreement with the DOE completing Mississippi Power's request, which enabled Mississippi Power to proceed with full dismantlement of the abandoned gasifier-related assets and site restoration activities. The expected impact of the closeout agreement was accrued in 2019. In connection with the DOE closeout discussions, in 2019, the Civil Division of the Department of Justice informed Southern Company and Mississippi Power of an investigation related to the grants received. The ultimate outcome of this matter cannot be determined at this time; however, it could have a material impact on Southern Company's and Mississippi Power's financial statements.
Plant Daniel
In conjunction with Southern Company's sale of Gulf Power, NextEra Energy held back $75 million of the purchase price pending Mississippi Power and Gulf Power negotiating a mutually acceptable revised operating agreement for Plant Daniel. In addition, Mississippi Power and Gulf Power agreed to seek a restructuring of their 50% undivided ownership interests in the Plant Daniel coal units such that each of them would, after the restructuring, own 100% of a generating unit. In 2019, Gulf Power provided notice to Mississippi Power that Gulf Power will retire its share of the coal generating capacity of Plant Daniel on January 15, 2024. Mississippi Power has the option to purchase Gulf Power's ownership interest for $1 on January 15, 2024, provided that Mississippi Power exercises the option no later than 120 days prior to that date. Mississippi Power is assessing the potential operational and economic effects of Gulf Power's notice. Mississippi Power and Gulf Power are continuing negotiations on a mutually acceptable revised operating agreement. The impacts of operating the units on an individual basis continue to be evaluated by Mississippi Power and any transfer of ownership would be subject to approval by the FERC and the Mississippi PSC. The ultimate outcome of this matter cannot be determined at this time. See Note 2 under "Mississippi Power - Integrated Resource Plan" for additional information on Plant Daniel and Note 15 under "Southern Company" for information regarding the sale of Gulf Power.
Commitments
To supply a portion of the fuel requirements of the Southern Company system's
electric generating plants, the Southern Company system has entered into various
long-term commitments not recognized on the balance sheets for the procurement
and delivery of
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fossil fuel and, for Alabama Power and Georgia Power, nuclear fuel. The majority of the Registrants' fuel expense for the periods presented was purchased under long-term commitments. Each Registrant expects that a substantial amount of its future fuel needs will continue to be purchased under long-term commitments. Georgia Power has commitments, in the form of capacity purchases, regarding a portion of a 5% interest in the original cost of Plant Vogtle Units 1 and 2 owned by MEAG Power that are in effect until the later of the retirement of the plant or the latest stated maturity date of MEAG Power's bonds issued to finance such ownership interest. The payments for capacity are required whether or not any capacity is available. Portions of the capacity payments made to MEAG Power for its Plant Vogtle Units 1 and 2 investment relate to costs in excess of Georgia Power's allowed investment for ratemaking purposes. The present value of these portions at the time of the disallowance was written off. Generally, the cost of such capacity is included in purchased power in Southern Company's statements of income and in purchased power, non-affiliates in Georgia Power's statements of income. Georgia Power's capacity payments related to this commitment totaled $6 million, $5 million, and $6 million in 2021, 2020, and 2019, respectively. At December 31, 2021, Georgia Power's estimated long-term obligations related to this commitment totaled $42 million, consisting of $4 million for 2022, $3 million annually for 2023 through 2025, $1 million for 2026, and $28 million thereafter.
See Note 9 for information regarding PPAs accounted for as leases.
Southern Company Gas has commitments for pipeline charges, storage capacity, and
gas supply, including charges recoverable through natural gas cost recovery
mechanisms or, alternatively, billed to marketers selling retail natural gas.
Gas supply commitments include amounts for gas commodity purchases associated
with Nicor Gas and SouthStar of 56 million mmBtu at floating gas prices
calculated using forward natural gas prices at December 31, 2021 and valued at
$222 million. Southern Company Gas provides guarantees to certain gas suppliers
for certain of its subsidiaries in support of payment obligations. Southern
Company Gas' expected future contractual obligations for pipeline charges,
storage capacity, and gas supply that are not recognized on the balance sheets
at December 31, 2021 were as follows:
Pipeline Charges, Storage Capacity, and Gas Supply
(in millions)
2022 $ 634
2023 455
2024 376
2025 275
2026 164
Thereafter 910
Total $ 2,814
Guarantees
SCS may enter into various types of wholesale energy and natural gas contracts
acting as an agent for the traditional electric operating companies and Southern
Power. Under these agreements, each of the traditional electric operating
companies and Southern Power may be jointly and severally liable. Accordingly,
Southern Company has entered into keep-well agreements with each of the
traditional electric operating companies to ensure they will not subsidize or be
responsible for any costs, losses, liabilities, or damages resulting from the
inclusion of Southern Power as a contracting party under these agreements.
Alabama Power has guaranteed a $100 million principal amount long-term bank loan
SEGCO entered into in 2018 and subsequently extended in 2021. Georgia Power has
agreed to reimburse Alabama Power for the portion of such obligation
corresponding to Georgia Power's proportionate ownership of SEGCO's stock if
Alabama Power is called upon to make such payment under its guarantee. At
December 31, 2021, the capitalization of SEGCO consisted of $82 million of
equity and $100 million of long-term debt that matures in November 2024, on
which the annual interest requirement is derived from a variable rate index. In
addition, SEGCO had short-term debt outstanding of $20 million. See Note 7 under
"SEGCO" for additional information.
As discussed in Note 9, Alabama Power and Georgia Power have entered into certain residual value guarantees related to railcar leases.
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4. REVENUE FROM CONTRACTS WITH CUSTOMERS
The Registrants generate revenues from a variety of sources, some of which are
not accounted for as revenue from contracts with customers, such as leases,
derivatives, and certain cost recovery mechanisms. See Note 1 under "Revenues"
for additional information on the revenue policies of the Registrants. See Notes
9 and 14 for additional information on revenue accounted for under lease and
derivative accounting guidance, respectively.
The following table disaggregates revenue from contracts with customers for the
periods presented:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
2021
Operating revenues
Retail electric revenues
Residential $ 6,207 $ 2,467 $ 3,471 $ 269 $ - $ -
Commercial 4,877 1,600 3,010 267 - -
Industrial 3,067 1,386 1,391 290 - -
Other 93 17 68 8 - -
Total retail electric revenues 14,244 5,470 7,940 834 - -
Natural gas distribution revenues
Residential 1,799 - - - - 1,799
Commercial 470 - - - - 470
Transportation 1,038 - - - - 1,038
Industrial 49 - - - - 49
Other 269 - - - - 269
Total natural gas distribution revenues 3,625 - - - - 3,625
Wholesale electric revenues
PPA energy revenues 1,122 184 95 11 854 -
PPA capacity revenues 493 115 55 5 323 -
Non-PPA revenues 236 170 21 401 398 -
Total wholesale electric revenues 1,851 469 171 417 1,575 -
Other natural gas revenues
Wholesale gas services 2,168 - - - - 2,168
Gas marketing services 464 - - - - 464
Other natural gas revenues 36 - - - - 36
Total natural gas revenues 2,668 - - - - 2,668
Other revenues 1,075 202 452 31 30 -
Total revenue from contracts with
customers 23,463 6,141 8,563 1,282 1,605 6,293
Other revenue sources(a) 3,349 272 697 40 611 1,786
Other adjustments(b) (3,699) - - - - (3,699)
Total operating revenues $ 23,113 $ 6,413 $ 9,260 $ 1,322 $ 2,216 $ 4,380
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Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
2020
Operating revenues
Retail electric revenues
Residential $ 6,113 $ 2,377 $ 3,476 $ 260 $ - $ -
Commercial 4,699 1,512 2,933 254 - -
Industrial 2,775 1,293 1,197 285 - -
Other 90 21 60 9 - -
Total retail electric revenues 13,677 5,203 7,666 808 - -
Natural gas distribution revenues
Residential 1,338 - - - - 1,338
Commercial 340 - - - - 340
Transportation 971 - - - - 971
Industrial 30 - - - - 30
Other 209 - - - - 209
Total natural gas distribution revenues 2,888 - - - - 2,888
Wholesale electric revenues
PPA energy revenues 735 133 42 9 570 -
PPA capacity revenues 454 108 50 3 296 -
Non-PPA revenues 210 43 10 311 239 -
Total wholesale electric revenues 1,399 284 102 323 1,105 -
Other natural gas revenues
Wholesale gas services 1,727 - - - - 1,727
Gas marketing services 391 - - - - 391
Other natural gas revenues 33 - - - - 33
Total other natural gas revenues 2,151 - - - - 2,151
Other revenues 982 159 447 26 14 -
Total revenue from contracts with
customers 21,097 5,646 8,215 1,157 1,119 5,039
Other revenue sources(a) 3,764 184 94 15 614 2,881
Other adjustments(b) (4,486) - - - - (4,486)
Total operating revenues $ 20,375 $ 5,830 $ 8,309 $ 1,172 $ 1,733 $ 3,434
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Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
2019
Operating revenues
Retail electric revenues
Residential $ 6,164 $ 2,509 $ 3,377 $ 278 $ - $ -
Commercial 5,065 1,677 3,097 291 - -
Industrial 3,126 1,460 1,360 306 - -
Other 90 25 54 11 - -
Total retail electric revenues 14,445 5,671 7,888 886 - -
Natural gas distribution revenues
Residential 1,413 - - - - 1,413
Commercial 389 - - - - 389
Transportation 907 - - - - 907
Industrial 35 - - - - 35
Other 245 - - - - 245
Total natural gas distribution revenues 2,989 - - - - 2,989
Wholesale electric revenues
PPA energy revenues 833 145 60 11 648 -
PPA capacity revenues 453 102 54 3 322 -
Non-PPA revenues 232 81 9 352 238 -
Total wholesale electric revenues 1,518 328 123 366 1,208 -
Other natural gas revenues
Gas pipeline investments 32 - - - - 32
Wholesale gas services 2,095 - - - - 2,095
Gas marketing services 440 - - - - 440
Other natural gas revenues 42 - - - - 42
Total other natural gas revenues 2,609 - - - - 2,609
Other revenues 1,035 153 407 19 12 -
Total revenue from contracts with
customers 22,596 6,152 8,418 1,271 1,220 5,598
Other revenue sources(a) 4,266 (27) (10) (7) 718 3,637
Other adjustments(b) (5,443) - - - - (5,443)
Total operating revenues $ 21,419 $ 6,125 $ 8,408 $ 1,264 $ 1,938 $ 3,792
(a)Other revenue sources relate to revenues from customers accounted for as
derivatives and leases, alternative revenue programs at Southern Company Gas,
and cost recovery mechanisms and revenues that meet other scope exceptions for
revenues from contracts with customers at the traditional electric operating
companies.
(b)Other adjustments relate to the cost of Southern Company Gas' energy and risk
management activities. Wholesale gas services revenues are presented net of the
related costs of those activities on the statement of income. See Notes 15 and
16 under "Southern Company Gas" for information on the sale of Sequent and
components of wholesale gas services' operating revenues, respectively.
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Contract Balances
The following table reflects the closing balances of receivables, contract assets, and contract liabilities related to revenues from contracts with customers at December 31, 2021 and 2020:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
Accounts Receivable
At December 31, 2021 $ 2,504 $ 589 $ 736 $ 73 $ 149 $ 753
At December 31, 2020 2,614 632 806 77 112 788
Contract Assets
At December 31, 2021 $ 117 $ 2 $ 63 $ - $ 1 $ -
At December 31, 2020 158 2 71 - - -
Contract Liabilities
At December 31, 2021 $ 57 $ 4 $ 14 $ - $ 1 $ -
At December 31, 2020 61 6 27 1 1 1
At December 31, 2021 and 2020, Georgia Power had contract assets primarily
related to retail customer fixed bill programs, where the payment is contingent
upon Georgia Power's continued performance and the customer's continued
participation in the program over a one-year contract term, and unregulated
service agreements, where payment is contingent on project completion. Contract
liabilities for Georgia Power relate to cash collections recognized in advance
of revenue for unregulated service agreements. Southern Company's unregulated
distributed generation business had contract assets of $50 million and $81
million at December 31, 2021 and 2020, respectively, and contract liabilities of
$39 million and $27 million at December 31, 2021 and 2020, respectively, for
outstanding performance obligations.
Revenues recognized in 2021 and 2020, which were included in contract
liabilities at December 31, 2020 and December 31, 2019, respectively, were $29
million and $33 million, respectively, for Southern Company and immaterial for
the other Registrants.
Remaining Performance Obligations
The traditional electric operating companies and Southern Power have long-term
contracts with customers in which revenues are recognized as performance
obligations are satisfied over the contract term. These contracts primarily
relate to PPAs whereby the traditional electric operating companies and Southern
Power provide electricity and generation capacity to a customer. The revenue
recognized for the delivery of electricity is variable; however, certain PPAs
include a fixed payment for fixed generation capacity over the term of the
contract. Southern Company's unregulated distributed generation business also
has partially satisfied performance obligations related to certain fixed price
contracts. Revenues from contracts with customers related to these performance
obligations remaining at December 31, 2021 are expected to be recognized as
follows:
2022 2023 2024 2025 2026 Thereafter
(in millions)
Southern Company $ 577 $ 462 $ 341 $ 319 $ 295 $ 2,309
Alabama Power 33 24 7 5 - -
Georgia Power 68 48 25 22 11 31
Southern Power 331 293 309 292 287 2,294
Revenue expected to be recognized for performance obligations remaining at December 31, 2021 was immaterial for Mississippi Power.
5. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment is stated at original cost or fair value at
acquisition, as appropriate, less any regulatory disallowances and impairments.
Original cost may include: materials; labor; minor items of property;
appropriate administrative and general costs; payroll-related costs such as
taxes, pensions, and other benefits; and the interest capitalized and/or cost of
equity funds used during construction.
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The Registrants' property, plant, and equipment in service consisted of the following at December 31, 2021 and 2020:
Southern Southern Southern
At December 31, 2021: Company Alabama Power Georgia Power Mississippi Power Power Company Gas
(in millions)
Electric utilities:
Generation $ 53,803 $ 16,631 $ 19,184 $ 2,791 $ 14,551 $ -
Transmission 13,406 5,334 7,132 900 - -
Distribution 22,236 8,643 12,437 1,156 - -
General/other 5,423 2,527 2,579 259 34 -
Electric utilities' plant in service 94,868 33,135 41,332 5,106 14,585 -
Southern Company Gas:
Natural gas distribution utilities
transportation and distribution 15,714 - - - - 15,714
Storage facilities 1,315 - - - - 1,315
Other 1,851 - - - - 1,851
Southern Company Gas plant in service 18,880 - - - - 18,880
Other plant in service 1,844 - - - - -
Total plant in service $ 115,592 $ 33,135 $ 41,332 $ 5,106 $ 14,585 $ 18,880
Southern Southern Southern
At December 31, 2020: Company Alabama Power Georgia Power Mississippi Power Power Company Gas
(in millions)
Electric utilities:
Generation $ 52,179 $ 16,201 $ 18,675 $ 2,819 $ 13,872 $ -
Transmission 12,879 5,033 6,951 856 - -
Distribution 20,958 8,248 11,622 1,088 - -
General/other 5,072 2,334 2,434 248 32 -
Electric utilities' plant in service 91,088 31,816 39,682 5,011 13,904 -
Southern Company Gas:
Natural gas distribution utilities
transportation and distribution 14,610 - - - - 14,610
Storage facilities 1,752 - - - - 1,752
Other 1,249 - - - - 1,249
Southern Company Gas plant in service 17,611 - - - - 17,611
Other plant in service 1,817 - - - - -
Total plant in service $ 110,516 $ 31,816 $ 39,682 $ 5,011 $ 13,904 $ 17,611
The cost of replacements of property, exclusive of minor items of property, is
capitalized. The cost of maintenance, repairs, and replacement of minor items of
property is charged to other operations and maintenance expenses as incurred or
performed with the exception of nuclear refueling costs and certain maintenance
costs including those described below.
In accordance with orders from their respective state PSCs, Alabama Power and
Georgia Power defer nuclear refueling outage operations and maintenance expenses
to a regulatory asset when the charges are incurred. Alabama Power amortizes the
costs over a subsequent 18-month period with Plant Farley's fall outage cost
amortization beginning in January of the following year and spring outage cost
amortization beginning in July of the same year. Georgia Power amortizes its
costs over each unit's operating cycle, or 18 months for Plant Vogtle Units 1
and 2 and 24 months for Plant Hatch Units 1 and 2. Georgia Power's amortization
period begins the month the refueling outage starts.
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A portion of Mississippi Power's railway track maintenance costs is charged to fuel stock and recovered through Mississippi Power's fuel clause.
The portion of Southern Company Gas' non-working gas used to maintain the structural integrity of natural gas storage facilities that is considered to be non-recoverable is depreciated, while the recoverable or retained portion is not depreciated.
See Note 9 for information on finance lease right-of-use (ROU) assets, net, which are included in property, plant, and equipment.
The Registrants have deferred certain implementation costs related to cloud
hosting arrangements. Once a hosted software is placed into service, the related
deferred costs are amortized on a straight-line basis over the remaining
expected hosting arrangement term, including any renewal options that are
reasonably certain of exercise. The amortization is reflected with the
associated cloud hosting fees, which are generally reflected in other operations
and maintenance expenses on the Registrants' statements of income. At
December 31, 2021 and 2020, deferred cloud implementation costs, which are
generally included in other deferred charges and assets on the Registrants'
balance sheets, are as follows:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
Deferred cloud implementation costs:
At December 31, 2021 $ 240 $ 54 $ 81 $ 11 $ 14 $ 35
At December 31, 2020 162 38 58 7 9 17
Depreciation and Amortization
The traditional electric operating companies' and Southern Company Gas' depreciation of the original cost of utility plant in service is provided primarily by using composite straight-line rates. The approximate rates for 2021, 2020, and 2019 are as follows:
2021 2020 2019
Alabama Power 2.7 % 2.6 % 3.1 %
Georgia Power 3.3 % 3.0 % 2.6 %
Mississippi Power 3.6 % 3.7 % 3.7 %
Southern Company Gas 2.8 % 2.8 % 2.9 %
Depreciation studies are conducted periodically to update the composite rates.
These studies are filed with the respective state PSC and/or other applicable
state and federal regulatory agencies for the traditional electric operating
companies and the natural gas distribution utilities. During 2020, Georgia
Power, Mississippi Power, and Atlanta Gas Light revised their depreciation rates
in accordance with base rate case approvals by their respective PSCs. The
revised rates were effective January 1, 2020 for Georgia Power and Atlanta Gas
Light and April 1, 2020 for Mississippi Power. See Note 2 for additional
information.
When property, plant, and equipment subject to composite depreciation is retired
or otherwise disposed of in the normal course of business, its original cost,
together with the cost of removal, less salvage, is charged to accumulated
depreciation. For other property dispositions, the applicable cost and
accumulated depreciation are removed from the balance sheet accounts, and a gain
or loss is recognized. Minor items of property included in the original cost of
the asset are retired when the related property unit is retired.
At December 31, 2021 and 2020, accumulated depreciation for Southern Company and
Southern Company Gas consisted of utility plant in service totaling $33.1
billion and $31.6 billion, respectively, for Southern Company and $4.8 billion
and $4.6 billion, respectively, for Southern Company Gas, as well as other plant
in service totaling $930 million and $817 million, respectively, for Southern
Company and $219 million and $195 million, respectively, for Southern Company
Gas. Other plant in service includes the non-utility assets of Southern Company
Gas, as well as, for Southern Company, certain other non-utility subsidiaries.
Depreciation of the original cost of other plant in service is provided
primarily on a straight-line basis over estimated useful lives. Useful lives for
Southern Company Gas's non-utility assets range from five to 12 years for
transportation equipment, 30 to 75 years for storage facilities, and up to 75
years for other assets. Useful lives for the assets of Southern Company's other
non-utility subsidiaries range up to 37 years.
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Southern Power
Southern Power applies component depreciation, where depreciation is computed
principally by the straight-line method over the estimated useful life of the
asset. Certain of Southern Power's generation assets related to natural
gas-fired facilities are depreciated on a units-of-production basis, using hours
or starts, to better match outage and maintenance costs to the usage of, and
revenues from, these assets. The primary assets in Southern Power's property,
plant, and equipment are generating facilities, which generally have estimated
useful lives as follows:
Southern Power Generating Facility Useful life
Natural gas Up to 50 years
Solar Up to 35 years
Wind Up to 30 years
When Southern Power's depreciable property, plant, and equipment is retired, or
otherwise disposed of in the normal course of business, the applicable cost and
accumulated depreciation is removed and a gain or loss is recognized in the
statements of income. Southern Power reviews its estimated useful lives and
salvage values on an ongoing basis. The results of these reviews could result in
changes which could have a material impact on Southern Power's net income.
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Joint Ownership Agreements
At December 31, 2021, the Registrants' percentage ownership and investment
(exclusive of nuclear fuel) in jointly-owned facilities in commercial operation
were as follows:
Percent Accumulated
Facility (Type) Ownership Plant in Service Depreciation CWIP
(in millions)
Alabama Power
Greene County (natural gas) Units
1 and 2 60.0 % (a) $ 191 $ 79 $ 1
Plant Miller (coal) Units 1 and 2 91.8 (b) 2,133 665 15
Georgia Power
Plant Hatch (nuclear) 50.1 % (c) $ 1,382 $ 647 $ 42
Plant Vogtle (nuclear) Units 1 and
2 45.7 (c) 3,611 2,265 86
Plant Scherer (coal) Units 1 and 2 8.4 (c) 276 100 1
Plant Scherer (coal) Unit 3 75.0 (c) 1,314 539 8
Plant Wansley (coal) 53.5 (c) 1,070 472 7
Rocky Mountain (pumped storage) 25.4 (d) 184 148 1
Mississippi Power
Greene County (natural gas) Units
1 and 2 40.0 % (a) $ 124 $ 61 $ -
Plant Daniel (coal) Units 1 and 2 50.0 (e) 762 237 19
Southern Company Gas
Dalton Pipeline (natural gas
pipeline) 50.0 % (f) $ 271 $ 19 $ -
(a)Jointly owned by Alabama Power and Mississippi Power and operated and maintained by Alabama Power.
(b)Jointly owned with PowerSouth and operated and maintained by Alabama Power.
(c)Georgia Power owns undivided interests in Plants Hatch, Vogtle Units 1 and 2, Scherer, and Wansley in varying amounts jointly with one or more of the following entities: OPC, MEAG Power, Dalton, Florida Power & Light Company, JEA, and Gulf Power. Georgia Power has been contracted to operate and maintain the plants as agent for the co-owners and is jointly and severally liable for third party claims related to these plants.
(d)Jointly owned with OPC, which is the operator of the plant.
(e)Jointly owned by Gulf Power and Mississippi Power. In accordance with the operating agreement, Mississippi Power acts as Gulf Power's agent with respect to the operation and maintenance of these units. See Note 3 under "Other Matters - Mississippi Power - Plant Daniel" for information regarding a commitment between Mississippi Power and Gulf Power to seek a restructuring of their 50% undivided ownership interests in Plant Daniel. (f)Jointly owned with The Williams Companies, Inc., the Dalton Pipeline is a 115-mile natural gas pipeline that serves as an extension of the Transcontinental Gas Pipe Line Company, LLC pipeline system into northwest Georgia. Southern Company Gas leases its 50% undivided ownership for approximately $26 million annually through 2042. The lessee is responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC-regulated tariff. Georgia Power also owns 45.7% of Plant Vogtle Units 3 and 4, which are currently under construction and had a CWIP balance of $8.6 billion at December 31, 2021, excluding estimated probable losses recorded in 2018, 2020, and 2021. See Note 2 under "Georgia Power - Nuclear Construction" for additional information. The Registrants' proportionate share of their jointly-owned facility operating expenses is included in the corresponding operating expenses in the statements of income and each Registrant is responsible for providing its own financing.
Assets Subject to Lien
In 2018, the Mississippi PSC approved executed agreements between Mississippi
Power and its largest retail customer, Chevron Products Company (Chevron), for
Mississippi Power to continue providing retail service to the Chevron refinery
in Pascagoula, Mississippi through at least 2038. The agreements grant Chevron a
security interest in the co-generation assets owned by Mississippi Power, with a
lease receivable balance of $167 million at December 31, 2021, located at the
refinery that is exercisable upon the occurrence of (i) certain bankruptcy
events or (ii) other events of default coupled with specific reductions in steam
output at the facility and a downgrade of Mississippi Power's credit rating to
below investment grade by two of the three rating agencies.
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See Note 8 under "Long-term Debt" for information regarding debt secured by certain assets of Georgia Power and Southern Company Gas.
6. ASSET RETIREMENT OBLIGATIONS
AROs are computed as the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The estimated costs are capitalized as part of the related long-lived asset and depreciated over the asset's useful life. In the absence of quoted market prices, AROs are estimated using present value techniques in which estimates of future cash outlays associated with the asset retirements are discounted using a credit-adjusted risk-free rate. Estimates of the timing and amounts of future cash outlays are based on projections of when and how the assets will be retired and the cost of future removal activities. Each traditional electric operating company and natural gas distribution utility has received accounting guidance from its state PSC or applicable state regulatory agency allowing the continued accrual or recovery of other retirement costs for long-lived assets that it does not have a legal obligation to retire. Accordingly, the accumulated removal costs for these obligations are reflected in the balance sheets as regulatory liabilities and amounts to be recovered are reflected in the balance sheets as regulatory assets. The ARO liabilities for the traditional electric operating companies primarily relate to facilities that are subject to the CCR Rule and the related state rules, principally ash ponds. In addition, Alabama Power and Georgia Power have retirement obligations related to the decommissioning of nuclear facilities (Alabama Power's Plant Farley and Georgia Power's ownership interests in Plant Hatch and Plant Vogtle Units 1 and 2). See "Nuclear Decommissioning" herein for additional information. Other significant AROs include various landfill sites and asbestos removal for Alabama Power, Georgia Power, and Mississippi Power and gypsum cells and mine reclamation for Mississippi Power. The ARO liability for Southern Power primarily relates to its solar and wind facilities, which are located on long-term land leases requiring the restoration of land at the end of the lease. The traditional electric operating companies and Southern Company Gas also have identified other retirement obligations, such as obligations related to certain electric transmission and distribution facilities, certain asbestos-containing material within long-term assets not subject to ongoing repair and maintenance activities, certain wireless communication towers, the disposal of polychlorinated biphenyls in certain transformers, leasehold improvements, equipment on customer property, and property associated with the Southern Company system's rail lines and natural gas pipelines. However, liabilities for the removal of these assets have not been recorded because the settlement timing for certain retirement obligations related to these assets is indeterminable and, therefore, the fair value of the retirement obligations cannot be reasonably estimated. A liability for these retirement obligations will be recognized when sufficient information becomes available to support a reasonable estimation of the ARO. Southern Company and the traditional electric operating companies will continue to recognize in their respective statements of income allowed removal costs in accordance with regulatory treatment. Any differences between costs recognized in accordance with accounting standards related to asset retirement and environmental obligations and those reflected in rates are recognized as either a regulatory asset or liability in the balance sheets as ordered by the various state PSCs.
Details of the AROs included in the balance sheets are as follows:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Power(*)
(in millions)
Balance at December 31, 2019 $ 9,786 $ 3,540 $ 5,784 $ 190 $ 89
Liabilities incurred 19 - 10 - 9
Liabilities settled (442) (219) (185) (22) -
Accretion 409 152 238 8 4
Cash flow revisions 912 501 418 - (7)
Balance at December 31, 2020 $ 10,684 $ 3,974 $ 6,265 $ 176 $ 95
Liabilities incurred 26 - 3 - 23
Liabilities settled (456) (202) (210) (24) -
Accretion 407 156 236 7 5
Cash flow revisions 1,026 406 530 31 8
Balance at December 31, 2021 $ 11,687 $ 4,334 $ 6,824 $ 190 $ 131
(*)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
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During 2020, Alabama Power recorded increases totaling approximately $501
million to its AROs related to the CCR Rule and the related state rule primarily
as a result of management's completion of the closure design for the remaining
ash pond and the addition of a water treatment system to the design of another
ash pond. The additional estimated costs to close these ash ponds under the
planned closure-in-place methodology primarily relate to inputs from contractor
bids, design revisions, and changes in the expected volume of ash handling.
During 2021, Alabama Power recorded increases totaling approximately $406
million to its AROs primarily related to the CCR Rule and the related state rule
based on updated estimates for post-closure costs at its ash ponds and inflation
rates.
During the third quarter 2020, Georgia Power refined the cost estimates related
to its plans to close the ash ponds at all of its generating plants in
compliance with the CCR Rule and the related state rule, including updates to
long-term post-closure care requirements, market pricing, and timing of future
cash outlays and recorded an increase of approximately $411 million to its AROs
related to the CCR Rule and the related state rule. In September 2021, Georgia
Power recorded a further increase of approximately $435 million to these AROs
based on updated estimates for inflation rates and the timing of closure
activities.
In September 2021, Mississippi Power recorded an increase of approximately $31
million to its AROs related to the CCR Rule based on updated estimates for the
timing of closure activities, post-closure costs at one of its ash ponds, and
inflation rates.
The cost estimates for AROs related to the disposal of CCR are based on
information at December 31, 2021 using various assumptions related to closure
and post-closure costs, timing of future cash outlays, inflation and discount
rates, and the potential methods for complying with the CCR Rule and the related
state rules. The traditional electric operating companies have periodically
updated, and expect to continue periodically updating, their related cost
estimates and ARO liabilities for each CCR unit as additional information
related to these assumptions becomes available. Some of these updates have been,
and future updates may be, material. Additionally, the closure designs and plans
in the States of Alabama and Georgia are subject to approval by environmental
regulatory agencies. Absent continued recovery of ARO costs through regulated
rates, results of operations, cash flows, and financial condition for Southern
Company and the traditional electric operating companies could be materially
impacted. See Note 2 under "Georgia Power - Rate Plans" for additional
information. The ultimate outcome of these matters cannot be determined at this
time.
Nuclear Decommissioning
The NRC requires licensees of commercial nuclear power reactors to establish a
plan for providing reasonable assurance of funds for future decommissioning.
Alabama Power and Georgia Power have external trust funds (Funds) to comply with
the NRC's regulations. Use of the Funds is restricted to nuclear decommissioning
activities. The Funds are managed and invested in accordance with applicable
requirements of various regulatory bodies, including the NRC, the FERC, and
state PSCs, as well as the IRS. While Alabama Power and Georgia Power are
allowed to prescribe an overall investment policy to the Funds' managers,
neither Southern Company nor its subsidiaries or affiliates are allowed to
engage in the day-to-day management of the Funds or to mandate individual
investment decisions. Day-to-day management of the investments in the Funds is
delegated to unrelated third-party managers with oversight by the management of
Alabama Power and Georgia Power. The Funds' managers are authorized, within
certain investment guidelines, to actively buy and sell securities at their own
discretion in order to maximize the return on the Funds' investments. The Funds
are invested in a tax-efficient manner in a diversified mix of equity and fixed
income securities and are reported as trading securities.
Alabama Power and Georgia Power record the investment securities held in the
Funds at fair value, as disclosed in Note 13, as management believes that fair
value best represents the nature of the Funds. Gains and losses, whether
realized or unrealized, are recorded in the regulatory liability for AROs in the
balance sheets and are not included in net income or OCI. Fair value adjustments
and realized gains and losses are determined on a specific identification basis.
The Funds at Georgia Power participate in a securities lending program through
the managers of the Funds. Under this program, Georgia Power's Funds' investment
securities are loaned to institutional investors for a fee. Securities loaned
are fully collateralized by cash, letters of credit, and/or securities issued or
guaranteed by the U.S. government or its agencies or instrumentalities. At
December 31, 2021 and 2020, approximately $42 million and $44 million,
respectively, of the fair market value of Georgia Power's Funds' securities were
on loan and pledged to creditors under the Funds' managers' securities lending
program. The fair value of the collateral received was approximately $43 million
and $45 million at December 31, 2021 and 2020, respectively, and can only be
sold by the borrower upon the return of the loaned securities. The collateral
received is treated as a non-cash item in the statements of cash flows.
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Investment securities in the Funds for December 31, 2021 and 2020 were as
follows:
Alabama Georgia
Southern Company Power Power
(in millions)
At December 31, 2021:
Equity securities $ 1,358 $ 849 $ 509
Debt securities 986 316 670
Other securities 197 159 38
Total investment securities in the Funds $ 2,541 $ 1,324 $ 1,217
At December 31, 2020:
Equity securities $ 1,339 $ 842 $ 497
Debt securities 851 231 620
Other securities 111 83 28
Total investment securities in the Funds $ 2,301 $ 1,156 $ 1,145
These amounts exclude receivables related to investment income and pending investment sales and payables related to pending investment purchases. For Southern Company and Georgia Power, these amounts include Georgia Power's investment securities pledged to creditors and collateral received and excludes payables related to Georgia Power's securities lending program.
The fair value increases (decreases) of the Funds, including unrealized gains (losses) and reinvested interest and dividends and excluding the Funds' expenses, for 2021, 2020, and 2019 are shown in the table below.
Alabama Georgia
Southern Company Power Power
(in millions)
Fair value increases
2021 $ 274 $ 200 $ 74
2020 280 142 138
2019 344 194 150
Unrealized gains (losses)
At December 31, 2021 $ (27) $ (30) $ 3
At December 31, 2020 220 121 99
At December 31, 2019 259 149 110
The investment securities held in the Funds continue to be managed with a long-term focus. Accordingly, all purchases and sales within the Funds are presented separately in the statements of cash flows as investing cash flows, consistent with the nature of the securities and purpose for which the securities were acquired.
For Alabama Power, approximately $15 million at each of December 31, 2021 and
2020 previously recorded in internal reserves is being transferred into the
Funds through 2040 as approved by the Alabama PSC. The NRC's minimum external
funding requirements are based on a generic estimate of the cost to decommission
only the radioactive portions of a nuclear unit based on the size and type of
reactor. Alabama Power and Georgia Power have filed plans with the NRC designed
to ensure that, over time, the deposits and earnings of the Funds will provide
the minimum funding amounts prescribed by the NRC.
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At December 31, 2021 and 2020, the accumulated provisions for the external decommissioning trust funds were as follows:
2021 2020
(in millions)
Alabama Power
Plant Farley $ 1,324 $ 1,156
Georgia Power
Plant Hatch $ 757 $ 716
Plant Vogtle Units 1 and 2 460 429
Total $ 1,217 $ 1,145
Site study cost is the estimate to decommission a specific facility as of the
site study year. The decommissioning cost estimates are based on prompt
dismantlement and removal of the plant from service. The actual decommissioning
costs may vary from these estimates because of changes in the assumed date of
decommissioning, changes in NRC requirements, or changes in the assumptions used
in making these estimates. The estimated costs of decommissioning at
December 31, 2021 based on the most current studies, which were performed in
2018 for Alabama Power and in 2021 for Georgia Power, were as follows:
Plant Plant Plant Vogtle
Farley Hatch(*) Units 1 and 2(*)
Decommissioning periods:
Beginning year 2037 2034 2047
Completion year 2076 2075 2079
(in millions)
Site study costs:
Radiated structures $ 1,234 $ 771 $ 628
Spent fuel management 387 186 170
Non-radiated structures 99 61 85
Total site study costs $ 1,720 $ 1,018 $ 883
(*)Based on Georgia Power's ownership interests.
For ratemaking purposes, Alabama Power's decommissioning costs are based on the site study and Georgia Power's decommissioning costs are based on the NRC generic estimate to decommission the radioactive portion of the facilities and the site study estimate for spent fuel management as of 2021. Significant assumptions used to determine these costs for ratemaking were an estimated inflation rate of 4.5% and 2.5% for Alabama Power and Georgia Power, respectively, and an estimated trust earnings rate of 7.0% and 4.5% for Alabama Power and Georgia Power, respectively. Amounts previously contributed to the Funds for Plant Farley are currently projected to be adequate to meet the decommissioning obligations. Alabama Power will continue to provide site-specific estimates of the decommissioning costs and related projections of funds in the external trust to the Alabama PSC and, if necessary, would seek the Alabama PSC's approval to address any changes in a manner consistent with NRC and other applicable requirements. Effective January 1, 2020, in connection with the 2019 ARP, Georgia Power's annual decommissioning cost for ratemaking is a total of $4 million for Plant Hatch and Plant Vogtle Units 1 and 2. Georgia Power's annual decommissioning cost for ratemaking in 2019 totaled $5 million.
7. CONSOLIDATED ENTITIES AND EQUITY METHOD INVESTMENTS
The Registrants may hold ownership interests in a number of business ventures
with varying ownership structures. Partnership interests and other variable
interests are evaluated to determine if each entity is a VIE. If a venture is a
VIE for which a Registrant is the primary beneficiary, the assets, liabilities,
and results of operations of the entity are consolidated. The Registrants
reassess the conclusion as to whether an entity is a VIE upon certain
occurrences, which are deemed reconsideration events.
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For entities that are not determined to be VIEs, the Registrants evaluate whether they have control or significant influence over the investee to determine the appropriate consolidation and presentation. Generally, entities under the control of a Registrant are consolidated, and entities over which a Registrant can exert significant influence, but which a Registrant does not control, are accounted for under the equity method of accounting. Investments accounted for under the equity method are recorded within equity investments in unconsolidated subsidiaries in the balance sheets and, for Southern Company and Southern Company Gas, the equity income is recorded within earnings from equity method investments in the statements of income. See "SEGCO" and "Southern Company Gas" herein for additional information.
SEGCO
Alabama Power and Georgia Power own equally all of the outstanding capital stock of SEGCO, which owns electric generating units with a total rated capacity of 1,020 MWs, as well as associated transmission facilities. Alabama Power and Georgia Power account for SEGCO using the equity method; Southern Company consolidates SEGCO. The capacity of these units is sold equally to Alabama Power and Georgia Power. Alabama Power and Georgia Power make payments sufficient to provide for the operating expenses, taxes, interest expense, and a ROE. The share of purchased power included in purchased power, affiliates in the statements of income totaled $75 million in 2021, $67 million in 2020, and $93 million in 2019 for Alabama Power and $77 million in 2021, $69 million in 2020, and $95 million in 2019 for Georgia Power.
SEGCO paid dividends of $14 million in 2021, $12 million in 2020, and $14 million in 2019, one half of which were paid to each of Alabama Power and Georgia Power. In addition, Alabama Power and Georgia Power each recognize 50% of SEGCO's net income.
Alabama Power, which owns and operates a generating unit adjacent to the SEGCO generating units, has a joint ownership agreement with SEGCO for the ownership of an associated gas pipeline. Alabama Power owns 14% of the pipeline with the remaining 86% owned by SEGCO.
See Note 3 under "Guarantees" for additional information regarding guarantees of Alabama Power and Georgia Power related to SEGCO.
Southern Power
Variable Interest Entities
Southern Power has certain subsidiaries that are determined to be VIEs. Southern Power is considered the primary beneficiary of these VIEs because it controls the most significant activities of the VIEs, including operating and maintaining the respective assets, and has the obligation to absorb expected losses of these VIEs to the extent of its equity interests.
SP Solar and SP Wind
In 2018, Southern Power sold a noncontrolling 33% limited partnership interest
in SP Solar to Global Atlantic Financial Group Limited (Global Atlantic). A
wholly-owned subsidiary of Southern Power is the general partner and holds a 1%
ownership interest in SP Solar and another wholly-owned subsidiary of Southern
Power owns the remaining 66% ownership in SP Solar. SP Solar qualifies as a VIE
since the arrangement is structured as a limited partnership and the 33% limited
partner does not have substantive kick-out rights against the general partner.
At December 31, 2021 and 2020, SP Solar had total assets of $6.1 billion, total
liabilities of $408 million and $387 million, respectively, and noncontrolling
interests of $1.1 billion. Cash distributions from SP Solar are allocated 67% to
Southern Power and 33% to Global Atlantic in accordance with their partnership
interest percentage. Under the terms of the limited partnership agreement,
distributions without limited partner consent are limited to available cash and
SP Solar is obligated to distribute all such available cash to its partners each
quarter. Available cash includes all cash generated in the quarter subject to
the maintenance of appropriate operating reserves.
In 2018, Southern Power sold a noncontrolling tax equity interest in SP Wind to
three financial investors. Southern Power owns 100% of the Class B membership
interests and the three financial investors own 100% of the Class A membership
interests. SP Wind qualifies as a VIE since the structure of the arrangement is
similar to a limited partnership and the Class A members do not have substantive
kick-out rights against Southern Power.
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At December 31, 2021 and 2020, SP Wind had total assets of $2.3 billion and $2.4 billion, respectively, total liabilities of $130 million and $138 million, respectively, and noncontrolling interests of $41 million and $43 million, respectively. Under the terms of the limited liability agreement, distributions without Class A member consent are limited to available cash and SP Wind is obligated to distribute all such available cash to its members each quarter. Available cash includes all cash generated in the quarter subject to the maintenance of appropriate operating reserves. Cash distributions from SP Wind are generally allocated 60% to Southern Power and 40% to the three financial investors in accordance with the limited liability agreement. Southern Power consolidates both SP Solar and SP Wind, as the primary beneficiary, since it controls the most significant activities of each entity, including operating and maintaining their assets. Certain transfers and sales of the assets in the VIEs are subject to partner consent and the liabilities are non-recourse to the general credit of Southern Power. Liabilities consist of customary working capital items and do not include any long-term debt.
Other Variable Interest Entities
Southern Power has other consolidated VIEs that relate to certain subsidiaries that have either sold noncontrolling interests to tax equity investors or acquired less than a 100% interest from facility developers. These entities are considered VIEs because the arrangements are structured similar to a limited partnership and the noncontrolling members do not have substantive kick-out rights. At December 31, 2021 and 2020, the other VIEs had total assets of $1.9 billion and $1.1 billion, respectively, total liabilities of $263 million and $110 million, respectively, and noncontrolling interests of $886 million and $454 million, respectively. Under the terms of the partnership agreements, distributions of all available cash are required each month or quarter and additional distributions require partner consent.
Equity Method Investments
At December 31, 2021 and 2020, Southern Power had equity method investments in wind and battery energy storage projects totaling $86 million and $19 million, respectively. Earnings (loss) from these investments were immaterial for all periods presented. Subsequent to December 31, 2021, Southern Power sold an equity method investment in a wind project and received proceeds of $31 million. The gain associated with the transaction was immaterial.
Southern Company Gas
Equity Method Investments
The carrying amounts of Southern Company Gas' equity method investments at December 31, 2021 and 2020 and related earnings (loss) from those investments for the years ended December 31, 2021, 2020, and 2019 were as follows:
Investment Balance December 31, 2021 December 31, 2020
(in millions)
SNG(a) $ 1,129 $ 1,167
PennEast Pipeline(b) 11 91
Other 33 32
Total $ 1,173 $ 1,290
(a)Decrease primarily relates to the continued amortization of deferred tax assets established upon acquisition, as well as distributions in excess of earnings.
(b)Investment balance at December 31, 2021 reflects pre-tax impairment charges
totaling $84 million recorded during 2021. See "PennEast Pipeline Project"
herein for additional information, including the September 2021 cancellation of
the project.
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Earnings (Loss) from Equity Method Investments 2021 2020 2019
(in millions)
SNG $ 127 $ 129 $ 141
Atlantic Coast Pipeline(a)(b) - 3 13
PennEast Pipeline(a)(c) (81) 7 6
Other(d) 4 2 (3)
Total $ 50 $ 141 $ 157
(a)Earnings primarily result from AFUDC equity recorded by the project entity.
(b)In March 2020, Southern Company Gas completed the sale of its interest in Atlantic Coast Pipeline. See Note 15 under "Southern Company Gas" for additional information.
(c)For 2021, includes pre-tax impairment charges totaling $84 million. See "PennEast Pipeline Project" herein for additional information, including the September 2021 cancellation of the project.
(d)In March 2020, Southern Company Gas completed the sale of its interest in Pivotal LNG. See Note 15 under "Southern Company Gas" for additional information.
PennEast Pipeline Project
In 2014, Southern Company Gas entered into a partnership in which it holds a 20% ownership interest in the PennEast Pipeline, an interstate pipeline company formed to develop and operate an approximate 118-mile natural gas pipeline between New Jersey and Pennsylvania.
In 2019, an appellate court ruled that the PennEast Pipeline does not have
federal eminent domain authority over lands in which a state has property rights
interests. On June 29, 2021, the U.S. Supreme Court ruled in favor of PennEast
Pipeline following a review of the appellate court decision. Southern Company
Gas assesses its equity method investments for impairment whenever events or
changes in circumstances indicate that the investment may be impaired. Following
the U.S. Supreme Court ruling, during the second quarter 2021, Southern Company
Gas management reassessed the project construction timing, including the
anticipated timing for receipt of a FERC certificate and all remaining state and
local permits, as well as potential challenges thereto, and performed an
impairment analysis. The outcome of the analysis resulted in a pre-tax
impairment charge of $82 million ($58 million after tax).
On September 27, 2021, PennEast Pipeline announced that further development of
the project is no longer supported, and, as a result, all further development of
the project has ceased. During the third quarter 2021, Southern Company Gas
recorded an additional pre-tax charge of $2 million ($2 million after tax)
related to its share of the project level impairment, as well as $7 million of
additional tax expense, resulting in total pre-tax charges of $84 million
($67 million after tax) during 2021 related to the project.
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8. FINANCING
Long-term Debt
Details of long-term debt at December 31, 2021 and 2020 are provided in the
following table:
Balance Outstanding at
At December 31, 2021 December 31,
Weighted Average
Maturity Interest Rate 2021 2020
(in millions)
Southern Company
Senior notes(a) 2022-2052 3.62% $ 33,120 $ 30,850
Junior subordinated notes 2024-2081 4.00% 8,918 7,295
FFB loans(b) 2022-2044 2.88% 4,962 4,618
Pollution control revenue bonds(c) 2022-2053 1.05% 2,662 2,675
First mortgage bonds(d) 2023-2060 3.53% 2,100 1,900
Medium-term notes 2022-2027 7.60% 130 160
Other long-term debt 2022-2026 0.79% 270 370
Other revenue bonds - 320
Debt payable to affiliated trusts(e) - 206
Finance lease obligations(f) 215 231
Unamortized fair value adjustment 359 393
Unamortized debt premium (discount), net (216) (201)
Unamortized debt issuance expenses (243) (237)
Total long-term debt 52,277 48,580
Less: Amount due within one year 2,157 3,507
Total long-term debt excluding amount due
within one year $ 50,120 $ 45,073
Alabama Power
Senior notes 2022-2052 3.89% $ 8,725 $ 7,625
Pollution control revenue bonds(c) 2024-2038 0.55% 995 1,060
Other long-term debt 2026 1.24% 45 45
Debt payable to affiliated trusts(e) - 206
Finance lease obligations(f) 4 5
Unamortized debt premium (discount), net (18) (16)
Unamortized debt issuance expenses (64) (56)
Total long-term debt 9,687 8,869
Less: Amount due within one year 751 311
Total long-term debt excluding amount due
within one year $ 8,936 $ 8,558
Georgia Power
Senior notes 2022-2051 3.61% $ 6,825 $ 6,400
Junior subordinated notes 2077 5.00% 270 270
FFB loans(b) 2022-2044 2.88% 4,962 4,618
Pollution control revenue bonds(c) 2022-2053 1.33% 1,591 1,538
Other long-term debt 2022 0.70% 125 125
Finance lease obligations(f) 136 145
Unamortized debt premium (discount), net (11) (12)
Unamortized debt issuance expenses (114) (114)
Total long-term debt 13,784 12,970
Less: Amount due within one year 675 542
Total long-term debt excluding amount due
within one year $ 13,109 $ 12,428
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Balance Outstanding at
At December 31, 2021 December 31,
Weighted Average
Maturity Interest Rate 2021 2020
(in millions)
Mississippi Power
Senior notes 2024-2051 3.43% $ 1,425 $ 900
Pollution control revenue bonds(c) 2025-2028 1.86% 76 76
Other revenue bonds - 320
Other long-term debt - 100
Finance lease obligations(f) 18 19
Unamortized debt premium (discount), net 2 11
Unamortized debt issuance expenses (10) (7)
Total long-term debt 1,511 1,419
Less: Amount due within one year 1 406
Total long-term debt excluding amount due
within one year $ 1,510 $ 1,013
Southern Power
Senior notes(a) 2022-2046 3.74% $ 3,711 $ 3,714
Unamortized debt premium (discount), net (6) (6)
Unamortized debt issuance expenses (17) (16)
Total long-term debt 3,688 3,692
Less: Amount due within one year 679 299
Total long-term debt excluding amount due
within one year $ 3,009 $ 3,393
Southern Company Gas
Senior notes 2023-2051 3.96% $ 4,348 $ 4,200
First mortgage bonds(d) 2023-2060 3.53% 2,100 1,900
Medium-term notes 2022-2027 7.60% 130 160
Unamortized fair value adjustment 359 393
Unamortized debt premium (discount), net (35) (27)
Total long-term debt 6,902 6,626
Less: Amount due within one year 47 333
Total long-term debt excluding amount due
within one year $ 6,855 $ 6,293
(a)Includes a fair value gain (loss) of $5 million and $109 million at December 31, 2021 and 2020, respectively, related to Southern Power's foreign currency hedge on its €1.1 billion senior notes.
(b)Secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. See "DOE Loan Guarantee Borrowings" herein for additional information. (c)Pollution control revenue bond obligations represent loans to the traditional electric operating companies from public authorities of funds derived from sales by such authorities of revenue bonds issued to finance pollution control and solid waste disposal facilities. In some cases, the pollution control revenue bond obligations represent obligations under installment sales agreements with respect to facilities constructed with the proceeds of revenue bonds issued by public authorities. The traditional electric operating companies are required to make payments sufficient for the authorities to meet principal and interest requirements of such bonds. Proceeds from certain issuances are restricted until qualifying expenditures are incurred.
(d)Secured by substantially all of Nicor Gas' properties.
(e)At December 31, 2020, Alabama Power had a wholly-owned trust subsidiary for the purpose of issuing preferred securities. The proceeds of the related equity investments and preferred security sales were loaned back to Alabama Power through the issuance of junior subordinated notes, which Alabama Power redeemed during 2021. The junior subordinated notes constituted substantially all of the assets of this trust. Alabama Power considered the mechanisms and obligations relating to the preferred securities issued for its benefit, taken together, constituted a full and unconditional guarantee by it of the trust's payment obligations with respect to these securities. See Note 1 under "Variable Interest Entities" for additional information on the accounting treatment for this trust and the related securities.
(f)Secured by the underlying lease ROU asset. See Note 9 for additional information.
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Maturities of long-term debt for the next five years are as follows:
Southern Georgia Southern Company
Company(a) Alabama Power Power(b) Mississippi Power Southern Power(c) Gas
(in millions)
2022 $ 2,157 $ 751 $ 676 $ 1 $ 677 $ 46
2023 3,738 301 897 1 290 400
2024 2,280 22 498 201 - -
2025 1,199 250 145 11 500 300
2026 3,723 45 441 1 964 530
(a)Amount for 2022 excludes junior subordinated notes totaling $1.725 billion at
the parent entity that Southern Company has agreed to remarket in 2022 in
connection with the related stock purchase contracts; however, the final
maturity dates are in 2024 and 2027 (one half in each year). See "Equity Units"
herein for additional information. Also see notes (b) and (c) below.
(b)Amounts include principal amortization related to the FFB borrowings; however, the final maturity date is February 20, 2044. See "DOE Loan Guarantee Borrowings" herein for additional information.
(c)Southern Power's 2022 maturity and $564 million of its 2026 maturities represent euro-denominated debt at the U.S. dollar denominated hedge settlement amount.
DOE Loan Guarantee Borrowings
Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (Title XVII Loan Guarantee Program), Georgia Power and the DOE entered into a loan guarantee agreement in 2014 and the Amended and Restated Loan Guarantee Agreement in March 2019. Under the Amended and Restated Loan Guarantee Agreement, the DOE agreed to guarantee the obligations of Georgia Power under the FFB Credit Facilities. Under the FFB Credit Facilities, Georgia Power was authorized to make term loan borrowings through the FFB in an amount up to approximately $5.130 billion, provided that total aggregate borrowings under the FFB Credit Facilities could not exceed 70% of (i) Eligible Project Costs minus (ii) approximately $1.492 billion (reflecting the amounts received by Georgia Power under the Guarantee Settlement Agreement less the related customer refunds). In June 2021 and December 2021, Georgia Power made the final borrowings under the FFB Credit Facilities in aggregate principal amounts of $371 million and $69 million, respectively, at an interest rate of 2.434% and 2.178%, respectively, through the final maturity date of February 20, 2044. No further borrowings are permitted under the FFB Credit Facilities. During 2021, Georgia Power made principal amortization payments of $96 million under the FFB Credit Facilities. At December 31, 2021 and 2020, Georgia Power had $5.0 billion and $4.6 billion of borrowings outstanding under the FFB Credit Facilities, respectively. All borrowings under the FFB Credit Facilities are full recourse to Georgia Power, and Georgia Power is obligated to reimburse the DOE for any payments the DOE is required to make to the FFB under its guarantee. Georgia Power's reimbursement obligations to the DOE are full recourse and secured by a first priority lien on (i) Georgia Power's undivided ownership interest in Plant Vogtle Units 3 and 4 (primarily the units under construction, the related real property, and any nuclear fuel loaded in the reactor core) and (ii) Georgia Power's rights and obligations under the principal contracts relating to Plant Vogtle Units 3 and 4. There are no restrictions on Georgia Power's ability to grant liens on other property. The final maturity date for each advance under the FFB Credit Facilities is February 20, 2044. Interest is payable quarterly and principal payments began in February 2020. Each borrowing under the FFB Credit Facilities bears interest at a fixed rate equal to the applicable U.S. Treasury rate at the time of the borrowing plus a spread equal to 0.375%.
Under the Amended and Restated Loan Guarantee Agreement, Georgia Power is subject to customary borrower affirmative and negative covenants and events of default. In addition, Georgia Power is subject to project-related reporting requirements and other project-specific covenants and events of default.
In the event certain mandatory prepayment events occur, Georgia Power will be
required to prepay the outstanding principal amount of all borrowings under the
FFB Credit Facilities over a period of five years (with level principal
amortization). Among other things, these mandatory prepayment events include (i)
the termination of the Vogtle Services Agreement or rejection of the Vogtle
Services Agreement in any Westinghouse bankruptcy if Georgia Power does not
maintain access to intellectual property rights under the related intellectual
property licenses; (ii) termination of the Bechtel Agreement, unless the Vogtle
Owners enter into a replacement agreement; (iii) cancellation of Plant Vogtle
Units 3 and 4 by the Georgia PSC or by Georgia Power; (iv) failure of the
holders of 90% of the ownership interests in Plant Vogtle Units 3 and 4 to vote
to continue construction following certain schedule extensions; (v) cost
disallowances by the Georgia PSC that could have a material adverse effect on
completion of
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Plant Vogtle Units 3 and 4 or Georgia Power's ability to repay the outstanding borrowings under the FFB Credit Facilities; or (vi) loss of or failure to receive necessary regulatory approvals. Under certain circumstances, insurance proceeds and any proceeds from an event of taking must be applied to immediately prepay outstanding borrowings under the FFB Credit Facilities. Georgia Power also may voluntarily prepay outstanding borrowings under the FFB Credit Facilities. Under the FFB Credit Facilities, any prepayment (whether mandatory or optional) will be made with a make-whole premium or discount, as applicable. The latest extension of the schedule for Plant Vogtle Units 3 and 4 triggers the requirement that the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 must vote to continue construction. If the holders of at least 90% of the ownership interests of Plant Vogtle Units 3 and 4 do not vote to continue construction, the DOE may require Georgia Power to prepay all outstanding borrowings under the FFB Credit Facilities over a period of five years. In connection with any cancellation of Plant Vogtle Units 3 and 4, the DOE may elect to continue construction of Plant Vogtle Units 3 and 4. In such an event, the DOE will have the right to assume Georgia Power's rights and obligations under the principal agreements relating to Plant Vogtle Units 3 and 4 and to acquire all or a portion of Georgia Power's ownership interest in Plant Vogtle Units 3 and 4.
See Note 2 under "Georgia Power - Nuclear Construction" for additional information.
Secured Debt
Each of Southern Company's subsidiaries is organized as a legal entity, separate and apart from Southern Company and its other subsidiaries. There are no agreements or other arrangements among the Southern Company system companies under which the assets of one company have been pledged or otherwise made available to satisfy obligations of Southern Company or any of its other subsidiaries. As discussed under "Long-term Debt" herein, the Registrants had secured debt outstanding at December 31, 2021 and 2020. Each Registrant's senior notes, junior subordinated notes, pollution control and other revenue bond obligations, bank term loans, credit facility borrowings, and notes payable are effectively subordinated to all secured debt of each respective Registrant.
Equity Units
In 2019, Southern Company issued 34.5 million 2019 Series A Equity Units (Equity Units), initially in the form of corporate units (Corporate Units), at a stated amount of $50 per Corporate Unit, for a total stated amount of $1.725 billion. Net proceeds from the issuance were approximately $1.682 billion. The proceeds were used to repay short-term indebtedness and for other general corporate purposes, including investments in Southern Company's subsidiaries. Each Corporate Unit is comprised of (i) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019A Remarketable Junior Subordinated Notes (Series 2019A RSNs) due 2024, (ii) a 1/40 undivided beneficial ownership interest in $1,000 principal amount of Southern Company's Series 2019B Remarketable Junior Subordinated Notes (together with the Series 2019A RSNs, the RSNs) due 2027, and (iii) a stock purchase contract, which obligates the holder to purchase from Southern Company, no later than August 1, 2022, a certain number of shares of Southern Company's common stock for $50 in cash (Stock Purchase Contract). Southern Company has agreed to remarket the RSNs in 2022, at which time each interest rate on the RSNs will reset at the applicable market rate. Holders may choose to either remarket their RSNs, receive the proceeds, and use those funds to settle the related Stock Purchase Contract or retain the RSNs and use other funds to settle the related Stock Purchase Contract. If the remarketing is unsuccessful, holders will have the right to put their RSNs to Southern Company at a price equal to the principal amount. The Corporate Units carry an annual distribution rate of 6.75% of the stated amount, which is comprised of a quarterly interest payment on the RSNs of 2.70% per year and a quarterly purchase contract adjustment payment of 4.05% per year. Each Stock Purchase Contract obligates the holder to purchase, and Southern Company to sell, for $50 a number of shares of Southern Company common stock determined based on the applicable market value (as determined under the related Stock Purchase Contract) in accordance with the conversion ratios set forth below (subject to anti-dilution adjustments):
•If the applicable market value is equal to or greater than $68.64, 0.7284 shares.
•If the applicable market value is less than $68.64 but greater than $57.20, a number of shares equal to $50 divided by the applicable market value.
•If the applicable market value is less than or equal to $57.20, 0.8741 shares.
A holder's ownership interest in the RSNs is pledged to Southern Company to
secure the holder's obligation under the related Stock Purchase Contract. If a
holder of a Stock Purchase Contract chooses at any time to have its RSNs
released from the pledge, such holder's obligation under such Stock Purchase
Contract must be secured by a U.S. Treasury security equal to the aggregate
principal amount of the RSNs. At the time of issuance, the RSNs were recorded on
Southern Company's consolidated balance
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sheet as long-term debt and the present value of the contract adjustment
payments of $198 million was recorded as a liability, representing the
obligation to make contract adjustment payments, with an offsetting reduction to
paid-in capital. The liability balance at December 31, 2021 was $52 million,
which was classified as current. The difference between the face value and
present value of the contract adjustment payments is being accreted to interest
expense on the consolidated statements of income over the three-year period
ending in August 2022. The liability recorded for the contract adjustment
payments is considered non-cash and excluded from the consolidated statements of
cash flows. To settle the Stock Purchase Contracts, Southern Company will be
required to issue a maximum of 30.2 million shares of common stock (subject to
anti-dilution adjustments and a make-whole adjustment if certain fundamental
changes occur).
Bank Credit Arrangements
At December 31, 2021, committed credit arrangements with banks were as follows:
Expires
Due within
Company 2022 2023 2024 2026 Total Unused One Year
(in millions)
Southern Company parent $ - $ - $ - $ 2,000 $ 2,000 $ 1,998 $ -
Alabama Power - - 550 700 1,250 1,250 -
Georgia Power - - - 1,750 1,750 1,726 -
Mississippi Power - 125 150 - 275 275 -
Southern Power(a) - - - 600 600 568 -
Southern Company Gas(b) 250 - - 1,500 1,750 1,747 250
SEGCO 30 - - - 30 30 30
Southern Company $ 280 $ 125 $ 700 $ 6,550 $ 7,655 $ 7,594 $ 280
(a)Does not include Southern Power Company's $75 million and $60 million
continuing letter of credit facilities for standby letters of credit expiring in
2023, of which $8 million and $4 million, respectively, was unused at
December 31, 2021. Subsequent to December 31, 2021, Southern Power amended its
$60 million letter of credit facility, which, among other things, extended the
expiration date from 2023 to 2025 and increased the amount to $75 million.
Southern Power's subsidiaries are not parties to its bank credit arrangements or
letter of credit facilities.
(b)Southern Company Gas, as the parent entity, guarantees the obligations of
Southern Company Gas Capital, which is the borrower of $800 million of the
arrangement expiring in 2026 and all $250 million of the arrangement expiring in
2022. Southern Company Gas' committed credit arrangement expiring in 2026 also
includes $700 million for which Nicor Gas is the borrower and which is
restricted for working capital needs of Nicor Gas. Pursuant to the multi-year
credit arrangement expiring in 2026, the allocations between Southern Company
Gas Capital and Nicor Gas may be adjusted. See "Structural Considerations"
herein for additional information.
The bank credit arrangements require payment of commitment fees based on the
unused portion of the commitments. Commitment fees average less than 1/4 of 1%
for the Registrants and Nicor Gas. Subject to applicable market conditions,
Southern Company and its subsidiaries expect to renew or replace their bank
credit arrangements as needed, prior to expiration. In connection therewith,
Southern Company and its subsidiaries may extend the maturity dates and/or
increase or decrease the lending commitments thereunder.
These bank credit arrangements, as well as the term loan arrangements of the
Registrants, Nicor Gas, and SEGCO, contain covenants that limit debt levels and
contain cross-acceleration or, in the case of Southern Power, cross-default
provisions to other indebtedness (including guarantee obligations) that are
restricted only to the indebtedness of the individual company. Such
cross-default provisions to other indebtedness would trigger an event of default
if Southern Power defaulted on indebtedness or guarantee obligations over a
specified threshold. Such cross-acceleration provisions to other indebtedness
would trigger an event of default if the applicable borrower defaulted on
indebtedness, the payment of which was then accelerated. Southern Company's,
Southern Company Gas', and Nicor Gas' credit arrangements contain covenants that
limit debt levels to 70% of total capitalization, as defined in the agreements,
and the other subsidiaries' bank credit arrangements contain covenants that
limit debt levels to 65% of total capitalization, as defined in the agreements.
For purposes of these definitions, debt excludes junior subordinated notes and,
in certain arrangements, other hybrid securities. Additionally, for Southern
Company and Southern Power, for purposes of these definitions, debt excludes any
project debt incurred by certain subsidiaries of Southern Power to the extent
such debt is non-recourse to Southern Power and capitalization excludes the
capital stock or other equity attributable to such subsidiaries. At December 31,
2021, the Registrants, Nicor Gas, and SEGCO were in compliance with all such
covenants. None of the bank credit arrangements contain material adverse change
clauses at the time of borrowings.
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A portion of the unused credit with banks is allocated to provide liquidity support to the revenue bonds of the traditional electric operating companies and the commercial paper programs of the Registrants, Nicor Gas, and SEGCO. The amount of variable rate revenue bonds of the traditional electric operating companies outstanding requiring liquidity support at December 31, 2021 was approximately $1.5 billion (comprised of approximately $789 million at Alabama Power, $672 million at Georgia Power, and $34 million at Mississippi Power). In addition, at December 31, 2021, Georgia Power had approximately $157 million of fixed rate revenue bonds outstanding that are required to be remarketed within the next 12 months.
At both December 31, 2021 and 2020, Southern Power had $105 million of cash collateral posted related to PPA requirements, which is included in other deferred charges and assets on Southern Power's consolidated balance sheets.
Notes Payable
The Registrants, Nicor Gas, and SEGCO make short-term borrowings primarily through commercial paper programs that have the liquidity support of the committed bank credit arrangements described above under "Bank Credit Arrangements." Southern Power's subsidiaries are not parties or obligors to its commercial paper program. Southern Company Gas maintains commercial paper programs at Southern Company Gas Capital and at Nicor Gas. Nicor Gas' commercial paper program supports working capital needs at Nicor Gas as Nicor Gas is not permitted to make money pool loans to affiliates. All of Southern Company Gas' other subsidiaries benefit from Southern Company Gas Capital's commercial paper program. See "Structural Considerations" herein for additional information. In addition, Southern Company and certain of its subsidiaries have entered into various bank term loan agreements. Unless otherwise stated, the proceeds of these loans were used to repay existing indebtedness and for general corporate purposes, including working capital and, for the subsidiaries, their continuous construction programs.
Commercial paper and short-term bank term loans are included in notes payable in the balance sheets. Details of short-term borrowings for the applicable Registrants were as follows:
Notes Payable at December 31, 2021 Notes Payable at December 31, 2020
Amount Weighted Average Amount Weighted Average
Outstanding Interest Rate Outstanding Interest Rate
(in millions) (in millions)
Southern Company
Commercial paper $ 1,140 0.3 % $ 609 0.3 %
Short-term bank debt 300 0.7 % - - %
Total $ 1,440 0.4 % $ 609 0.3 %
Georgia Power
Commercial paper $ - - % $ 60 0.3 %
Mississippi Power
Commercial paper $ - - % $ 25 0.4 %
Southern Power
Commercial paper $ 211 0.3 % $ 175 0.3 %
Southern Company Gas
Commercial paper:
Southern Company Gas Capital $ 379 0.3 % $ 220 0.3 %
Nicor Gas 530 0.3 % 104 0.2 %
Short-term bank debt:
Nicor Gas 300 0.7 % - - %
Total $ 1,209 0.4 % $ 324 0.2 %
See "Bank Credit Arrangements" herein for information on bank term loan covenants that limit debt levels and cross-acceleration or cross-default provisions.
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Outstanding Classes of Capital Stock
Southern Company Common Stock Stock Issued During 2021, Southern Company issued approximately 3.5 million shares of common stock primarily through employee equity compensation plans and received proceeds of approximately $73 million.
See "Equity Units" herein for additional information.
Shares Reserved
At December 31, 2021, a total of 127 million shares were reserved for issuance
pursuant to the Southern Investment Plan, employee savings plans, the Outside
Directors Stock Plan, the Equity and Incentive Compensation Plan (which includes
stock options and performance share units as discussed in Note 12), and an
at-the-market program. Of the total 127 million shares reserved, 31.5 million
shares are available for awards under the Equity and Incentive Compensation Plan
at December 31, 2021.
Diluted Earnings Per Share
For Southern Company, the only differences in computing basic and diluted
earnings per share (EPS) are attributable to awards outstanding under
stock-based compensation plans and the Equity Units. Earnings per share dilution
resulting from stock-based compensation plans and the Equity Units issuance is
determined using the treasury stock method. Shares used to compute diluted EPS
were as follows:
Average Common Stock Shares
2021 2020 2019
(in millions)
As reported shares 1,061 1,058 1,046
Effect of stock-based compensation 7 7 8
Diluted shares 1,068 1,065 1,054
In all years presented, an immaterial number of stock-based compensation awards was not included in the diluted EPS calculation because the awards were anti-dilutive.
The Equity Units were excluded from the calculation of diluted EPS for all years presented as the dilutive stock price threshold was not met.
Redeemable Preferred Stock of Subsidiaries
As discussed further under "Alabama Power" herein, the preferred stock of Alabama Power is presented as "Redeemable Preferred Stock of Subsidiaries" on Southern Company's balance sheets in a manner consistent with temporary equity under applicable accounting standards.
Alabama Power
Alabama Power has preferred stock, Class A preferred stock, and common stock
outstanding. Alabama Power also has authorized preference stock, none of which
is outstanding. Alabama Power's preferred stock and Class A preferred stock,
without preference between classes, rank senior to Alabama Power's common stock
with respect to payment of dividends and voluntary and involuntary dissolution.
The preferred stock and Class A preferred stock of Alabama Power contain a
feature that allows the holders to elect a majority of Alabama Power's board of
directors if preferred dividends are not paid for four consecutive quarters.
Because such a potential redemption-triggering event is not solely within the
control of Alabama Power, the preferred stock and Class A preferred stock is
presented as "Redeemable Preferred Stock" on Alabama Power's balance sheets in a
manner consistent with temporary equity under applicable accounting standards.
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Alabama Power's preferred stock is subject to redemption at a price equal to the
par value plus a premium. Alabama Power's Class A preferred stock is subject to
redemption at a price equal to the stated capital. All series of Alabama Power's
preferred stock currently are subject to redemption at the option of Alabama
Power. The Class A preferred stock is subject to redemption on or after October
1, 2022, or following the occurrence of a rating agency event. Information for
each outstanding series is in the table below:
Par Value/Stated Redemption
Preferred Stock Capital Per Share Shares Outstanding Price Per Share
4.92% Preferred Stock $100 80,000 $103.23
4.72% Preferred Stock $100 50,000 $102.18
4.64% Preferred Stock $100 60,000 $103.14
4.60% Preferred Stock $100 100,000 $104.20
4.52% Preferred Stock $100 50,000 $102.93
4.20% Preferred Stock $100 135,115 $105.00
5.00% Class A Preferred Stock $25 10,000,000 $25.00(*)
(*)$25.50 if prior to October 1, 2022
Georgia Power
Georgia Power has preferred stock, Class A preferred stock, preference stock, and common stock authorized, but only common stock outstanding.
Mississippi Power
Mississippi Power has preferred stock and common stock authorized, but only common stock outstanding.
Dividend Restrictions
The income of Southern Company is derived primarily from equity in earnings of its subsidiaries. At December 31, 2021, consolidated retained earnings included $4.4 billion of undistributed retained earnings of the subsidiaries.
The traditional electric operating companies and Southern Power can only pay dividends to Southern Company out of retained earnings or paid-in-capital.
See Note 7 under "Southern Power" for information regarding the distribution requirements for certain Southern Power subsidiaries.
By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. At December 31, 2021, the amount of Southern Company Gas' subsidiary retained earnings restricted for dividend payment totaled $1.3 billion.
Structural Considerations
Since Southern Company and Southern Company Gas are holding companies, the right
of Southern Company and Southern Company Gas and, hence, the right of creditors
of Southern Company or Southern Company Gas to participate in any distribution
of the assets of any respective subsidiary of Southern Company or Southern
Company Gas, whether upon liquidation, reorganization or otherwise, is subject
to prior claims of creditors and preferred stockholders of such subsidiary.
Southern Company Gas' 100%-owned subsidiary, Southern Company Gas Capital, was
established to provide for certain of Southern Company Gas' ongoing financing
needs through a commercial paper program, the issuance of various debt, hybrid
securities, and other financing arrangements. Southern Company Gas fully and
unconditionally guarantees all debt issued by Southern Company Gas Capital.
Nicor Gas is not permitted by regulation to make loans to affiliates or utilize
Southern Company Gas Capital for its financing needs.
Southern Power Company's senior notes, bank term loan, commercial paper, and
bank credit arrangement are unsecured senior indebtedness, which rank equally
with all other unsecured and unsubordinated debt of Southern Power Company.
Southern Power's subsidiaries are not issuers, borrowers, or obligors, as
applicable, under any of these unsecured senior debt arrangements, which are
effectively subordinated to any future secured debt of Southern Power Company
and any potential claims of creditors of Southern Power's subsidiaries.
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9. LEASES
On January 1, 2019, the Registrants adopted the provisions of FASB ASC Topic 842 (as amended), Leases (ASC 842), which require lessees to recognize leases with a term of greater than 12 months on the balance sheet as lease obligations, representing the discounted future fixed payments due, along with ROU assets that will be amortized over the term of each lease. The Registrants elected the transition methodology provided by ASC 842, whereby the applicable requirements were applied on a prospective basis as of the adoption date. The Registrants also elected the package of practical expedients provided by ASC 842 that allows prior determinations of whether existing contracts are, or contain, leases and the classification of existing leases to continue without reassessment. Additionally, the Registrants applied the use-of-hindsight practical expedient in determining lease terms as of the date of adoption and elected the practical expedient that allows existing land easements not previously accounted for as leases not to be reassessed.
Lessee
As lessee, the Registrants lease certain electric generating units (including
renewable energy facilities), real estate/land, communication towers, railcars,
and other equipment and vehicles. The major categories of lease obligations are
as follows:
Southern Alabama Georgia Mississippi Southern
Company Power Power Power Southern Power Company Gas
(in millions)
At December 31, 2021
Electric generating units $ 802 $ 104 $ 1,217 $ - $ - $ -
Real estate/land 876 3 49 2 526 45
Communication towers 156 2 4 - - 24
Railcars 32 10 20 2 - -
Other 103 5 1 24 - 1
Total $ 1,969 $ 124 $ 1,291 $ 28 $ 526 $ 70
At December 31, 2020
Electric generating units $ 941 $ 146 $ 1,368 $ - $ - $ -
Real estate/land 815 4 53 2 451 61
Communication towers 158 2 3 - - 20
Railcars 42 16 23 3 - -
Other 127 7 5 23 - 1
Total $ 2,083 $ 175 $ 1,452 $ 28 $ 451 $ 82
Real estate/land leases primarily consist of commercial real estate leases at
Southern Company, Georgia Power, and Southern Company Gas and various land
leases primarily associated with renewable energy facilities at Southern Power.
The commercial real estate leases have remaining terms of up to 24 years while
the land leases have remaining terms of up to 45 years, including renewal
periods.
Communication towers are leased for the installation of equipment to provide
cellular phone service to customers and to support the automated meter
infrastructure programs at the traditional electric operating companies and
Nicor Gas. Communication tower leases have remaining terms of up to 15 years
with options to renew that could extend the terms for an additional 15 years.
Renewal options exist in many of the leases. Except as otherwise noted, the
expected term used in calculating the lease obligation generally reflects only
the noncancelable period of the lease as it is not considered reasonably certain
that the lease will be extended. Land leases associated with renewable energy
facilities at Southern Power and communication tower leases for automated meter
infrastructure at Nicor Gas include renewal periods reasonably certain of
exercise resulting in an expected lease term at least equal to the expected life
of the renewable energy facilities and the automated meter infrastructure,
respectively.
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Contracts that Contain a Lease
While not specifically structured as a lease, some of the PPAs at Alabama Power and Georgia Power are deemed to represent a lease of the underlying electric generating units when the terms of the PPA convey the right to control the use of the underlying assets. Amounts recorded for leases of electric generating units are generally based on the amount of scheduled capacity payments due over the remaining term of the PPA, which varies between one and 17 years. Georgia Power has several PPAs with Southern Power that Georgia Power accounts for as leases with a lease obligation of $521 million and $575 million at December 31, 2021 and 2020, respectively. The amount paid for energy under these affiliate PPAs reflects a price that would be paid in an arm's-length transaction as reviewed and approved by the Georgia PSC.
Short-term Leases
Leases with an initial term of 12 months or less are not recorded on the balance sheet; the Registrants generally recognize lease expense for these leases on a straight-line basis over the lease term.
Residual Value Guarantees
Residual value guarantees exist primarily in railcar leases at Alabama Power and Georgia Power and the amounts probable of being paid under those guarantees are included in the lease payments. All such amounts are immaterial at December 31, 2021 and 2020.
Lease and Nonlease Components
For all asset categories, with the exception of electric generating units, gas
pipelines, and real estate leases, the Registrants combine lease payments and
any nonlease components, such as asset maintenance, for purposes of calculating
the lease obligation and the right-of-use asset.
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Balance sheet amounts recorded for operating and finance leases are as follows:
Southern Alabama Georgia Mississippi Southern
Company Power Power Power Southern Power Company Gas
(in millions)
At December 31, 2021
Operating Leases
Operating lease ROU assets, net $ 1,701 $ 108 $ 1,157 $ 10 $ 479 $ 70
Operating lease obligations - current $ 250 $ 54 $
156 $ 4 $ 28 $ 11 Operating lease obligations - non-current 1,503 66 999 6 497 59 Total operating lease obligations(*) $ 1,754 $ 121 $ 1,155 $ 10 $ 525 $ 70 Finance Leases Finance lease ROU assets, net $ 197 $ 4 $ 104 $ 17 $ - $ -
Finance lease obligations - current $ 16 $ 1 $
10 $ 1 $ - $ - Finance lease obligations - non-current 199 3 126 17 - - Total finance lease obligations $ 215 $ 4 $ 136 $ 18 $ - $ - At December 31, 2020 Operating Leases Operating lease ROU assets, net $ 1,802 $ 151 $ 1,308 $ 9 $ 415 $ 81
Operating lease obligations - current $ 241 $ 51 $
151 $ 2 $ 25 $ 15
Operating lease obligations - non-current 1,611 119 1,156
7 426 67
Total operating lease obligations(*) $ 1,852 $ 170 $ 1,307 $ 9 $ 451 $ 82
Finance Leases
Finance lease ROU assets, net $ 218 $ 5 $ 115 $ 19 $ - $ -
Finance lease obligations - current $ 17 $ 1 $
9 $ 1 $ - $ -
Finance lease obligations - non-current 214 4 136 18 - -
Total finance lease obligations $ 231 $ 5 $ 145 $ 19 $ - $ -
(*)Includes operating lease obligations related to PPAs at Southern Company,
Alabama Power, and Georgia Power totaling $802 million, $104 million, and $1.11
billion, respectively, at December 31, 2021 and $941 million, $146 million, and
$1.25 billion, respectively, at December 31, 2020.
If not presented separately on the Registrants' balance sheets, amounts related
to leases are presented as follows: operating lease ROU assets, net are included
in "other deferred charges and assets"; operating lease obligations are included
in "other current liabilities" and "other deferred credits and liabilities," as
applicable; finance lease ROU assets, net are included in "plant in service";
and finance lease obligations are included in "securities due within one year"
and "long-term debt," as applicable.
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Lease costs for 2021, 2020, and 2019, which includes both amounts recognized as
operations and maintenance expense and amounts capitalized as part of the cost
of another asset, are as follows:
Southern Alabama Georgia Mississippi Southern
Company Power Power Power Southern Power Company Gas
(in millions)
2021
Lease cost
Operating lease cost(*) $ 313 $ 58 $ 208 $ 2 $ 33 $ 19
Finance lease cost:
Amortization of ROU assets 21 1 11 1 - -
Interest on lease obligations 11 - 16 1 - -
Total finance lease cost 32 1 27 2 - -
Short-term lease costs 48 15 24 - - -
Variable lease cost 96 4 83 - 5 -
Sublease income 1 - - - - -
Total lease cost $ 490 $ 78 $ 342 $ 4 $ 38 $ 19
2020
Lease cost
Operating lease cost(*) $ 309 $ 55 $ 212 $ 3 $ 29 $ 19
Finance lease cost:
Amortization of ROU assets 26 1 15 - - -
Interest on lease obligations 11 - 16 - - -
Total finance lease cost 37 1 31 - - -
Short-term lease costs 39 11 26 - - -
Variable lease cost 91 4 76 - 7 -
Sublease income - (1) - - - -
Total lease cost $ 476 $ 70 $ 345 $ 3 $ 36 $ 19
2019
Lease cost
Operating lease cost(*) $ 310 $ 54 $ 206 $ 3 $ 28 $ 18
Finance lease cost:
Amortization of ROU assets 28 1 15 - - -
Interest on lease obligations 12 - 18 - - -
Total finance lease cost 40 1 33 - - -
Short-term lease costs 48 19 22 - - -
Variable lease cost 105 6 85 - 7 -
Sublease income - (1) - - - -
Total lease cost $ 503 $ 79 $ 346 $ 3 $ 35 $ 18
(*)Includes operating lease costs related to PPAs at Southern Company, Alabama
Power, and Georgia Power totaling $165 million, $47 million, and $184 million,
respectively, in 2021, $161 million, $43 million, and $184 million,
respectively, in 2020, and $149 million, $41 million, and $174 million,
respectively, in 2019.
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Georgia Power has variable lease payments that are based on the amount of energy produced by certain renewable generating facilities subject to PPAs, including $41 million, $39 million, and $42 million in 2021, 2020, and 2019, respectively, from finance leases which are included in purchased power on Georgia Power's statements of income, $20 million of which was included in purchased power, affiliates for all periods presented.
Other information with respect to cash and noncash activities related to leases, as well as weighted-average lease terms and discount rates, is as follows:
Southern Alabama Georgia Mississippi Southern
Company Power Power Power Southern Power Company Gas
(in millions)
2021
Other information
Cash paid for amounts included in the
measurements of lease obligations:
Operating cash flows from operating leases $ 308 $ 58 $ 211 $ 2 $ 28 $ 19
Operating cash flows from finance leases 9 - 17 1 - -
Financing cash flows from finance leases 17 1 9 1 - -
ROU assets obtained in exchange for new
operating lease obligations 64 3 9 - 72 7
ROU assets obtained in exchange for new
finance lease obligations 3 - - - - -
2020
Other information
Cash paid for amounts included in the
measurements of lease obligations:
Operating cash flows from operating leases $ 310 $ 55 $ 215 $ 3 $ 28 $ 18
Operating cash flows from finance leases 9 - 18 - - -
Financing cash flows from finance leases 22 1 11 - - -
ROU assets obtained in exchange for new
operating lease obligations 227 63 32 - 51 4
ROU assets obtained in exchange for new
finance lease obligations 10 2 - - - -
2019
Other information
Cash paid for amounts included in the
measurements of lease obligations:
Operating cash flows from operating leases $ 323 $ 54 $ 210 $ 3 27 18
Operating cash flows from finance leases 10 - 19 - - -
Financing cash flows from finance leases 32 1 13 - - -
ROU assets obtained in exchange for new
operating lease obligations 118 7 21 - 2 19
ROU assets obtained in exchange for new
finance lease obligations 35 2 24 - - -
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Southern Alabama Georgia Mississippi Southern Company
Company Power Power Power Southern Power Gas
At December 31, 2021
Weighted-average remaining lease term in
years:
Operating leases 15.9 9.1 8.7 6.1 32.8 10.5
Finance leases 18.0 8.7 8.5 13.9 N/A N/A
Weighted-average discount rate:
Operating leases 4.41 % 4.37 % 4.45 % 2.74 % 5.20 % 3.61 %
Finance leases 4.82 % 3.09 % 10.81 % 2.74 % N/A N/A
At December 31, 2020
Weighted-average remaining lease term in
years:
Operating leases 14.5 7.8 9.4 6.5 32.1 9.8
Finance leases 18.2 9.7 9.5 14.9 N/A N/A
Weighted-average discount rate:
Operating leases 4.44 % 4.14 % 4.37 % 3.26 % 5.45 % 3.67 %
Finance leases 4.79 % 3.20 % 10.81 % 2.74 N/A N/A
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Maturities of lease liabilities are as follows:
At December 31, 2021
Southern Alabama Georgia Mississippi Southern
Company Power Power Power Southern Power Company Gas
(in millions)
Maturity Analysis
Operating leases:
2022 $ 307 $ 59 $ 205 $ 4 $ 37 $ 14
2023 238 9 201 2 29 11
2024 195 7 164 1 29 11
2025 174 6 136 1 29 11
2026 154 5 133 1 30 8
Thereafter 1,575 69 566 2 995 31
Total 2,643 155 1,405 11 1,149 86
Less: Present value discount 889 34 250 1 624 16
Operating lease obligations $ 1,754 $ 121 $ 1,155 $ 10 $ 525 $ 70
Finance leases:
2022 $ 25 $ 2 $ 25 $ 2 $ - $ -
2023 22 1 25 2 - -
2024 19 1 25 2 - -
2025 16 - 25 2 - -
2026 16 - 26 1 - -
Thereafter 231 - 83 13 - -
Total 329 4 209 22 - -
Less: Present value discount 114 - 73 4 - -
Finance lease obligations $ 215 $ 4 $ 136 $ 18 $ - $ -
Payments made under PPAs at Georgia Power for energy generated from certain
renewable energy facilities accounted for as operating and finance leases are
considered variable lease costs and are therefore not reflected in the above
maturity analysis.
Lessor
The Registrants are each considered lessors in various arrangements that have
been determined to contain a lease due to the customer's ability to control the
use of the underlying asset owned by the applicable Registrant. For the
traditional electric operating companies, these arrangements consist of outdoor
lighting contracts accounted for as operating leases with initial terms of up to
seven years, after which the contracts renew on a month-to-month basis at the
customer's option. For Mississippi Power, these arrangements also include a
tolling arrangement related to an electric generating unit accounted for as a
sales-type lease with a remaining term of 17 years. For Southern Power, these
arrangements consist of PPAs related to electric generating units, including
solar and wind facilities, accounted for as operating leases with remaining
terms of up to 25 years and PPAs related to battery energy storage facilities
accounted for as sales-type leases with remaining terms of up to 19 years.
Southern Company Gas is the lessor in operating leases related to gas pipelines
with remaining terms of up to 21 years. For Southern Company, these arrangements
also include PPAs related to fuel cells accounted for as operating leases with
remaining terms of up to 12 years.
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Lease income for 2021, 2020, and 2019, is as follows:
Southern Mississippi Southern
Company Alabama Power Georgia Power Power Southern Power Company Gas
(in millions)2021
Lease income - interest income on sales-type
leases $ 15 $ - $ - $ 14 $ 1 $ -
Lease income - operating leases 223 82 42 2 85 35
Variable lease income 429 - - - 456 -
Total lease income $ 667 $ 82 $ 42 $ 16 $ 542 $ 35
2020
Lease income - interest income on sales-type
leases $ 16 $ - $ - $ 12 $ - $ -
Lease income - operating leases 208 45 58 2 87 35
Variable lease income 419 - - - 449 -
Total lease income $ 643 $ 45 $ 58 $ 14 $ 536 $ 35
2019
Lease income - interest income on sales-type
leases $ 9 $ - $ - $ 9 $ - $ -
Lease income - operating leases 273 24 71 - 160 35
Variable lease income 403 - - - 434 -
Total lease income $ 685 $ 24 $ 71 $ 9 $ 594 $ 35
Lease payments received under tolling arrangements and PPAs consist of either
scheduled payments or variable payments based on the amount of energy produced
by the underlying electric generating units. Lease income for Alabama Power and
Southern Power is included in wholesale revenues. Scheduled payments to be
received under outdoor lighting contracts, tolling arrangements, and PPAs
accounted for as leases are presented in the following maturity analyses.
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No profit or loss was recognized by Mississippi Power when a tolling arrangement accounted for as a sales-type lease began in 2019. During 2020 and 2021, Mississippi Power completed construction of additional leased assets under the lease and, upon completion, the book values of $26 million and $39 million, respectively, were transferred from CWIP to lease receivables. Each transfer represented a non-cash investing transaction for purposes of the statements of cash flows. During 2021, Southern Power completed construction of a portion of the Garland and Tranquillity battery energy storage facilities' assets and recorded losses totaling $40 million upon commencement of the related PPAs, which Southern Power accounts for as sales-type leases. The losses were due to ITCs retained and expected to be realized by Southern Power and its partners in these projects, and no estimated residual asset value was assumed in calculating the losses. Each lease has an initial term of 20 years. Upon commencement of the leases, the book values of the related assets totaling $210 million were derecognized from CWIP and lease receivables were recorded. At December 31, 2021, the current portion of the lease receivables totaling $12 million is included in other current assets and the long-term portion totaling $161 million is included in miscellaneous property and investments on Southern Company's balance sheet and net investment in sales-type leases on Southern Power's consolidated balance sheet. The transfers represented noncash investing transactions for purposes of the statement of cash flows. See Note 15 under "Southern Power" for additional information.
The undiscounted cash flows expected to be received for in-service leased assets under the leases are as follows:
At December 31, 2021
Southern
Southern Company Mississippi Power Power
(in millions)
2022 $ 37 $ 25 $ 12
2023 39 24 15
2024 38 23 15
2025 37 22 15
2026 36 21 15
Thereafter 390 183 207
Total undiscounted cash flows $ 577 $ 298 $ 279
Net investment in sales-type lease(*) 340 167 173
Difference between undiscounted cash flows and discounted cash flows
$ 237 $ 131 $ 106
(*)For Mississippi Power, included in other current assets and other property
and investments on the balance sheets. For Southern Power, included in other
current assets and net investment in sales-type leases on the balance sheet.
The undiscounted cash flows to be received under operating leases and contracts
accounted for as operating leases (adjusted for intercompany eliminations) are
as follows:
At December 31, 2021
Southern Alabama Southern
Company Power Georgia Power Power Southern Company Gas
(in millions)
2022 $ 188 $ 76 $ 8 $ 87 $ 35
2023 139 32 2 88 35
2024 107 5 - 90 33
2025 100 3 - 74 28
2026 99 3 - 73 28
Thereafter 883 23 - 240 407
Total $ 1,516 $ 142 $ 10 $ 652 $ 566
Southern Power receives payments for renewable energy under PPAs accounted for
as operating leases that are considered contingent rents and are therefore not
reflected in the table above. Alabama Power and Southern Power allocate revenue
to the nonlease components of PPAs based on the stand-alone selling price of
capacity and energy. The undiscounted cash flows to be received under outdoor
lighting contracts accounted for as operating leases at Mississippi Power are
immaterial.
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Southern Company Leveraged Lease
At December 31, 2020, a subsidiary of Southern Holdings had four leveraged lease
agreements related to energy generation, distribution, and transportation
assets, including two domestic and two international projects. During 2021, one
of the domestic projects was sold and the agreements for both international
projects were terminated. At December 31, 2021, one leveraged lease agreement
related to energy generation remains, with an expected remaining term of 10
years. Southern Company continues to receive federal income tax deductions for
depreciation and amortization, as well as interest on long-term debt related to
this investment. Southern Company wrote off the related investment balance in
2020, as discussed below.
Southern Company's net investment in leveraged leases at December 31, 2020
consisted of the following:
December 31, 2020(*)
(in millions)
Net rentals receivable $ 734
Unearned income (178)
Investment in leveraged leases 556
Deferred taxes from leveraged leases (7)
Net investment in leveraged leases $ 549
(*)Excludes the investment classified as held for sale. See Note 15 under "Southern Company" for additional information.
The following table provides a summary of the components of income related to
leveraged lease investments. Income was impacted in all periods presented by the
impairment charges discussed below and in Note 15 under "Southern Company."
Income in 2021 does not include the impacts of the sale and terminations of
leveraged lease projects discussed in Note 15 under "Southern Company."
2021 2020 2019
(in millions)
Pretax leveraged lease income (loss) $ 17 $ (180) $ 11 Income tax benefit (expense)
(5) 98 -
Net leveraged lease income (loss) $ 12 $ (82) $ 11
Since 2017, the financial and operational performance of the remaining domestic
lessee and the associated generation assets raised significant concerns about
the short-term ability of the generation assets to produce cash flows sufficient
to support ongoing operations and the lessee's contractual obligations and its
ability to make the remaining semi-annual lease payments through the end of the
lease term in 2047. In addition, following the expiration of the existing power
offtake agreement in 2032, the lessee also is exposed to remarketing risk, which
encompasses the price and availability of alternative sources of generation.
In connection with the 2019 annual impairment analysis, Southern Company revised
the estimated cash flows to be received under the leveraged lease, which
resulted in an impairment charge of $17 million ($13 million after tax) recorded
in the fourth quarter 2019. During the second quarter 2020, Southern Company
received the latest annual forecasts of natural gas prices and considered the
significant decline in forecasted prices to be an indicator of potential
impairment that required an interim impairment assessment. Accordingly,
consistent with prior impairment analyses, Southern Company evaluated the
recoverability of the lease receivable and the expected residual value of the
generation assets under various natural gas price scenarios to estimate the cash
flows expected to be received from remarketing the generation assets following
the expiration of the existing PPA and the residual value of the generation
assets at the end of the lease. Based on the forecasts of energy prices in the
years following the expiration of the existing PPA, Southern Company concluded
that it was no longer probable that any of the associated rental payments would
be received, because it was no longer probable the generation assets would be
successfully remarketed and continue to operate after that date. During the
second quarter 2020, Southern Company revised the estimated cash flows to be
received under the leveraged lease to reflect this conclusion, which resulted in
a full impairment of the lease investment and a pre-tax charge to earnings of
$154 million ($74 million after tax).
All required lease payments through December 31, 2021 have been paid in full. If
any future lease payments due prior to the expiration of the associated PPA are
not paid in full, the Southern Holdings subsidiary may be unable to make its
corresponding payment to the holders of the underlying non-recourse debt related
to the generation assets. Failure to make the required payment to the
debtholders could represent an event of default that would give the debtholders
the right to foreclose on, and take ownership
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of, the generation assets, in effect terminating the lease. As the remaining amount of the lease investment was charged against earnings in the second quarter 2020, termination would not be expected to result in additional charges. Southern Company will continue to monitor the operational performance of the underlying assets and evaluate the ability of the lessee to continue to make the required lease payments and meet its obligations associated with a future closure or retirement of the generation assets and associated properties, including the dry ash landfill.
10. INCOME TAXES
Southern Company files a consolidated federal income tax return and the Registrants file various state income tax returns, some of which are combined or unitary. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary's current and deferred tax expense is computed on a stand-alone basis, and each subsidiary is allocated an amount of tax similar to that which would be paid if it filed a separate income tax return. In accordance with IRS regulations, each company is jointly and severally liable for the federal tax liability.
Current and Deferred Income Taxes
Details of income tax provisions are as follows:
2021
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas
(in millions)
Federal -
Current $ 50 $ 104 $ 311 $ 25 $ (340) $ 85
Deferred 36 172 (449) (15) 343 35
86 276 (138) 10 3 120
State -
Current (25) 23 71 - (16) (68)
Deferred 206 73 (101) 11 - 223
181 96 (30) 11 (16) 155
Total $ 267 $ 372 $ (168) $ 21 $ (13) $ 275
2020
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas
(in millions)
Federal -
Current $ 199 $ 198 $ 365 $ 18 $ (303) $ 82
Deferred 70 44 (224) (14) 299 53
269 242 141 4 (4) 135
State -
Current 100 61 60 - (4) 35
Deferred 24 34 (49) 10 11 3
124 95 11 10 7 38
Total $ 393 $ 337 $ 152 $ 14 $ 3 $ 173
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2019
Southern Company Alabama Power Georgia Mississippi Southern Power Southern Company
Power Power Gas
(in millions)
Federal -
Current $ 156 $ 61 $ 264 $ (6) $ (717) $ (120)
Deferred 1,237 125 180 26 647 195
1,393 186 444 20 (70) 75
State -
Current 275 12 6 (1) 1 37
Deferred 130 72 22 11 13 18
405 84 28 10 14 55
Total $ 1,798 $ 270 $ 472 $ 30 $ (56) $ 130
Southern Company's and Southern Power's ITCs and PTCs generated in the current
tax year and carried forward from prior tax years that cannot be utilized in the
current tax year are reclassified from current to deferred taxes in federal
income tax expense in the tables above. Southern Power's ITCs and PTCs
reclassified in this manner include $6 million for 2021, $5 million for 2020,
and $51 million for 2019. Southern Power received $289 million, $340 million,
and $734 million of cash related to federal ITCs under renewable energy
initiatives in 2021, 2020, and 2019, respectively. See "Deferred Tax Assets and
Liabilities" herein for additional information.
In accordance with regulatory requirements, deferred federal ITCs for the
traditional electric operating companies are deferred and amortized over the
average life of the related property, with such amortization normally applied as
a credit to reduce depreciation and amortization in the statements of income.
Southern Power's and the natural gas distribution utilities' deferred federal
ITCs, as well as certain state ITCs for Nicor Gas, are deferred and amortized to
income tax expense over the life of the respective asset. ITCs amortized in
2021, 2020, and 2019 were immaterial for the traditional electric operating
companies and Southern Company Gas and were as follows for Southern Company and
Southern Power:
Southern Company Southern Power
(in millions)
2021 $ 84 $ 58
2020 84 59
2019 181 151
When Southern Power recognizes tax credits, the tax basis of the asset is
reduced by 50% of the ITCs received, resulting in a net deferred tax asset.
Southern Power has elected to recognize the tax benefit of this basis difference
as a reduction to income tax expense in the year in which the plant reaches
commercial operation. The tax benefit of the related basis differences reduced
income tax expense by $5 million in 2019.
State ITCs and other state credits, which are recognized in the period in which
the credits are generated, reduced Georgia Power's income tax expense by $66
million in 2021, $67 million in 2020, and $51 million in 2019.
Southern Power's federal and state PTCs, which are recognized in the period in
which the credits are generated, reduced Southern Power's income tax expense by
$16 million in 2021, $15 million in 2020, and $12 million in 2019.
Effective Tax Rate
Southern Company's effective tax rate is typically lower than the statutory rate
due to employee stock plans' dividend deduction, non-taxable AFUDC equity at the
traditional electric operating companies, flowback of excess deferred income
taxes at the regulated utilities, and federal income tax benefits from ITCs and
PTCs primarily at Southern Power.
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent.
As a result of the sale, changes in state apportionment rates resulted in
$85 million of additional net state tax expense. See Note 15 under "Southern
Company Gas" for additional information.
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A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
2021
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas Federal statutory rate
21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
State income tax, net of federal
deduction 5.5 4.6 (5.7) 4.9 (8.0) 15.1
Employee stock plans' dividend deduction (0.9) - - - - -
Non-deductible book depreciation 0.9 0.5 3.1 0.4 - -
Flowback of excess deferred income taxes (11.7) (2.6) (49.9) (15.2) - (2.8)
AFUDC-Equity (1.5) (0.7) (6.4) - - -
Federal PTCs - - - - (4.6) -
Amortization of ITC (2.2) (0.1) (0.4) - (29.7) (0.1)
Noncontrolling interests 0.8 - - - 13.4 -
Leveraged lease impairments and
dispositions (1.4) - - - - -
Other (0.1) 0.2 (1.9) 0.6 (0.4) 0.6
Effective income tax (benefit) rate 10.4 % 22.9 % (40.2) % 11.7 % (8.3) % 33.8 %
2020
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas Federal statutory rate
21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
State income tax, net of federal
deduction 2.8 5.0 0.5 4.8 2.7 4.0
Employee stock plans' dividend deduction (0.7) - - - - -
Non-deductible book depreciation 0.7 0.6 0.8 0.5 - -
Flowback of excess deferred income taxes (8.8) (3.1) (12.0) (18.5) - (2.7)
AFUDC-Equity (0.8) (0.6) (1.1) (0.1) - -
Federal PTCs - - - - (2.5) -
Amortization of ITC (1.6) (0.1) (0.1) (0.1) (22.1) (0.1)
Noncontrolling interests - - - - 3.1 -
Leveraged lease impairments (1.6) - - - - -
Other 0.2 (0.3) (0.3) 0.9 (0.9) 0.5
Effective income tax (benefit) rate 11.2 % 22.5 % 8.8 % 8.5 % 1.3 % 22.7 %
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2019
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas Federal statutory rate
21.0 % 21.0 % 21.0 % 21.0 % 21.0 % 21.0 %
State income tax, net of federal
deduction 4.9 4.9 1.0 4.3 4.0 6.1
Employee stock plans' dividend deduction (0.4) - - - - -
Non-deductible book depreciation 0.3 0.6 0.5 0.4 - -
Flowback of excess deferred income taxes (2.1) (5.3) - (12.6) - (6.0)
AFUDC-Equity (0.4) (0.8) (0.6) (0.1) - -
ITC basis difference (0.1) - - - (1.9) -
Amortization of ITC (0.8) (0.1) (0.1) (0.1) (16.1) (0.1)
Tax impact from sale of subsidiaries 5.1 - - - (27.6) (1.4)
Noncontrolling interests - - - - 0.8 -
Other - (0.4) (0.3) 4.9 (0.6) (1.4)
Effective income tax (benefit) rate 27.5 % 19.9 % 21.5 % 17.8 % (20.4) % 18.2 %
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Deferred Tax Assets and Liabilities
The tax effects of temporary differences between the carrying amounts of assets
and liabilities in the financial statements of the Registrants and their
respective tax bases, which give rise to deferred tax assets and liabilities,
are as follows:
December 31, 2021
Southern Alabama Georgia Southern Southern
Company Power Power Mississippi Power Power Company Gas
(in millions)
Deferred tax liabilities -
Accelerated depreciation $ 9,300 $ 2,541 $ 3,340 $ 330 $ 1,421 $ 1,428
Property basis differences 2,301 1,182 781 169 - 148
Federal effect of net state deferred tax assets - - - 22 - -
Leveraged lease basis differences 61 - - - - -
Employee benefit obligations 820 268 382 41 11 57
Under recovered fuel and natural gas costs 315 47 109 15 - 144
Regulatory assets -
Storm damage reserves 18 - 18 - - -
Employee benefit obligations 825 205 256 38 - 15
Remaining book value of retired assets 271 145 121 5 - -
Premium on reacquired debt 72 10 62 - - -
AROs 2,232 863 1,325 44 - -
AROs 868 329 494 - - -
Other 368 147 77 34 14 82
Total deferred income tax liabilities 17,451 5,737 6,965 698 1,446 1,874
Deferred tax assets -
Federal effect of net state deferred tax
liabilities 305 165 41 - 27 93
State effect of federal deferred taxes 135 135 - - - -
Employee benefit obligations 1,035 225 342 57 7 77
Other property basis differences 231 - 90 - 121 -
ITC and PTC carryforward 1,750 12 704 - 827 -
Long-term debt fair value adjustment 91 - - - - 91
Other partnership basis difference 160 - - - 160 -
Other comprehensive losses 92 5 15 - 11 -
AROs 3,100 1,192 1,819 44 - -
Estimated loss on plants under construction 825 - 825 - - -
Other deferred state tax attributes 361 - 11 246 52 5
Regulatory liability associated with the Tax
Reform Legislation (not subject to normalization) 268 237 19 12 - -
Other 561 193 153 34 53 62
Total deferred income tax assets 8,914 2,164 4,019 393 1,258 328
Valuation allowance (207) - (73) (41) (27) (9)
Net deferred income tax assets 8,707 2,164 3,946 352 1,231 319
Net deferred income taxes (assets)/liabilities $ 8,744 $ 3,573 $ 3,019 $
346 $ 215 $ 1,555
Recognized in the balance sheets: Accumulated deferred income taxes - assets $ (118) $ - $ - $
(118) $ - $ -
Accumulated deferred income taxes - liabilities $ 8,862 $ 3,573 $ 3,019 $
464 $ 215 $ 1,555
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December 31, 2020
Southern Alabama Georgia Southern Southern
Company Power Power Mississippi Power Power Company Gas
(in millions)
Deferred tax liabilities -
Accelerated depreciation $ 8,950 $ 2,453 $ 3,228 $ 319 $ 1,389 $ 1,349
Property basis differences 1,999 1,010 689 148 - 135
Federal effect of net state deferred tax assets - - - 25 - -
Leveraged lease basis differences 142 - - - - -
Employee benefit obligations 739 250 362 39 12 26
Regulatory assets -
Storm damage reserves 80 - 80 - - -
Employee benefit obligations 1,313 348 438 62 - 45
Remaining book value of retired assets 270 123 141 6 - -
Premium on reacquired debt 78 12 66 - - -
AROs 1,969 764 1,165 40 - -
AROs 804 328 429 - - -
Other 437 128 82 66 12 138
Total deferred income tax liabilities 16,781 5,416 6,680 705 1,413 1,693
Deferred tax assets -
Federal effect of net state deferred tax
liabilities 284 151 59 - 26 70
State effect of federal deferred taxes 126 126 - - - -
Employee benefit obligations 1,511 369 522 80 6 100
Other property basis differences 223 - 72 - 134 -
ITC and PTC carryforward 1,853 12 539 - 1,110 -
Long-term debt fair value adjustment 86 - - - - 86
Other partnership basis difference 166 - - - 166 -
Other comprehensive losses 128 7 17 - 25 -
AROs 2,773 1,092 1,594 40 - -
Estimated loss on plants under construction 369 - 369 - - -
Other deferred state tax attributes 357 - 9 250 68 10
Regulatory liability associated with the Tax
Reform Legislation (not subject to normalization) 338 243 76 19 - -
Other 660 143 186 39 52 166
Total deferred income tax assets 8,874 2,143 3,443 428 1,587 432
Valuation allowance (136) - (35) (41) (35) (4)
Net deferred income tax assets 8,738 2,143 3,408 387 1,552 428
Net deferred income taxes (assets)/liabilities $ 8,043 $ 3,273 $ 3,272 $
318 $ (139) $ 1,265
Recognized in the balance sheets: Accumulated deferred income taxes - assets $ (132) $ - $ - $
(129) $ (262) $ -
Accumulated deferred income taxes - liabilities $ 8,175 $ 3,273 $ 3,272 $
447 $ 123 $ 1,265
The traditional electric operating companies and the natural gas distribution
utilities have tax-related regulatory assets (deferred income tax charges) and
regulatory liabilities (deferred income tax credits). The regulatory assets are
primarily attributable to tax benefits flowed through to customers in prior
years, deferred taxes previously recognized at rates lower than the current
enacted tax law, and taxes applicable to capitalized interest. The regulatory
liabilities are primarily attributable to deferred taxes previously recognized
at rates higher than the current enacted tax law and to unamortized ITCs. See
Note 2 for each Registrant's related balances at December 31, 2021 and 2020.
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Tax Credit Carryforwards
Federal ITC/PTC carryforwards at December 31, 2021 were as follows:
Alabama Georgia Southern
Southern Company Power Power Power
(in millions)
Federal ITC/PTC carryforwards $ 1,218 $ 12 $ 173 $ 827
Tax year in which federal ITC/PTC
carryforwards begin expiring 2031 2032 2031 2035
Year by which federal ITC/PTC
carryforwards are expected to be utilized 2024 2024 2024 2024
The estimated tax credit utilization reflects the various sale transactions
described in Note 15 and could be further delayed by numerous factors, including
the acquisition of additional renewable projects, an increase in Georgia Power's
ownership interest percentage in Plant Vogtle Units 3 and 4, the purchase of
rights to additional PTCs of Plant Vogtle Units 3 and 4 pursuant to certain
joint ownership agreements, changes in taxable income projections, and potential
income tax rate changes. See Note 2 under "Georgia Power - Nuclear Construction"
for additional information on Plant Vogtle Units 3 and 4.
At December 31, 2021, Georgia Power also had approximately $428 million in net
state investment and other net state tax credit carryforwards for the State of
Georgia that will expire between tax years 2021 and 2031 and are not expected to
be fully utilized. Georgia Power has a net state valuation allowance of $58
million associated with these carryforwards.
The ultimate outcome of these matters cannot be determined at this time.
Net Operating Loss Carryforwards
At December 31, 2021, the net state income tax benefit of state and local NOL carryforwards for Southern Company's subsidiaries were as follows:
Approximate Net State Income
Tax Benefit of NOL Tax Year NOL
Company/Jurisdiction Carryforwards Begins Expiring
(in millions)
Mississippi Power
Mississippi $ 195 2031
Southern Power
Oklahoma 27 2035
Florida 10 2034
South Carolina 2 2036
Other states 2 Various
Southern Power Total $ 41
Other(*)
New York 11 2035
New York City 14 2035
Other states 17 Various
Southern Company Total $ 278
(*)Represents other non-registrant Southern Company subsidiaries. Alabama Power,
Georgia Power, and Southern Company Gas did not have material state or local NOL
carryforwards at December 31, 2021.
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State NOLs for Mississippi, Oklahoma, and Florida are not expected to be fully utilized prior to expiration. At December 31, 2021, Mississippi Power had a net state valuation allowance of $32 million for the Mississippi NOL, Southern Power had net state valuation allowances of $11 million for the Oklahoma NOL and $10 million for the Florida NOL, and Southern Company had a net valuation allowance of $25 million for the New York and New York City NOLs.
The ultimate outcome of these matters cannot be determined at this time.
Unrecognized Tax Benefits
Changes in unrecognized tax benefits for the periods presented were as follows:
Southern Company
(in millions)
Unrecognized tax benefits at December 31, 2018 and 2019 $ -
Tax positions changes - increase from prior periods 44
Unrecognized tax benefits at December 31, 2020
44
Tax positions changes - increase from prior periods 3 Unrecognized tax benefits at December 31, 2021 $
47
The unrecognized tax positions increase from prior periods for 2020 and the balance of unrecognized tax benefits at December 31, 2020 and 2021 primarily relate to a 2019 state tax filing position to exclude certain gains from 2019 dispositions from taxation in a certain unitary state. If accepted by the state, this position would decrease Southern Company's annual effective tax rate. The ultimate outcome of this unrecognized tax benefit is dependent on completion of the related state audit, which is not expected to be resolved within the next 12 months.
All of the Registrants classify interest on tax uncertainties as interest expense. Accrued interest for all tax positions was immaterial for all years presented. None of the Registrants accrued any penalties on uncertain tax positions.
The IRS has finalized its audits of Southern Company's consolidated federal income tax returns through 2020. Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits for the Registrants' state income tax returns have either been concluded, or the statute of limitations has expired, for years prior to 2015.
11. RETIREMENT BENEFITS
The Southern Company system has a qualified defined benefit, trusteed pension
plan covering substantially all employees, with the exception of PowerSecure
employees. The qualified pension plan is funded in accordance with requirements
of the Employee Retirement Income Security Act of 1974, as amended (ERISA). No
contributions to the qualified pension plan were made for the year ended
December 31, 2021 and no mandatory contributions to the qualified pension plan
are anticipated for the year ending December 31, 2022. The Southern Company
system also provides certain non-qualified defined benefits for a select group
of management and highly compensated employees, which are funded on a cash
basis. In addition, the Southern Company system provides certain medical care
and life insurance benefits for retired employees through other postretirement
benefit plans. The traditional electric operating companies fund other
postretirement trusts to the extent required by their respective regulatory
commissions. Southern Company Gas has a separate unfunded supplemental
retirement health care plan that provides medical care and life insurance
benefits to employees of discontinued businesses. For the year ending
December 31, 2022, no contributions to any other postretirement trusts are
expected.
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Actuarial Assumptions
The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the following year and the benefit obligations as of the measurement date are presented below.
2021
Assumptions used to determine net Georgia Southern Company
periodic costs: Southern Company Alabama Power Power Mississippi Power Southern Power Gas Pension plans Discount rate - benefit obligations
2.81 % 2.85 % 2.79 % 2.80 % 2.99 % 2.75 %
Discount rate - interest costs 2.13 2.17 2.09 2.12 2.46 2.10
Discount rate - service costs 3.18 3.23 3.21 3.20 3.22 2.97
Expected long-term return on plan
assets 8.25 8.25 8.25 8.25 8.25 8.25
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
Other postretirement benefit plans
Discount rate - benefit obligations 2.56 % 2.63 % 2.52 % 2.53 % 2.78 % 2.46 %
Discount rate - interest costs 1.84 1.91 1.82 1.78 2.12 1.64
Discount rate - service costs 3.07 3.13 3.08 3.06 3.05 3.01
Expected long-term return on plan
assets 7.09 7.18 6.84 6.98 - 6.54
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
2020
Assumptions used to determine net Alabama Georgia Southern Company
periodic costs: Southern Company Power Power Mississippi Power Southern Power Gas Pension plans Discount rate - benefit obligations
3.41 % 3.44 % 3.40 % 3.41 % 3.52 % 3.39 %
Discount rate - interest costs 2.99 3.01 2.96 2.99 3.18 2.99
Discount rate - service costs 3.66 3.69 3.67 3.67 3.70 3.53
Expected long-term return on plan
assets 8.25 8.25 8.25 8.25 8.25 8.25
Annual salary increase 4.73 4.73 4.73 4.73 4.73 4.73
Other postretirement benefit plans
Discount rate - benefit obligations 3.24 % 3.28 % 3.22 % 3.22 % 3.39 % 3.19 %
Discount rate - interest costs 2.80 2.84 2.79 2.76 2.97 2.71
Discount rate - service costs 3.57 3.61 3.57 3.57 3.57 3.52
Expected long-term return on plan
assets 7.25 7.36 7.05 7.07 - 6.69
Annual salary increase 4.73 4.73 4.73 4.73 4.73 4.73
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2019
Assumptions used to determine net Alabama Georgia Southern Company
periodic costs: Southern Company Power Power Mississippi Power Southern Power Gas Pension plans Discount rate - benefit obligations
4.49 % 4.51 % 4.48 % 4.49 % 4.65 % 4.47 %
Discount rate - interest costs 4.12 4.14 4.10 4.12 4.35 4.11
Discount rate - service costs 4.70 4.73 4.72 4.73 4.75 4.57
Expected long-term return on plan
assets 7.75 7.75 7.75 7.75 7.75 7.75
Annual salary increase 4.34 4.46 4.46 4.46 4.46 3.07
Other postretirement benefit plans
Discount rate - benefit obligations 4.37 % 4.40 % 4.36 % 4.35 % 4.50 % 4.32 %
Discount rate - interest costs 3.98 4.01 3.97 3.95 4.14 3.91
Discount rate - service costs 4.63 4.67 4.64 4.64 4.65 4.56
Expected long-term return on plan
assets 6.86 6.76 6.85 6.79 - 6.49
Annual salary increase 4.34 4.46 4.46 4.46 4.46 3.07
2021
Assumptions used to determine benefit Southern Company
obligations: Southern Company Alabama Power Georgia Power Mississippi Power Southern Power Gas
Pension plans
Discount rate 3.09 % 3.12 % 3.07 % 3.07 % 3.21 % 3.04 %
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
Other postretirement benefit plans
Discount rate 2.90 % 2.95 % 2.87 % 2.88 % 3.07 % 2.82 %
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
2020
Assumptions used to determine benefit Southern Company
obligations: Southern Company Alabama Power Georgia Power Mississippi Power Southern Power Gas
Pension plans
Discount rate 2.81 % 2.85 % 2.79 % 2.80 % 2.99 % 2.75 %
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
Other postretirement benefit plans
Discount rate 2.56 % 2.63 % 2.52 % 2.53 % 2.78 % 2.46 %
Annual salary increase 4.80 4.80 4.80 4.80 4.80 4.80
The Registrants estimate the expected rate of return on pension plan and other
postretirement benefit plan assets using a financial model to project the
expected return on each current investment portfolio. The analysis projects an
expected rate of return on each of the different asset classes in order to
arrive at the expected return on the entire portfolio relying on each trust's
target asset allocation and reasonable capital market assumptions. The financial
model is based on four key inputs: anticipated returns by asset class (based in
part on historical returns), each trust's target asset allocation, an
anticipated inflation rate, and the projected impact of a periodic rebalancing
of each trust's portfolio. Prior to 2020, the Registrants set the expected rate
of return assumption using asset return modeling based on geometric returns that
reflect the compound average returns for dependent annual periods. Beginning in
2020, the Registrants set the expected rate of return assumption using an
arithmetic mean which represents the expected simple average return to be earned
by the pension plan assets over any one year. The Registrants believe the use of
the arithmetic mean is more compatible with the expected rate of return's
function of estimating a single year's investment return.
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An additional assumption used in measuring the accumulated other postretirement
benefit obligations (APBO) was a weighted average medical care cost trend rate.
The weighted average medical care cost trend rates used in measuring the APBO
for the Registrants at December 31, 2021 were as follows:
Initial Cost Trend Ultimate Cost Trend Year That Ultimate
Rate Rate Rate is Reached
Pre-65 6.00 % 4.50 % 2028
Post-65 medical 5.00 4.50 2028
Post-65 prescription 6.25 4.50 2029
Pension Plans
The total accumulated benefit obligation for the pension plans at December 31, 2021 and 2020 was as follows:
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
December 31, 2021 $ 14,687 $ 3,362 $ 4,562 $ 672 $ 178 $ 1,030
December 31, 2020 14,922 3,414 4,657 683 175 1,072
An actuarial gain of $393 million was recorded for the annual remeasurement of
the Southern Company system pension plans at December 31, 2021 primarily due to
an increase of 28 basis points in the overall discount rate used to calculate
the benefit obligation as a result of higher market interest rates. An actuarial
loss of $1.7 billion was recorded for the annual remeasurement of the Southern
Company system pension plans at December 31, 2020 primarily due to a decrease of
60 basis points in the overall discount rate used to calculate the benefit
obligation as a result of lower market interest rates.
Changes in the projected benefit obligations and the fair value of plan assets during the plan years ended December 31, 2021 and 2020 were as follows:
2021
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
Change in benefit obligation
Benefit obligation at beginning of
year $ 16,646 $ 3,854 $ 5,127 $ 754 $ 217 $ 1,189
Service cost 434 102 112 18 10 37
Interest cost 346 82 104 16 5 24
Benefits paid (651) (137) (210) (28) (4) (73)
Actuarial gain (393) (95) (121) (17) (6) (43)
Balance at end of year 16,382 3,806 5,012 743 222 1,134
Change in plan assets
Fair value of plan assets at beginning
of year 15,367 3,684 4,844 701 186 1,123
Actual return on plan assets 2,449 586 781 111 30 181
Employer contributions 60 8 - 2 1 10
Benefits paid (651) (137) (210) (28) (4) (73)
Fair value of plan assets at end of
year 17,225 4,141 5,415 786 213 1,241
Accrued asset (liability) $ 843 $ 335 $ 403 $ 43 $ (9) $ 107
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2020
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
Change in benefit obligation
Benefit obligation at beginning of
year $ 14,788 $ 3,404 $ 4,610 $ 671 $ 185 $ 1,067
Service cost 376 89 96 15 8 33
Interest cost 432 100 133 20 6 31
Benefits paid (629) (132) (202) (27) (6) (69)
Actuarial loss 1,679 393 490 75 24 127
Balance at end of year 16,646 3,854 5,127 754 217 1,189
Change in plan assets
Fair value of plan assets at beginning
of year 14,057 3,357 4,442 641 169 1,050
Actual return on plan assets 1,881 450 594 85 22 139
Employer contributions 58 9 10 2 1 3
Benefits paid (629) (132) (202) (27) (6) (69)
Fair value of plan assets at end of
year 15,367 3,684 4,844 701 186 1,123
Accrued liability $ (1,279) $ (170) $ (283) $ (53) $ (31) $ (66)
The projected benefit obligations for the qualified and non-qualified pension
plans at December 31, 2021 are shown in the following table. All pension plan
assets are related to the qualified pension plan.
Southern Southern
Company Alabama Power Georgia Power Mississippi Power Southern Power Company Gas
(in millions)
Projected benefit obligations:
Qualified pension plan $ 15,568 $ 3,678 $ 4,852 $ 708 $ 193 $ 1,066
Non-qualified pension plan 814 129 160 36 29 68
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Amounts recognized in the balance sheets at December 31, 2021 and 2020 related to the Registrants' pension plans consist of the following:
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
December 31, 2021:
Prepaid pension costs(a) $ 1,657 $ 464 $ 563 $ 78 $ 20 $ 175
Other regulatory assets,
deferred(b) 2,920 809 971 146 - 91
Other current liabilities (55) (9) (12) (2) (2) (2)
Employee benefit obligations(c) (759) (120) (148) (33) (27) (66)
Other regulatory liabilities,
deferred (119) - - - - -
AOCI 100 - - - 35 (45)
December 31, 2020:
Prepaid pension costs $ - $ - $ - $ - $ - $ 70
Other regulatory assets,
deferred(b) 4,655 1,286 1,598 235 - 205
Other current liabilities (52) (9) (10) (2) (2) (2)
Employee benefit obligations(c) (1,227) (161) (273) (51) (29) (134)
Other regulatory liabilities,
deferred (34) - - - - -
AOCI 245 - - - 60 1
(a)Included in prepaid pension and other postretirement benefit costs on Alabama
Power's balance sheet and other deferred charges and assets on Southern Power's
consolidated balance sheet.
(b)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
(c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
Presented below are the amounts included in regulatory assets at December 31,
2021 and 2020 related to the portion of the defined benefit pension plan
attributable to Southern Company, the traditional electric operating companies,
and Southern Company Gas that had not yet been recognized in net periodic
pension cost.
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Company Gas
(in millions)
Balance at December 31, 2021
Regulatory assets:
Prior service cost $ 11 $ 5 $ 8 $ 1 $ (11)
Net loss 2,790 804 963 145 38
Regulatory amortization - - - - 64
Total regulatory assets(*) $ 2,801 $ 809 $ 971 $ 146 $ 91
Balance at December 31, 2020
Regulatory assets:
Prior service cost $ 11 $ 5 $ 9 $ 2 $ (13)
Net loss 4,610 1,281 1,589 233 135
Regulatory amortization - - - - 83
Total regulatory assets(*) $ 4,621 $ 1,286 $ 1,598 $ 235 $ 205
(*)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
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The changes in the balance of regulatory assets related to the portion of the
defined benefit pension plan attributable to Southern Company, the traditional
electric operating companies, and Southern Company Gas for the years ended
December 31, 2021 and 2020 are presented in the following table:
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Company Gas
(in millions)
Regulatory assets (liabilities):(*)
Balance at December 31, 2019 $ 3,993 $ 1,130 $ 1,416 $ 203 $ 172
Net loss 884 228 269 45 45
Reclassification adjustments:
Amortization of prior service costs (1) (1) (1) - 2
Amortization of net loss (255) (71) (86) (13) (8)
Amortization of regulatory assets(*) - - - - (6)
Total reclassification adjustments (256) (72) (87) (13) (12)
Total change 628 156 182 32 33
Balance at December 31, 2020 $ 4,621 $ 1,286 $ 1,598 $ 235 $ 205
Net gain (1,523) (394) (527) (74) (97)
Reclassification adjustments:
Amortization of prior service costs (1) (1) (1) - 2
Amortization of net loss (296) (82) (99) (15) (9)
Amortization of regulatory assets(*) - - - - (10)
Total reclassification adjustments (297) (83) (100) (15) (17)
Total change (1,820) (477) (627) (89) (114)
Balance at December 31, 2021 $ 2,801 $ 809 $ 971 $ 146 $ 91
(*)Amounts for Southern Company exclude regulatory assets of $210 million and $224 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' pension plans prior to its acquisition by Southern Company.
Presented below are the amounts included in AOCI at December 31, 2021 and 2020
related to the portion of the defined benefit pension plan attributable to
Southern Company, Southern Power, and Southern Company Gas that had not yet been
recognized in net periodic pension cost.
Southern Southern Southern Company
Company Power Gas
(in millions)
Balance at December 31, 2021
AOCI:
Prior service cost $ (2) $ - $ (3)
Net (gain) loss 102 35 (42)
Total AOCI $ 100 $ 35 $ (45)
Balance at December 31, 2020
AOCI:
Prior service cost $ (3) $ - $ (4)
Net loss 248 60 5
Total AOCI $ 245 $ 60 $ 1
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The components of OCI related to the portion of the defined benefit pension plan
attributable to Southern Company, Southern Power, and Southern Company Gas for
the years ended December 31, 2021 and 2020 are presented in the following table:
Southern Southern Company
Southern Company Power Gas
(in millions)
AOCI:
Balance at December 31, 2019 $ 185 $ 46 $ (14)
Net loss 74 16
15
Reclassification adjustments: Amortization of prior service costs - -
1
Amortization of net loss (14) (2)
(1)
Total reclassification adjustments (14) (2) - Total change 60 14 15 Balance at December 31, 2020 $ 245 $ 60 $ 1 Net gain (128) (22) (47) Reclassification adjustments: Amortization of net gain (loss) (17) (3)
1
Total reclassification adjustments (17) (3) 1
Total change (145) (25) (46)
Balance at December 31, 2021 $ 100 $ 35 $ (45)
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Components of net periodic pension cost for the Registrants were as follows:
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
2021
Service cost $ 434 $ 102 $ 112 $ 18 $ 10 $ 37
Interest cost 346 82 104 16 5 24
Expected return on plan assets (1,191) (287) (375) (55) (14) (86)
Recognized net loss 314 82 100 15 3 13
Net amortization 1 1 1 - - 15
Prior service cost - - - - - (3)
Net periodic pension cost (income) $ (96) $ (20) $ (58) $ (6) $ 4 $ -
2020
Service cost $ 376 $ 89 $ 96 $ 15 $ 8 $ 33
Interest cost 432 100 133 20 6 31
Expected return on plan assets (1,100) (264) (347) (51) (13) (75)
Recognized net loss 269 71 86 13 2 6
Net amortization 1 1 1 - - 15
Prior service cost - - - - - (3)
Net periodic pension cost (income) $ (22) $ (3) $ (31) $ (3) $ 3 $ 7
2019
Service cost $ 292 $ 69 $ 74 $ 12 $ 7 $ 25
Interest cost 492 114 156 22 5 36
Expected return on plan assets (885) (206) (292) (40) (10) (60)
Recognized net loss 120 37 44 6 1 2
Net amortization 2 - 1 - - 14
Prior service cost - - - - - (3)
Net periodic pension cost (income) $ 21 $ 14 $ (17) $ - $ 3 $ 14
The service cost component of net periodic pension cost is included in
operations and maintenance expenses and all other components of net periodic
pension cost are included in other income (expense), net in the Registrants'
statements of income.
Net periodic pension cost is the sum of service cost, interest cost, and other
costs netted against the expected return on plan assets. The expected return on
plan assets is determined by multiplying the expected rate of return on plan
assets and the market-related value of plan assets. In determining the
market-related value of plan assets, the Registrants have elected to amortize
changes in the market value of return-seeking plan assets over five years and to
recognize the changes in the market value of liability-hedging plan assets
immediately. Given the significant concentration in return-seeking plan assets,
the accounting value of plan assets that is used to calculate the expected
return on plan assets differs from the current fair value of the plan assets.
Effective January 1, 2020, Southern Company changed its method of calculating
the market-related value of the liability-hedging securities included in its
pension plan assets. The market-related value is used to determine the expected
return on plan assets component of net periodic pension cost. Southern Company
previously used the calculated value approach for all plan assets, which
smoothed asset returns and deferred gains and losses by amortizing them into the
calculation of the market-related value over five years. Southern Company
changed to the fair value approach for liability-hedging securities, which
includes measuring the market-related value of that portion of the plan assets
at fair value for purposes of determining the expected return on plan assets.
The remaining asset classes of plan assets continue to be valued using the
calculated value approach. Southern Company considers the fair value approach to
be preferable for liability-hedging securities because it results in a current
reflection of changes in the value of plan assets in the measurement of net
periodic pension cost more consistent with the change in the related
obligations.
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Future benefit payments reflect expected future service and are estimated based
on assumptions used to measure the projected benefit obligation for the pension
plans. At December 31, 2021, estimated benefit payments were as follows:
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas
(in millions)
Benefit Payments:
2022 $ 690 $ 148 $ 223 $ 31 $ 6 $ 65
2023 714 155 229 31 6 65
2024 736 159 235 32 6 64
2025 759 165 240 34 7 64
2026 780 171 245 35 7 64
2027 to 2031 4,138 921 1,275 187 42 329
Other Postretirement Benefits
Changes in the APBO and the fair value of the Registrants' plan assets during the plan years ended December 31, 2021 and 2020 were as follows:
2021
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
Change in benefit obligation
Benefit obligation at beginning of
year $ 1,948 $ 463 $ 699 $ 81 $ 12 $ 248
Service cost 24 6 7 1 - 2
Interest cost 35 9 12 1 - 4
Benefits paid (105) (22) (36) (5) - (18)
Actuarial (gain) loss (54) (16) (26) (2) (1) 1
Retiree drug subsidy 1 - - - - -
Balance at end of year 1,849 440 656 76 11 237
Change in plan assets
Fair value of plan assets at beginning
of year 1,158 458 427 27 - 128
Actual return on plan assets 154 55 55 4 - 18
Employer contributions 43 (2) 4 3 - 15
Benefits paid (104) (22) (36) (5) - (18)
Fair value of plan assets at end of
year 1,251 489 450 29 - 143
Accrued asset (liability) $ (598) $ 49 $ (206) $ (47) $ (11) $ (94)
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2020
Southern Georgia Southern
Company Alabama Power Power Mississippi Power Southern Power Company Gas
(in millions)
Change in benefit obligation
Benefit obligation at beginning of
year $ 1,985 $ 462 $ 742 $ 87 $ 11 $ 250
Service cost 22 6 6 1 1 2
Interest cost 54 13 20 2 - 7
Benefits paid (126) (29) (46) (6) - (17)
Actuarial (gain) loss 7 9 (26) (3) - 6
Retiree drug subsidy 6 2 3 - - -
Balance at end of year 1,948 463 699 81 12 248
Change in plan assets
Fair value of plan assets at beginning
of year 1,061 413 403 26 - 115
Actual return on plan assets 145 60 50 3 - 18
Employer contributions 72 12 17 4 - 12
Benefits paid (120) (27) (43) (6) - (17)
Fair value of plan assets at end of
year 1,158 458 427 27 - 128
Accrued liability $ (790) $ (5) $ (272) $ (54) $ (12) $ (120)
Amounts recognized in the balance sheets at December 31, 2021 and 2020 related
to the Registrants' other postretirement benefit plans consist of the following:
Southern Georgia Southern Southern
Company Alabama Power Power Mississippi Power Power Company Gas
(in millions)
December 31, 2021:
Prepaid other postretirement benefit
costs(a) $ - $ 49 $ - $ - $ - $ -
Other regulatory assets, deferred(b) 97 - 30 2 - -
Other current liabilities (5) - - - - -
Employee benefit obligations(c) (593) - (206) (47) (11) (94)
Other regulatory liabilities,
deferred (171) (62) (40) (1) - (34)
AOCI - - - - 2 (5)
December 31, 2020:
Other regulatory assets, deferred(b) $ 137 $ - $ 47 $ 5 $ - $ (23)
Other current liabilities (5) - - - - -
Employee benefit obligations(c) (785) (5) (272) (54) (12) (120)
Other regulatory liabilities,
deferred (86) (21) - - - -
AOCI 8 - - - 3 -
(a)Included in prepaid pension and other postretirement benefit costs on Alabama Power's balance sheet.
(b)Amounts for Southern Company exclude regulatory assets of $40 million and $47 million at December 31, 2021 and 2020, respectively, associated with unamortized amounts in Southern Company Gas' other postretirement benefit plans prior to its acquisition by Southern Company.
(c)Included in other deferred credits and liabilities on Southern Power's consolidated balance sheets.
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Presented below are the amounts included in net regulatory assets (liabilities)
at December 31, 2021 and 2020 related to the other postretirement benefit plans
of Southern Company, the traditional electric operating companies, and Southern
Company Gas that had not yet been recognized in net periodic other
postretirement benefit cost.
Georgia Southern
Southern Company Alabama Power Power Mississippi Power Company Gas
(in millions)
Balance at December 31, 2021:
Regulatory assets (liabilities):
Prior service cost $ 13 $ 3 $ 5 $ 1 $ 1
Net gain (87) (65) (15) - (51)
Regulatory amortization - - - - 16
Total regulatory assets (liabilities)(*) $ (74) $ (62) $ (10) $ 1 $ (34)
Balance at December 31, 2020:
Regulatory assets (liabilities):
Prior service cost $ 12 $ 3 $ 5 $ - $ 1
Net (gain) loss 39 (24) 42 5 (49)
Regulatory amortization - - - - 25
Total regulatory assets (liabilities)(*) $ 51 $ (21) $ 47 $ 5 $ (23)
(*)Amounts for Southern Company exclude regulatory assets of $40 million and $47
million at December 31, 2021 and 2020, respectively, associated with unamortized
amounts in Southern Company Gas' other postretirement benefit plans prior to its
acquisition by Southern Company.
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The changes in the balance of net regulatory assets (liabilities) related to the
other postretirement benefit plans for the plan years ended December 31, 2021
and 2020 are presented in the following table:
Georgia Southern
Southern Company Alabama Power Power Mississippi Power Company Gas
(in millions)
Net regulatory assets (liabilities):(*)
Balance at December 31, 2019 $ 121 $ 1 $ 96 $ 10 $ (11)
Net gain (65) (22) (47) (5) (5)
Reclassification adjustments:
Amortization of prior service costs 1 - 1 - -
Amortization of net loss (6) - (3) - -
Amortization of regulatory assets(*) - - - - (7)
Total reclassification adjustments (5) - (2) - (7)
Total change (70) (22) (49) (5) (12)
Balance at December 31, 2020 $ 51 $ (21) $ 47 $ 5 $ (23)
Net gain (120) (41) (55) (4) (2)
Reclassification adjustments:
Amortization of prior service costs 1 - 1 - -
Amortization of net loss (6) - (3) - -
Amortization of regulatory assets(*) - - - - (9)
Total reclassification adjustments (5) - (2) - (9)
Total change (125) (41) (57) (4) (11)
Balance at December 31, 2021 $ (74) $ (62) $ (10) $ 1 $ (34)
(*)Amounts for Southern Company exclude regulatory assets of $40 million and $47
million at December 31, 2021 and 2020, respectively, associated with unamortized
amounts in Southern Company Gas' other postretirement benefit plans prior to its
acquisition by Southern Company.
Presented below are the amounts included in AOCI at December 31, 2021 and 2020
related to the other postretirement benefit plans of Southern Company, Southern
Power, and Southern Company Gas that had not yet been recognized in net periodic
other postretirement benefit cost.
Southern Southern Southern Company
Company Power Gas
(in millions)
Balance at December 31, 2021
AOCI:
Prior service cost $ 1 $ - $ 1
Net (gain) loss (1) 2 (6)
Total AOCI $ - $ 2 $ (5)
Balance at December 31, 2020
AOCI:
Prior service cost $ 1 $ - $ 1
Net (gain) loss 7 3 (1)
Total AOCI $ 8 $ 3 $ -
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The components of OCI related to the other postretirement benefit plans for the
plan years ended December 31, 2021 and 2020 are presented in the following
table:
Southern
Southern Company Power Southern Company Gas
(in millions)
AOCI:
Balance at December 31, 2019 $ 2 $ 2 $ (4)
Net loss 2 1
-
Reclassification adjustments:
Amortization of net gain (loss) 4 - 4 Total change 6 1 4 Balance at December 31, 2020 $ 8 $ 3 $ - Net gain (11) (1) - Reclassification adjustments: Amortization of net gain (loss) 3 - (5) Total change (8) (1) (5) Balance at December 31, 2021 $ - $ 2 $ (5)
Components of the other postretirement benefit plans' net periodic cost for the Registrants were as follows:
Southern Georgia Southern Company
Company Alabama Power Power Mississippi Power Southern Power Gas
(in millions)
2021
Service cost $ 24 $ 6 $ 7 $ 1 $ - $ 2
Interest cost 35 9 12 1 - 4
Expected return on plan assets (76) (30) (26) (1) 1 (10)
Net amortization 2 - 2 - - 6
Net periodic postretirement benefit
cost (income) $ (15) $ (15) $ (5) $ 1 $ 1 $ 2
2020
Service cost $ 22 $ 6 $ 6 $ 1 $ 1 $ 2
Interest cost 54 13 20 2 - 7
Expected return on plan assets (72) (29) (26) (1) - (10)
Net amortization 1 - 2 - - 6
Net periodic postretirement benefit
cost (income) $ 5 $ (10) $ 2 $ 2 $ 1 $ 5
2019
Service cost $ 18 $ 5 $ 5 $ 1 $ 1 $ 1
Interest cost 69 16 26 3 - 9
Expected return on plan assets (65) (26) (25) (2) - (7)
Net amortization - 4 1 - - 6
Net periodic postretirement benefit
cost (income) $ 22 $ (1) $ 7 $ 2 $ 1 $ 9
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The service cost component of net periodic postretirement benefit cost is
included in operations and maintenance expenses and all other components of net
periodic postretirement benefit cost are included in other income (expense), net
in the Registrants' statements of income.
The Registrants' future benefit payments, including prescription drug benefits,
are provided in the table below. These amounts reflect expected future service
and are estimated based on assumptions used to measure the APBO for the other
postretirement benefit plans.
Georgia Southern Company
Southern Company Alabama Power Power Mississippi Power Southern Power Gas
(in millions)
Benefit payments:
2022 $ 111 $ 24 $ 40 $ 5 $ - $ 17
2023 110 24 39 5 - 17
2024 109 24 38 5 - 18
2025 112 25 40 5 1 17
2026 112 25 40 5 1 17
2027 to 2031 552 128 199 22 3 75
Benefit Plan Assets
Pension plan and other postretirement benefit plan assets are managed and
invested in accordance with all applicable requirements, including ERISA and the
Internal Revenue Code. The Registrants' investment policies for both the pension
plans and the other postretirement benefit plans cover a diversified mix of
assets as described below. Derivative instruments may be used to gain efficient
exposure to the various asset classes and as hedging tools. Additionally, the
Registrants minimize the risk of large losses primarily through diversification
but also monitor and manage other aspects of risk.
The investment strategy for plan assets related to the Southern Company system's
qualified pension plan is to be broadly diversified across major asset classes.
The asset allocation is established after consideration of various factors that
affect the assets and liabilities of the pension plan including, but not limited
to, historical and expected returns and interest rates, volatility, correlations
of asset classes, the current level of assets and liabilities, and the assumed
growth in assets and liabilities. Because a significant portion of the liability
of the pension plan is long-term in nature, the assets are invested consistent
with long-term investment expectations for return and risk. To manage the actual
asset class exposures relative to the target asset allocation, the Southern
Company system employs a formal rebalancing program. As additional risk
management, external investment managers and service providers are subject to
written guidelines to ensure appropriate and prudent investment practices.
Management believes the portfolio is well-diversified with no significant
concentrations of risk.
Southern Company's investment strategy also includes adjusting the established
asset allocation to invest a larger portion of the portfolio in fixed rate debt
securities should the qualified pension plan achieve a predetermined funding
threshold. Any future reallocation of plan assets based on achieving the funding
threshold would likely result in a reduction in the expected long-term return on
plan assets used to determine pension income. However, the amount of such a
decrease and the related financial statement impact cannot be determined at this
time.
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Investment Strategies and Benefit Plan Asset Fair Values
A description of the major asset classes that the pension and other postretirement benefit plans are comprised of, along with the valuation methods used for fair value measurement, is provided below:
Description Valuation Methodology
Domestic equity: A mix of large and small Domestic and international equities such as common
capitalization stocks with generally an equal stocks, American depositary receipts, and real
distribution of value and growth attributes, managed estate investment trusts that trade on public
both actively and through passive index approaches. exchanges are classified as Level 1 investments and
are valued at the closing price in the active
International equity: A mix of large and small market. Equity funds with unpublished prices that
capitalization growth and value stocks with are comprised of publicly traded securities (such as
developed and emerging markets exposure, managed commingled/pooled funds) are also valued at the
both actively and through fundamental indexing closing price in the active market, but are
approaches. classified as Level 2.
Investments in fixed income securities, including
fixed income pooledfunds, are generally classified
as Level 2 investments and are valued based on
Fixed income: A mix of domestic and international prices reported in the market place. Additionally,
bonds. the value of fixed income securities takes into
consideration certain items such as broker quotes,
spreads, yield curves, interest rates, and discount
rates that apply to the term of a specific
instrument.
Investments in TOLI policies are classified as Level
Trust-owned life insurance (TOLI): Investments of 2 investments and are valued based on the underlying
taxable trusts aimed at minimizing the impact of investments held in the policy's separate accounts.
taxes on the portfolio. The underlying assets are equity and fixed income
pooled funds that are comprised of Level 1 and Level
2 securities.
Special situations: Investments in opportunistic
strategies with the objective of diversifying and Investments in real estate, private equity, and
enhancing returns and exploiting short-term special situations are generally classified as Net
inefficiencies, as well as investments in promising Asset Value as a Practical Expedient, since the
new strategies of a longer-term nature. underlying assets typically do not have publicly
available observable inputs. The fund manager values
Real estate: Investments in traditional private the assets using various inputs and techniques
market, equity-oriented investments in real depending on the nature of the underlying
properties (indirectly through pooled funds or investments. Techniques may include purchase
partnerships) and in publicly traded real estate multiples for comparable transactions, comparable
securities. public company trading multiples, discounted cash
flow analysis, prevailing market capitalization
Private equity: Investments in private partnerships rates, recent sales of comparable investments, and
that invest in private or public securities independent third-party appraisals. The fair value
typically through privately-negotiated and/or of partnerships is determined by aggregating the
structured transactions, including leveraged value of the underlying assets less liabilities.
buyouts, venture capital, and distressed debt.
For purposes of determining the fair value of the pension plan and other
postretirement benefit plan assets and the appropriate level designation,
management relies on information provided by the plan's trustee. This
information is reviewed and evaluated by management with changes made to the
trustee information as appropriate. The fair values presented herein exclude
cash, receivables related to investment income and pending investment sales, and
payables related to pending investment purchases. The Registrants did not have
any investments classified as Level 3 at December 31, 2020.
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The fair values, and actual allocations relative to the target allocations, of
the Southern Company system's pension plans at December 31, 2021 and 2020 are
presented below.
Fair Value Measurements Using
Significant
Quoted Prices in Other Significant Net Asset Value
Active Markets for Observable Unobservable as a Practical
Identical Assets Inputs Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company
Assets:
Equity: 51 % 53 %
Domestic equity $ 3,095 $ 1,326 $ - $ - $ 4,421
International equity 2,740 1,402 3 - 4,145
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 1,209 - - 1,209
Mortgage- and asset-backed
securities - 10 - - 10
Corporate bonds - 1,752 - - 1,752
Pooled funds - 771 - - 771
Cash equivalents and other 405 7 - - 412
Real estate investments 706 - - 2,038 2,744 14 15
Special situations - - - 171 171 3 1
Private equity - - - 1,590 1,590 9 9
Total $ 6,946 $ 6,477 $ 3 $ 3,799 $ 17,225 100 % 100 %
Alabama Power
Assets:
Equity: 51 % 53 %
Domestic equity $ 743 $ 319 $ - $ - $ 1,062
International equity 659 337 1 - 997
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 291 - - 291
Mortgage- and asset-backed
securities - 2 - - 2
Corporate bonds - 421 - - 421
Pooled funds - 186 - - 186
Cash equivalents and other 97 2 - - 99
Real estate investments 170 - - 490 660 14 15
Special situations - - - 41 41 3 1
Private equity - - - 382 382 9 9
Total $ 1,669 $ 1,558 $ 1 $ 913 $ 4,141 100 % 100 %
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Fair Value Measurements Using
Significant
Quoted Prices in Other Significant Net Asset Value
Active Markets for Observable Unobservable as a Practical
Identical Assets Inputs Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total Target Allocation Actual Allocation
(in millions)
Georgia Power
Assets:
Equity: 51 % 53 %
Domestic equity $ 972 $ 417 $ - $ - $ 1,389
International equity 861 441 1 - 1,303
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 380 - - 380
Mortgage- and asset-backed
securities - 3 - - 3
Corporate bonds - 551 - - 551
Pooled funds - 243 - - 243
Cash equivalents and other 127 2 - - 129
Real estate investments 222 - - 641 863 14 15
Special situations - - - 54 54 3 1
Private equity - - - 500 500 9 9
Total $ 2,182 $ 2,037 $ 1 $ 1,195 $ 5,415 100 % 100 %
Mississippi Power
Assets:
Equity: 51 % 53 %
Domestic equity $ 142 $ 61 $ - $ - $ 203
International equity 126 64 - - 190
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 55 - - 55
Corporate bonds - 80 - - 80
Pooled funds - 35 - - 35
Cash equivalents and other 18 - - - 18
Real estate investments 32 - - 93 125 14 15
Special situations - - - 8 8 3 1
Private equity - - - 73 73 9 9
Total $ 318 $ 295 $ - $ 174 $ 787 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Other Significant Value as a
Active Markets for Observable Unobservable Practical
Identical Assets Inputs Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Power
Assets:
Equity: 51 % 53 %
Domestic equity $ 38 $ 16 $ - $ - $ 54
International equity 34 17 - - 51
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 15 - - 15
Corporate bonds - 22 - - 22
Pooled funds - 10 - - 10
Cash equivalents and other 5 - - - 5
Real estate investments 9 - - 25 34 14 15
Special situations - - - 2 2 3 1
Private equity - - - 20 20 9 9
Total $ 86 $ 80 $ - $ 47 $ 213 100% 100 %
Southern Company Gas
Assets:
Equity: 51 % 53 %
Domestic equity $ 223 $ 96 $ - $ - $ 319
International equity 197 101 - - 298
Fixed income: 23 22
U.S. Treasury, government, and
agency bonds - 87 - - 87
Mortgage- and asset-backed
securities - 1 - - 1
Corporate bonds - 126 - - 126
Pooled funds - 56 - - 56
Cash equivalents and other 29 - - - 29
Real estate investments 51 - - 147 198 14 15
Special situations - - - 12 12 3 1
Private equity - - - 115 115 9 9
Total $ 500 $ 467 $ - $ 274 $ 1,241 100 % 100 %
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Fair Value Measurements Using
Significant
Quoted Prices in Other Net Asset Value
Active Markets for Observable as a Practical
Identical Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company
Assets:
Equity: 51 % 56 %
Domestic equity $ 2,852 $ 1,247 $ - $ 4,099
International equity 2,660 1,497 - 4,157
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 951 - 951
Mortgage- and asset-backed securities - 9 - 9
Corporate bonds - 1,673 - 1,673
Pooled funds - 772 - 772
Cash equivalents and other 356 5 - 361
Real estate investments 542 - 1,596 2,138 14 13
Special situations - - 166 166 3 1
Private equity - - 1,104 1,104 9 7
Total $ 6,410 $ 6,154 $ 2,866 $ 15,430 100 % 100 %
Alabama Power
Assets:
Equity: 51 % 56 %
Domestic equity $ 685 $ 299 $ - $ 984
International equity 638 359 - 997
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 228 - 228
Mortgage- and asset-backed securities - 2 - 2
Corporate bonds - 401 - 401
Pooled funds - 185 - 185
Cash equivalents and other 85 1 - 86
Real estate investments 130 - 382 512 14 13
Special situations - - 40 40 3 1
Private equity - - 264 264 9 7
Total $ 1,538 $ 1,475 $ 686 $ 3,699 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Other Value as a
Active Markets for Observable Practical
Identical Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Georgia Power
Assets:
Equity: 51 % 56 %
Domestic equity $ 899 $ 393 $ - $ 1,292
International equity 839 472 - 1,311
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 300 - 300
Mortgage- and asset-backed securities - 3 - 3
Corporate bonds - 527 - 527
Pooled funds - 243 - 243
Cash equivalents and other 112 1 - 113
Real estate investments 171 - 503 674 14 13
Special situations - - 53 53 3 1
Private equity - - 348 348 9 7
Total $ 2,021 $ 1,939 $ 904 $ 4,864 100 % 100 %
Mississippi Power
Assets:
Equity: 51 % 56 %
Domestic equity $ 131 $ 57 $ - $ 188
International equity 122 68 - 190
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 43 - 43
Corporate bonds - 76 - 76
Pooled funds - 35 - 35
Cash equivalents and other 16 - - 16
Real estate investments 25 - 73 98 14 13
Special situations - - 8 8 3 1
Private equity - - 50 50 9 7
Total $ 294 $ 279 $ 131 $ 704 100 % 100 %
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Fair Value Measurements Using
Quoted Prices in Significant Net Asset
Active Markets Other Value as a
for Identical Observable Practical
Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Power
Assets:
Equity: 51 % 56 %
Domestic equity $ 35 $ 15 $ - $ 50
International equity 32 19 - 51
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 12 - 12
Corporate bonds - 20 - 20
Pooled funds - 9 - 9
Cash equivalents and other 4 - - 4
Real estate investments 7 - 19 26 14 13
Special situations - - 2 2 3 1
Private equity - - 13 13 9 7
Total $ 78 $ 75 $ 34 $ 187 100 % 100 %
Southern Company Gas
Assets:
Equity: 51 % 56 %
Domestic equity $ 209 $ 91 $ - $ 300
International equity 195 109 - 304
Fixed income: 23 23
U.S. Treasury, government, and agency
bonds - 69 - 69
Mortgage- and asset-backed securities - 1 - 1
Corporate bonds - 122 - 122
Pooled funds - 56 - 56
Cash equivalents and other 26 - - 26
Real estate investments 40 - 117 157 14 13
Special situations - - 12 12 3 1
Private equity - - 81 81 9 7
Total $ 470 $ 448 $ 210 $ 1,128 100 % 100 %
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued) Southern Company and Subsidiary Companies 2021 Annual Report The fair values, and actual allocations relative to the target allocations, of the applicable Registrants' other postretirement benefit plan assets at December 31, 2021 and 2020 are presented below.
Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Other Value as a
Active Markets for Observable Practical
Identical Assets Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company
Assets:
Equity: 64 % 66 %
Domestic equity $ 123 $ 112 $ - $ 235
International equity 73 99 - 172
Fixed income: 27 25
U.S. Treasury, government, and agency bonds - 37 - 37
Corporate bonds - 50 - 50
Pooled funds - 90 - 90
Cash equivalents and other 14 - - 14
Trust-owned life insurance - 530 - 530
Real estate investments 20 - 54 74 5 6
Special situations - - 5 5 1 -
Private equity - - 42 42 3 3
Total $ 230 $ 918 $ 101 $ 1,249 100 % 100 %
Alabama Power
Assets:
Equity: 71 % 69 %
Domestic equity $ 26 $ 11 $ - $ 37
International equity 23 12 - 35
Fixed income: 21 21
U.S. Treasury, government, and agency bonds - 10 - 10
Corporate bonds - 18 - 18
Pooled funds - 6 - 6
Cash equivalents and other 3 - - 3
Trust-owned life insurance - 341 - 341
Real estate investments 6 - 17 23 4 7
Special situations - - 2 2 1 -
Private equity - - 13 13 3 3
Total $ 58 $ 398 $ 32 $ 488 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Active Other Value as a
Markets for Identical Observable Practical
Assets Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Georgia Power
Assets:
Equity: 60 % 62 %
Domestic equity $ 65 $ 13 $ - $ 78
International equity 22 50 - 72
Fixed income: 33 30
U.S. Treasury, government, and agency
bonds - 9 - 9
Corporate bonds - 14 - 14
Pooled funds - 46 - 46
Cash equivalents and other 5 - - 5
Trust-owned life insurance - 189 - 189
Real estate investments 7 - 16 23 4 5
Special situations - - 1 1 1 -
Private equity - - 13 13 2 3
Total $ 99 $ 321 $ 30 $ 450 100 % 100 %
Mississippi Power
Assets:
Equity: 43 % 44 %
Domestic equity $ 4 $ 2 $ - $ 6
International equity 4 2 - 6
Fixed income: 36 34
U.S. Treasury, government, and agency
bonds - 5 - 5
Corporate bonds - 2 - 2
Pooled funds - 1 - 1
Cash equivalents and other 1 - - 1
Real estate investments 1 - 3 4 11 13
Special situations - - - - 2 1
Private equity - - 2 2 8 8
Total $ 10 $ 12 $ 5 $ 27 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Other Value as a
Quoted Prices in Active Observable Practical
Markets for Identical Assets Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company Gas
Assets:
Equity: 72 % 73 %
Domestic equity $ 3 $ 76 $ - $ 79
International equity 2 24 - 26
Fixed income: 26 24
U.S. Treasury, government, and agency
bonds - 1 - 1
Corporate bonds - 1 - 1
Pooled funds - 30 - 30
Cash equivalents and other 2 - - 2
Real estate investments 1 - 2 3 1 2
Private equity - - 1 1 1 1
Total $ 8 $ 132 $ 3 $ 143 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Other Value as a
Active Markets for Observable Practical
Identical Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company
Assets:
Equity: 63 % 66 %
Domestic equity $ 113 $ 98 $ - $ 211
International equity 71 102 - 173
Fixed income: 28 27
U.S. Treasury, government, and agency
bonds - 32 - 32
Corporate bonds - 44 - 44
Pooled funds - 86 - 86
Cash equivalents and other 15 - - 15
Trust-owned life insurance - 508 - 508
Real estate investments 15 - 42 57 5 5
Special situations - - 4 4 1 -
Private equity - - 29 29 3 2
Total $ 214 $ 870 $ 75 $ 1,159 100 % 100 %
Alabama Power
Assets:
Equity: 68 % 69 %
Domestic equity $ 26 $ 11 $ - $ 37
International equity 23 13 - 36
Fixed income: 24 25
U.S. Treasury, government, and agency
bonds - 11 - 11
Corporate bonds - 14 - 14
Pooled funds - 7 - 7
Cash equivalents and other 5 - - 5
Trust-owned life insurance - 321 - 321
Real estate investments 5 - 13 18 4 4
Special situations - - 1 1 1 -
Private equity - - 9 9 3 2
Total $ 59 $ 377 $ 23 $ 459 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Active Other Value as a
Markets for Identical Observable Practical
Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Georgia Power
Assets:
Equity: 60 % 64 %
Domestic equity $ 58 $ 10 $ - $ 68
International equity 21 50 - 71
Fixed income: 33 30
U.S. Treasury, government, and
agency bonds - 8 - 8
Corporate bonds - 13 - 13
Pooled funds - 46 - 46
Cash equivalents and other 5 - - 5
Trust-owned life insurance - 188 - 188
Real estate investments 5 - 13 18 4 4
Special situations - - 1 1 1 -
Private equity - - 9 9 2 2
Total $ 89 $ 315 $ 23 $ 427 100 % 100 %
Mississippi Power
Assets:
Equity: 43 % 46 %
Domestic equity $ 4 $ 2 $ - $ 6
International equity 4 2 - 6
Fixed income: 37 36
U.S. Treasury, government, and agency
bonds - 5 - 5
Corporate bonds - 2 - 2
Pooled funds - 1 - 1
Cash equivalents and other 1 - - 1
Real estate investments 1 - 2 3 11 11
Special situations - - - - 2 1
Private equity - - 2 2 7 6
Total $ 10 $ 12 $ 4 $ 26 100 % 100 %
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Fair Value Measurements Using
Significant Net Asset
Other Value as a
Quoted Prices in Active Observable Practical
Markets for Identical Assets Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (NAV) Total Target Allocation Actual Allocation
(in millions)
Southern Company Gas
Assets:
Equity: 72 % 76 %
Domestic equity $ 2 $ 66 $ - $ 68
International equity 2 25 - 27
Fixed income: 26 22
U.S. Treasury, government, and agency
bonds - 1 - 1
Corporate bonds - 1 - 1
Pooled funds - 25 - 25
Cash equivalents and other 1 - - 1
Real estate investments - - 1 1 1 1
Private equity - - 1 1 1 1
Total $ 5 $ 118 $ 2 $ 125 100 % 100 %
Employee Savings Plan
Southern Company and its subsidiaries also sponsor 401(k) defined contribution
plans covering substantially all employees and provide matching contributions up
to specified percentages of an employee's eligible pay. Total matching
contributions made to the plans for 2021, 2020, and 2019 were as follows:
Alabama Georgia Mississippi Southern
Southern Company Power Power Power Power
Southern Company Gas
(in millions)
2021 $ 119 $ 26 $ 28 $ 5 $ 2 $ 16
2020 120 26 29 5 2 16
2019 113 25 27 4 2 15
12. STOCK COMPENSATION
Stock-based compensation primarily in the form of Southern Company performance
share units (PSU) and restricted stock units (RSU) may be granted through the
Equity and Incentive Compensation Plan to Southern Company system employees
ranging from line management to executives.
At December 31, 2021, the number of current and former employees participating in stock-based compensation programs for the Registrants was as follows:
Southern Company Alabama Power Georgia Power Mississippi Power Southern Power Southern Company Gas
Number of employees 1,728 241 271 70 45 173
The majority of PSUs and RSUs awarded contain terms where employees become immediately vested in PSUs and RSUs upon retirement. As a result, compensation expense for employees that are retirement eligible at the grant date is recognized
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immediately, while compensation expense for employees that become retirement eligible during the vesting period is recognized over the period from grant date to the date of retirement eligibility. In addition, the Registrants recognize forfeitures as they occur.
All unvested PSUs and RSUs vest immediately upon a change in control where Southern Company is not the surviving corporation.
Performance Share Units
PSUs granted to employees vest at the end of a three-year performance period. Shares of Southern Company common stock are delivered to employees at the end of the performance period with the number of shares issued ranging from 0% to 200% of the target number of PSUs granted, based on achievement of the performance goals established by the Compensation Committee of the Southern Company Board of Directors. Southern Company has issued three types of PSUs, each with a unique performance goal. These types of PSUs include total shareholder return (TSR) awards based on the TSR for Southern Company common stock during the three-year performance period as compared to a group of industry peers; ROE awards based on Southern Company's equity-weighted return over the performance period; and EPS awards based on Southern Company's cumulative EPS over the performance period. EPS awards were last granted in 2017. The fair value of TSR awards is determined as of the grant date using a Monte Carlo simulation model. In determining the fair value of the TSR awards issued to employees, the expected volatility is based on the historical volatility of Southern Company's stock over a period equal to the performance period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant that covers the performance period of the awards. The following table shows the assumptions used in the pricing model and the weighted average grant-date fair value of TSR awards granted: Year Ended December 31 2021 2020 2019 Expected volatility 30.0% 15.4% 15.6% Expected term (in years) 3 3 3 Interest rate 0.2% 1.4% 2.4%
Weighted average grant-date fair value $69.06 $77.65 $62.71
The Registrants recognize TSR award compensation expense on a straight-line basis over the three-year performance period without remeasurement.
The fair values of EPS awards and ROE awards are based on the closing stock price of Southern Company common stock on the date of the grant. The weighted average grant-date fair value of the ROE awards granted during 2021, 2020, and 2019 was $59.49, $68.42, and $49.38, respectively. Compensation expense for EPS and ROE awards is generally recognized ratably over the three-year performance period adjusted for expected changes in EPS and ROE performance. Total compensation cost recognized for vested EPS awards and ROE awards reflects final performance metrics. Southern Company had 2.2 million unvested PSUs outstanding at December 31, 2020. In February 2021, the PSUs that vested for the three-year performance period ended December 31, 2020 were converted into 2.5 million shares outstanding at a share price of $60.10. During 2021, Southern Company granted 1.3 million PSUs and 1.3 million PSUs were vested or forfeited, resulting in 2.2 million unvested PSUs outstanding at December 31, 2021. In February 2022, the PSUs that vested for the three-year performance period ended December 31, 2021 were converted into 2.5 million shares outstanding at a weighted average share price of $66.57.
Total PSU compensation cost, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 are as follows:
2021 2020 2019
(in millions)
Southern Company
Compensation cost recognized in income $ 112 $ 84 $ 77
Tax benefit of compensation cost recognized in income 29 22 20
Southern Company Gas
Compensation cost recognized in income $ 17 $ 13 $ 14
Tax benefit of compensation cost recognized in income 4 4 4
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Total PSU compensation cost and the related tax benefit recognized in income
were immaterial for all periods presented for all other Registrants. The
compensation cost related to the grant of Southern Company PSUs to the employees
of each Subsidiary Registrant is recognized in each Subsidiary Registrant's
financial statements with a corresponding credit to equity representing a
capital contribution from Southern Company.
At December 31, 2021, Southern Company's total unrecognized compensation cost
related to PSUs was $32 million and is expected to be recognized over a
weighted-average period of approximately 19 months. The total unrecognized
compensation cost related to PSUs at December 31, 2021 was immaterial for all
other Registrants.
Restricted Stock Units
The fair value of RSUs is based on the closing stock price of Southern Company
common stock on the date of the grant. The weighted average grant-date fair
values of RSUs granted during 2021, 2020, and 2019 were $59.56, $67.60, and
$50.44, respectively. For most RSU awards, one-third of the RSUs vest each year
throughout a three-year service period and compensation cost for RSUs is
generally recognized over the corresponding one-, two-, or three-year vesting
period. Shares of Southern Company common stock are delivered to employees at
the end of each vesting period.
Southern Company had 1.2 million RSUs outstanding at December 31, 2020. During
2021, Southern Company granted 0.5 million RSUs and 0.6 million RSUs were vested
or forfeited, resulting in 1.1 million unvested RSUs outstanding at December 31,
2021, including RSUs related to employee retention agreements.
For the years ended December 31, 2021, 2020, and 2019, Southern Company's total
compensation cost for RSUs recognized in income was $32 million, $29 million,
and $28 million, respectively. The related tax benefit also recognized in income
was $8 million, $8 million, and $7 million for the years ended December 31,
2021, 2020, and 2019, respectively. Total unrecognized compensation cost related
to RSUs at December 31, 2021, which is being recognized over a weighted-average
period of approximately 16 months, is immaterial for Southern Company.
Total RSUs outstanding and total compensation cost and related tax benefit for
the RSUs recognized in income for the years ended December 31, 2021, 2020, and
2019, as well as the total unrecognized compensation cost at December 31, 2021,
were immaterial for all other Registrants. The compensation cost related to the
grant of Southern Company RSUs to the employees of each Subsidiary Registrant is
recognized in such Subsidiary Registrant's financial statements with a
corresponding credit to equity representing a capital contribution from Southern
Company.
Stock Options
In 2015, Southern Company discontinued granting stock options. As of
December 31, 2017, all stock option awards were vested and compensation cost
fully recognized. Stock options expire no later than 10 years after the grant
date and the latest possible exercise will occur by November 2024. At
December 31, 2021, the weighted average remaining contractual term for the
options outstanding and exercisable was approximately 19 months.
Southern Company's activity in the stock option program for 2021 is summarized
below:
Weighted Average
Shares Subject to Option Exercise Price
(in millions)
Outstanding at December 31, 2020 4.3 $ 43.04
Exercised 1.5 43.21
Outstanding and Exercisable at December 31, 2021 2.8 $ 42.95
Southern Company's cash receipts from issuances related to stock options exercised under the share-based payment arrangements for the years ended December 31, 2021, 2020, and 2019 were $66 million, $66 million, and $482 million, respectively.
At December 31, 2021, the aggregate intrinsic value for the options outstanding and exercisable was as follows:
Southern Company
Southern Company Georgia Power Gas
(in millions)
Total intrinsic value for outstanding and exercisable
options $ 71 $ 17 $ 8
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The aggregate intrinsic value for the options outstanding and exercisable was immaterial for Alabama Power, Mississippi Power, and Southern Power at December 31, 2021.
Total intrinsic value of options exercised, and the related tax benefit, for the years ended December 31, 2021, 2020, and 2019 are presented below:
Year Ended December 31 2021 2020 2019
(in millions)
Southern Company
Intrinsic value of options exercised $ 34 $ 38 $ 167
Tax benefit of options exercised 7 9 35
Alabama Power
Intrinsic value of options exercised $ 3 $ 5 $ 21
Tax benefit of options exercised 1 1 4
Georgia Power
Intrinsic value of options exercised $ 14 $ 9 $ 30
Tax benefit of options exercised 3 2 6
Total intrinsic value of options exercised, and the related tax benefit recognized in income, for the years ended December 31, 2021, 2020, and 2019 were immaterial for Mississippi Power, Southern Power, and Southern Company Gas.
13. FAIR VALUE MEASUREMENTS
Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement.
•Level 1 consists of observable market data in an active market for identical assets or liabilities.
•Level 2 consists of observable market data, other than that included in Level 1, that is either directly or indirectly observable.
•Level 3 consists of unobservable market data. The input may reflect the assumptions of each Registrant of what a market participant would use in pricing an asset or liability. If there is little available market data, then each Registrant's own assumptions are the best available information.
In the case of multiple inputs being used in a fair value measurement, the
lowest level input that is significant to the fair value measurement represents
the level in the fair value hierarchy in which the fair value measurement is
reported.
Net asset value as a practical expedient is the classification used for assets
that do not have readily determined fair values. Fund managers value the assets
using various inputs and techniques depending on the nature of the underlying
investments.
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At December 31, 2021, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
Fair Value Measurements Using
Net Asset
Quoted Prices in Value as a
Active Markets for Significant Other Significant Practical
Identical Assets Observable Inputs Unobservable Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Southern Company
Assets:
Energy-related derivatives(a) $ 24 $ 195 $ - $ - $ 219
Interest rate derivatives - 19 - - 19
Investments in trusts:(b)(c)
Domestic equity 791 225 - - 1,016
Foreign equity 165 188 - - 353
U.S. Treasury and government agency
securities - 314 - - 314
Municipal bonds - 56 - - 56
Pooled funds - fixed income - 13 - - 13
Corporate bonds 1 522 - - 523
Mortgage and asset backed securities - 93 - - 93
Private equity - - - 150 150
Cash and cash equivalents 2 - - - 2
Other 22 25 - - 47
Cash equivalents 1,160 14 - - 1,174
Other investments 9 35 - - 44
Total $ 2,174 $ 1,699 $ - $ 150 $ 4,023
Liabilities:
Energy-related derivatives(a) $ 10 $ 36 $ - $ - $ 46
Interest rate derivatives - 29 - - 29
Foreign currency derivatives - 79 - - 79
Contingent consideration - - 14 - 14
Other - 13 - - 13
Total $ 10 $ 157 $ 14 $ - $ 181
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Fair Value Measurements Using
Net Asset
Quoted Prices in Significant Value as a
Active Markets for Significant Other Unobservable Practical
Identical Assets Observable Inputs Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Alabama Power
Assets:
Energy-related derivatives $ - $ 55 $ - $ - $ 55 Nuclear decommissioning trusts:(b) Domestic equity
468 216 - - 684
Foreign equity 165 - - - 165
U.S. Treasury and government agency
securities - 21 - - 21
Municipal bonds - 1 - - 1
Corporate bonds 1 271 - - 272
Mortgage and asset backed securities - 22 - - 22
Private equity - - - 150 150
Other 9 - - - 9
Cash equivalents 839 14 - - 853
Other investments - 35 - - 35
Total $ 1,482 $ 635 $ - $ 150 $ 2,267
Liabilities:
Energy-related derivatives $ - $ 11 $ - $ - $ 11
Georgia Power
Assets:
Energy-related derivatives $ - $ 75 $ - $ - $ 75
Nuclear decommissioning trusts:(b)(c)
Domestic equity 323 1 - - 324
Foreign equity - 185 - - 185
U.S. Treasury and government agency
securities - 293 - - 293
Municipal bonds - 55 - - 55
Corporate bonds - 251 - - 251
Mortgage and asset backed securities - 71 - - 71
Other 13 25 - - 38
Total $ 336 $ 956 $ - $ - $ 1,292
Liabilities:
Energy-related derivatives $ - $ 8 $ - $ - $ 8
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Fair Value Measurements Using
Significant Net Asset
Quoted Prices in Active Other Value as a
Markets for Identical Observable Significant Practical
Assets Inputs Unobservable Inputs Expedient
At December 31, 2021: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Mississippi Power
Assets:
Energy-related derivatives $ - $ 56 $ - $ - $ 56
Cash equivalents 40 - - - 40
Total $ 40 $ 56 $ - $ - $ 96
Liabilities:
Energy-related derivatives $ - $ 5 $ - $ - $ 5
Southern Power
Assets:
Energy-related derivatives $ - $ 4 $ - $ - $ 4
Liabilities:
Foreign currency derivatives $ - $ 16 $ - $ - $ 16
Contingent consideration - - 14 - 14
Other - 13 - - 13
Total $ - $ 29 $ 14 $ - $ 43
Southern Company Gas
Assets:
Energy-related derivatives(a) $ 24 $ 5 $ - $ - $ 29
Interest rate derivatives - 6 - - 6
Non-qualified deferred compensation
trusts:
Domestic equity - 8 - - 8
Foreign equity - 3 - - 3
Pooled funds - fixed income - 13 - - 13
Cash equivalents 2 - - - 2
Total $ 26 $ 35 $ - $ - $ 61
Liabilities:
Energy-related derivatives(a)(b) $ 10 $ 12 $ - $ - $ 22
Interest rate derivatives - 5 - - 5
Total $ 10 $ 17 $ - $ - $ 27
(a)Excludes immaterial cash collateral.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.
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At December 31, 2020, assets and liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
Fair Value Measurements Using
Net Asset
Quoted Prices in Value as a
Active Markets for Significant Other Significant Practical
Identical Assets ObservableInputs Unobservable Inputs Expedient At December 31, 2020:
(Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Southern Company
Assets:
Energy-related derivatives(a) $ 401 $ 271 $ 32 $ - $ 704
Interest rate derivatives - 20 - - 20
Foreign currency derivatives - 87 - - 87
Investments in trusts:(b)(c)
Domestic equity 862 151 - - 1,013
Foreign equity 85 253 - - 338
U.S. Treasury and government agency
securities - 284 - - 284
Municipal bonds - 85 - - 85
Pooled funds - fixed income - 17 - - 17
Corporate bonds 13 386 - - 399
Mortgage and asset backed securities - 83 - - 83
Private equity - - - 76 76
Cash and cash equivalents 1 - - - 1
Other 28 7 - - 35
Cash equivalents 575 9 - - 584
Other investments 9 24 - - 33
Total $ 1,974 $ 1,677 $ 32 $ 76 $ 3,759
Liabilities:
Energy-related derivatives(a) $ 389 $ 204 $ 4 $ - $ 597
Foreign currency derivatives - 23 - - 23
Contingent consideration - - 17 - 17
Total $ 389 $ 227 $ 21 $ - $ 637
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Fair Value Measurements Using
Quoted Prices in Net Asset
Active Markets Significant Value as a
for Identical Significant Other Unobservable Practical
Assets Observable Inputs Inputs Expedient
At December 31, 2020: (Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Alabama Power
Assets:
Energy-related derivatives $ - $ 12 $ - $ - $ 12 Nuclear decommissioning trusts:(b) Domestic equity
543 141 - - 684
Foreign equity 85 73 - - 158
U.S. Treasury and government agency
securities - 21 - - 21
Municipal bonds - 1 - - 1
Corporate bonds 13 167 - - 180
Mortgage and asset backed securities - 29 - - 29
Private equity - - - 76 76
Other 7 - - - 7
Cash equivalents 311 9 - - 320
Other investments - 24 - - 24
Total $ 959 $ 477 $ - $ 76 $ 1,512
Liabilities:
Energy-related derivatives $ - $ 7 $ - $ - $ 7
Georgia Power
Assets:
Energy-related derivatives $ - $ 15 $ - $ - $ 15
Nuclear decommissioning trusts:(b)(c)
Domestic equity 319 1 - - 320
Foreign equity - 177 - - 177
U.S. Treasury and government agency
securities - 263 - - 263
Municipal bonds - 84 - - 84
Corporate bonds - 219 - - 219
Mortgage and asset backed securities - 54 - - 54
Other 21 7 - - 28
Total $ 340 $ 820 $ - $ - $ 1,160
Liabilities:
Energy-related derivatives $ - $ 13 $ - $ - $ 13
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Fair Value Measurements Using
Quoted Prices in Net Asset
Active Markets Value as a
for Identical Significant Other Significant Practical
Assets ObservableInputs Unobservable Inputs Expedient At December 31, 2020:
(Level 1) (Level 2) (Level 3) (NAV) Total
(in millions)
Mississippi Power
Assets:
Energy-related derivatives $ - $ 9 $ - $ - $ 9
Cash equivalents 21 - - - 21
Total $ 21 $ 9 $ - $ - $ 30
Liabilities:
Energy-related derivatives $ - $ 9 $ - $ - $ 9
Southern Power
Assets:
Energy-related derivatives $ - $ 2 $ - $ - $ 2
Foreign currency derivatives - 87 - - 87
Total $ - $ 89 $ - $ - $ 89
Liabilities:
Energy-related derivatives $ - $ 3 $ - $ - $ 3
Foreign currency derivatives - 23 - - 23
Contingent consideration - - 17 - 17
Total $ - $ 26 $ 17 $ - $ 43
Southern Company Gas
Assets:
Energy-related derivatives(a) $ 401 $ 233 $ 32 $ - $ 666
Non-qualified deferred compensation
trusts:
Domestic equity - 9 - - 9
Foreign equity - 3 - - 3
Pooled funds - fixed income - 17 - - 17
Cash equivalents 1 - - - 1
Total $ 402 $ 262 $ 32 $ - $ 696
Liabilities:
Energy-related derivatives(a)(b) $ 389 $ 172 $ 4 $ - $ 565
(a)Excludes $6 million associated with premiums and certain weather derivatives accounted for based on intrinsic value rather than fair value and cash collateral of $28 million.
(b)Excludes receivables related to investment income, pending investment sales, payables related to pending investment purchases, and currencies. See Note 6 under "Nuclear Decommissioning" for additional information.
(c)Includes investment securities pledged to creditors and collateral received and excludes payables related to the securities lending program. See Note 6 under "Nuclear Decommissioning" for additional information.
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Valuation Methodologies
The energy-related derivatives primarily consist of exchange-traded and
over-the-counter financial products for natural gas and physical power products,
including, from time to time, basis swaps. These are standard products used
within the energy industry and are valued using the market approach. The inputs
used are mainly from observable market sources, such as forward natural gas
prices, power prices, implied volatility, and overnight index swap interest
rates. Interest rate derivatives are also standard over-the-counter products
that are valued using observable market data and assumptions commonly used by
market participants. The fair value of interest rate derivatives reflects the
net present value of expected payments and receipts under the swap agreement
based on the market's expectation of future interest rates. Additional inputs to
the net present value calculation may include the contract terms, counterparty
credit risk, and occasionally, implied volatility of interest rate options. The
fair value of cross-currency swaps reflects the net present value of expected
payments and receipts under the swap agreement based on the market's expectation
of future foreign currency exchange rates. Additional inputs to the net present
value calculation may include the contract terms, counterparty credit risk, and
discount rates. The interest rate derivatives and cross-currency swaps are
categorized as Level 2 under Fair Value Measurements as these inputs are based
on observable data and valuations of similar instruments. See Note 14 for
additional information on how these derivatives are used.
For fair value measurements of the investments within the nuclear
decommissioning trusts and the non-qualified deferred compensation trusts,
external pricing vendors are designated for each asset class with each security
specifically assigned a primary pricing source. For investments held within
commingled funds, fair value is determined at the end of each business day
through the net asset value, which is established by obtaining the underlying
securities' individual prices from the primary pricing source. A market price
secured from the primary source vendor is then evaluated by management in its
valuation of the assets within the trusts. As a general approach, fixed income
market pricing vendors gather market data (including indices and market research
reports) and integrate relative credit information, observed market movements,
and sector news into proprietary pricing models, pricing systems, and
mathematical tools. Dealer quotes and other market information, including live
trading levels and pricing analysts' judgments, are also obtained when
available.
The NRC requires licensees of commissioned nuclear power reactors to establish a
plan for providing reasonable assurance of funds for future decommissioning. See
Note 6 under "Nuclear Decommissioning" for additional information.
Southern Power has contingent payment obligations related to certain
acquisitions whereby it is primarily obligated to make generation-based payments
to the seller, which commenced at the commercial operation of the respective
facility and continue through 2026. The obligations are categorized as Level 3
under Fair Value Measurements as the fair value is determined using significant
unobservable inputs for the forecasted facility generation in MW-hours, as well
as other inputs such as a fixed dollar amount per MW-hour, and a discount rate.
The fair value of contingent consideration reflects the net present value of
expected payments and any periodic change arising from forecasted generation is
expected to be immaterial.
Southern Power also has payment obligations through 2040 whereby it must
reimburse the transmission owners for interconnection facilities and network
upgrades constructed to support connection of a Southern Power generating
facility to the transmission system. The obligations are categorized as Level 2
under Fair Value Measurements as the fair value is determined using observable
inputs for the contracted amounts and reimbursement period, as well as a
discount rate. The fair value of the obligations reflects the net present value
of expected payments.
"Other investments" include investments traded in the open market that have
maturities greater than 90 days, which are categorized as Level 2 under Fair
Value Measurements and are comprised of corporate bonds, bank certificates of
deposit, treasury bonds, and/or agency bonds.
The fair value measurements of private equity investments held in Alabama
Power's nuclear decommissioning trusts that are calculated at net asset value
per share (or its equivalent) as a practical expedient totaled $150 million and
$76 million at December 31, 2021 and 2020, respectively. Unfunded commitments
related to the private equity investments totaled $69 million and $73 million at
December 31, 2021 and 2020, respectively. Private equity investments include
high-quality private equity funds across several market sectors and funds that
invest in real estate assets. Private equity funds do not have redemption
rights. Distributions from these funds will be received as the underlying
investments in the funds are liquidated.
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At December 31, 2021 and 2020, other financial instruments for which the carrying amount did not equal fair value were as follows:
Southern
Southern Company
Company(*) Alabama Power Georgia Power Mississippi Power Southern Power Gas(*)
(in billions)
At December 31, 2021:
Long-term debt, including
securities due within one year:
Carrying amount $ 52.1 $ 9.7 $ 13.6 $ 1.5 $ 3.7 $ 6.9
Fair value 57.1 10.9 15.1 1.6 4.1 7.8
At December 31, 2020:
Long-term debt, including
securities due within one year:
Carrying amount $ 48.3 $ 8.9 $ 12.8 $ 1.4 $ 3.7 $ 6.6
Fair value 56.3 10.7 15.2 1.6 4.2 8.0
(*)The long-term debt of Southern Company Gas is recorded at amortized cost,
including the fair value adjustments at the effective date of the 2016 merger
with Southern Company. Southern Company Gas amortizes the fair value adjustments
over the remaining lives of the respective bonds, the latest being through 2043.
The fair values are determined using Level 2 measurements and are based on quoted market prices for the same or similar issues or on the current rates available to the Registrants.
Commodity Contracts with Level 3 Valuation Inputs
Prior to July 1, 2021, Southern Company Gas had Level 3 physical natural gas
forward contracts related to Sequent. See Note 15 under "Southern Company Gas"
for information regarding the sale of Sequent. The following table provides a
reconciliation of Southern Company Gas' Level 3 contracts during 2021.
2021
(in millions)
Beginning balance $ 28
Instruments realized or otherwise settled during period
(6)
Changes in fair value (4)
Sale of Sequent (18)
Ending balance $ -
Changes in fair value of Level 3 instruments represent changes in gains and losses reported on Southern Company Gas' statements of income in natural gas revenues prior to the sale of Sequent.
14. DERIVATIVES
Southern Company, the traditional electric operating companies, Southern Power,
and Southern Company Gas are exposed to market risks, including commodity price
risk, interest rate risk, weather risk, and occasionally foreign currency
exchange rate risk. To manage the volatility attributable to these exposures,
each company nets its exposures, where possible, to take advantage of natural
offsets and enters into various derivative transactions for the remaining
exposures pursuant to each company's policies in areas such as counterparty
exposure and risk management practices. Prior to the sale of Sequent on July 1,
2021, Southern Company Gas' wholesale gas operations used various contracts in
its commercial activities that generally met the definition of derivatives. For
the traditional electric operating companies, Southern Power, and Southern
Company Gas' other businesses, each company's policy is that derivatives are to
be used primarily for hedging purposes and mandates strict adherence to all
applicable risk management policies. Derivative positions are monitored using
techniques including, but not limited to, market valuation, value at risk,
stress testing, and sensitivity analysis. Derivative instruments are recognized
at fair value in the balance sheets as either assets or liabilities and are
presented on a net basis. See Note 13 for additional fair value information. In
the statements of cash flows, any cash impacts of settled energy-related and
interest rate derivatives are recorded as operating activities. Any cash
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impacts of settled foreign currency derivatives are classified as operating or financing activities to correspond with the classification of the hedged interest or principal, respectively. See Note 1 under "Financial Instruments" for additional information. See Note 15 under "Southern Company Gas" for additional information regarding the sale of Sequent.
Energy-Related Derivatives
The traditional electric operating companies, Southern Power, and Southern Company Gas enter into energy-related derivatives to hedge exposures to electricity, natural gas, and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the traditional electric operating companies and the natural gas distribution utilities have limited exposure to market volatility in energy-related commodity prices. Each of the traditional electric operating companies and certain of the natural gas distribution utilities of Southern Company Gas manage fuel-hedging programs, implemented per the guidelines of their respective state PSCs or other applicable state regulatory agencies, through the use of financial derivative contracts, which are expected to continue to mitigate price volatility. The traditional electric operating companies (with respect to wholesale generating capacity) and Southern Power have limited exposure to market volatility in energy-related commodity prices because their long-term sales contracts shift substantially all fuel cost responsibility to the purchaser. However, the traditional electric operating companies and Southern Power may be exposed to market volatility in energy-related commodity prices to the extent any uncontracted capacity is used to sell electricity. Southern Company Gas retains exposure to price changes that can, in a volatile energy market, be material and can adversely affect its results of operations. Southern Company Gas also enters into weather derivative contracts as economic hedges in the event of warmer-than-normal weather. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non-exchange-traded options are accounted for using the intrinsic value method. Changes in the intrinsic value for non-exchange-traded contracts are reflected in operating revenues.
Energy-related derivative contracts are accounted for under one of three methods:
•Regulatory Hedges - Energy-related derivative contracts designated as
regulatory hedges relate primarily to the traditional electric operating
companies' and the natural gas distribution utilities' fuel-hedging programs,
where gains and losses are initially recorded as regulatory liabilities and
assets, respectively, and then are included in fuel expense as the underlying
fuel is used in operations and ultimately recovered through an approved cost
recovery mechanism.
•Cash Flow Hedges - Gains and losses on energy-related derivatives designated as
cash flow hedges (which are mainly used to hedge anticipated purchases and
sales) are initially deferred in AOCI before being recognized in the statements
of income in the same period and in the same income statement line item as the
earnings effect of the hedged transactions.
•Not Designated - Gains and losses on energy-related derivative contracts that
are not designated or fail to qualify as hedges are recognized in the statements
of income as incurred.
Some energy-related derivative contracts require physical delivery as opposed to
financial settlement, and this type of derivative is both common and prevalent
within the electric and natural gas industries. When an energy-related
derivative contract is settled physically, any cumulative unrealized gain or
loss is reversed and the contract price is recognized in the respective line
item representing the actual price of the underlying goods being delivered.
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At December 31, 2021, the net volume of energy-related derivative contracts for
natural gas positions, together with the longest hedge date over which the
respective entity is hedging its exposure to the variability in future cash
flows for forecasted transactions and the longest non-hedge date for derivatives
not designated as hedges, were as follows:
Net Longest Longest
Purchased Hedge Non-Hedge
mmBtu Date Date
(in millions)
Southern Company(*) 311 2030 2025
Alabama Power 74 2024 -
Georgia Power 89 2024 -
Mississippi Power 75 2025 -
Southern Power 5 2030 2022
Southern Company Gas(*) 68 2024 2025
(*)Southern Company Gas' derivative instruments include both long and short
natural gas positions. A long position is a contract to purchase natural gas and
a short position is a contract to sell natural gas. Southern Company Gas' volume
represents the net of long natural gas positions of 74 million mmBtu and short
natural gas positions of 6 million mmBtu at December 31, 2021, which is also
included in Southern Company's total volume. See Note 15 under "Southern Company
Gas" for information regarding the sale of Sequent.
In addition to the volumes discussed above, the traditional electric operating
companies and Southern Power enter into physical natural gas supply contracts
that provide the option to sell back excess natural gas due to operational
constraints. The maximum expected volume of natural gas subject to such a
feature is 26 million mmBtu for Southern Company, which includes 6 million mmBtu
for Alabama Power, 8 million mmBtu for Georgia Power, 4 million mmBtu for
Mississippi Power, and 8 million mmBtu for Southern Power.
For cash flow hedges of energy-related derivatives, the estimated pre-tax gains
(losses) expected to be reclassified from AOCI to earnings for the year ending
December 31, 2022 are immaterial for all Registrants.
Interest Rate Derivatives
Southern Company and certain subsidiaries may enter into interest rate
derivatives to hedge exposure to changes in interest rates. Derivatives related
to existing variable rate securities or forecasted transactions are accounted
for as cash flow hedges where the derivatives' fair value gains or losses are
recorded in OCI and are reclassified into earnings at the same time and
presented on the same income statement line item as the earnings effect of the
hedged transactions. Derivatives related to existing fixed rate securities are
accounted for as fair value hedges, where the derivatives' fair value gains or
losses and hedged items' fair value gains or losses are both recorded directly
to earnings on the same income statement line item. Fair value gains or losses
on derivatives that are not designated or fail to qualify as hedges are
recognized in the statements of income as incurred.
At December 31, 2021, the following interest rate derivatives were outstanding:
Interest Weighted Average Hedge Fair Value
Notional Rate Interest Maturity Gain (Loss)
Amount Received Rate Paid Date December 31, 2021
(in millions) (in millions)
Fair Value Hedges of Existing Debt
1-month LIBOR +
Southern Company parent $ 400 1.75% 0.68% March 2028 $ (5)
1-month LIBOR +
Southern Company parent 1,000 3.70% 2.36% April 2030 (6)
1-month LIBOR +
Southern Company Gas 500 1.75% 0.38% January 2031 1
Southern Company $ 1,900 $ (10)
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For cash flow hedge interest rate derivatives, the estimated pre-tax gains (losses) expected to be reclassified from AOCI to interest expense for the year ending December 31, 2022 total $(21) million for Southern Company and are immaterial for all other Registrants. Deferred gains and losses related to interest rate derivatives are expected to be amortized into earnings through 2051 for Southern Company, 2051 for Alabama Power, 2044 for Georgia Power, 2028 for Mississippi Power, and 2046 for Southern Company Gas.
Foreign Currency Derivatives
Southern Company and certain subsidiaries, including Southern Power, may enter
into foreign currency derivatives to hedge exposure to changes in foreign
currency exchange rates, such as that arising from the issuance of debt
denominated in a currency other than U.S. dollars. Derivatives related to
forecasted transactions are accounted for as cash flow hedges where the
derivatives' fair value gains or losses are recorded in OCI and are reclassified
into earnings at the same time and on the same income statement line as the
earnings effect of the hedged transactions, including foreign currency gains or
losses arising from changes in the U.S. currency exchange rates. Derivatives
related to existing fixed rate securities are accounted for as fair value
hedges, where the derivatives' fair value gains or losses and hedged items' fair
value gains or losses are both recorded directly to earnings on the same income
statement line item, including foreign currency gains or losses arising from
changes in the U.S. currency exchange rates. Southern Company has elected to
exclude the cross-currency basis spread from the assessment of effectiveness in
the fair value hedges of its foreign currency risk and record any difference
between the change in the fair value of the excluded components and the amounts
recognized in earnings as a component of OCI.
At December 31, 2021, the following foreign currency derivatives were
outstanding:
Fair Value
Hedge Gain (Loss)
Pay Notional Pay Rate Receive Notional Receive Rate Maturity Date December 31, 2021
(in millions) (in millions) (in millions)
Fair Value Hedges of Existing Debt
Southern Company parent $ 1,476 3.39% € 1,250 1.88% September 2027 $ (63)
Cash Flow Hedges of Existing Debt
Southern Power $ 677 2.95% € 600 1.00% June 2022 $ (5)
Southern Power 564 3.78% 500 1.85% June 2026 (10)
Southern Power total $ 1,241 € 1,100 $ (15)
Southern Company $ 2,717 € 2,350 $ (78)
The estimated pre-tax gains (losses) related to Southern Power's foreign currency derivatives accounted for as cash flow hedges expected to be reclassified from AOCI to earnings for the year ending December 31, 2022 are $(13) million.
Derivative Financial Statement Presentation and Amounts
Southern Company, the traditional electric operating companies, Southern Power,
and Southern Company Gas enter into derivative contracts that may contain
certain provisions that permit intra-contract netting of derivative receivables
and payables for routine billing and offsets related to events of default and
settlements. Southern Company and certain subsidiaries also utilize master
netting agreements to mitigate exposure to counterparty credit risk. These
agreements may contain provisions that permit netting across product lines and
against cash collateral. The fair value amounts of derivative assets and
liabilities on the balance sheets are presented net to the extent that there are
netting arrangements or similar agreements with the counterparties.
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At December 31, 2021 and 2020, the fair value of energy-related derivatives,
interest rate derivatives, and foreign currency derivatives was reflected in the
balance sheets as follows:
2021 2020Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities
(in millions)
Southern Company
Derivatives designated as hedging instruments for
regulatory purposes
Energy-related derivatives:
Assets from risk management activities/Other current
liabilities $ 129 $ 30 $ 24 $ 11
Other deferred charges and assets/Other deferred
credits and liabilities 72 6 18 19
Total derivatives designated as hedging instruments for regulatory purposes
$ 201 $ 36 $ 42 $ 30
Derivatives designated as hedging instruments in
cash flow and fair value hedges
Energy-related derivatives:
Assets from risk management activities/Other current
liabilities $ 7 $ 5 $ 3 $ 5
Other deferred charges and assets/Other deferred
credits and liabilities 1 - - -
Interest rate derivatives:
Assets from risk management activities/Other current 19 - 20 -
liabilities
Other deferred charges and assets/Other deferred credits and liabilities - 29 - -
Foreign currency derivatives: Assets from risk management activities/Other current liabilities
- 39 - 23
Other deferred charges and assets/Other deferred
credits and liabilities - 40 87 -
Total derivatives designated as hedging instruments in cash flow and fair value hedges
$ 27 $ 113 $ 110 $ 28
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current
liabilities $ 9 $ 4 $ 388 $ 331
Other deferred charges and assets/Other deferred
credits and liabilities 1 - 270 232
Total derivatives not designated as hedging
instruments $ 10 $ 4 $ 658 $ 563
Gross amounts recognized $ 238 $ 153 $ 810 $ 621
Gross amounts offset(a) $ (25) $ (28) $ (529) $ (557) Net amounts recognized in the Balance Sheets(b) $ 213 $ 125 $ 281 $ 64
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2021 2020
Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities
(in millions)
Alabama Power
Derivatives designated as hedging instruments for
regulatory purposes
Energy-related derivatives:
Other current assets/Other current liabilities $ 30 $ 9 $ 7 $ 2
Other deferred charges and assets/Other deferred
credits and liabilities 25 2 5 5
Total derivatives designated as hedging instruments
for regulatory purposes $ 55 $ 11 $ 12 $ 7
Gross amounts offset $ (5) $ (5) $ (7) $ (7)
Net amounts recognized in the Balance Sheets $ 50 $ 6 $ 5 $ -
Georgia Power Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 54 $ 6 $ 7 $ 5 Other deferred charges and assets/Other deferred credits and liabilities 21 2 8 8 Total derivatives designated as hedging instruments for regulatory purposes $ 75 $ 8 $ 15 $ 13 Gross amounts offset $ (8) $ (8) $ (12) $ (12) Net amounts recognized in the Balance Sheets $ 67 $
- $ 3 $ 1
Mississippi Power Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Other current assets/Other current liabilities $ 30 $ 3 $ 4 $ 3 Other deferred charges and assets/Other deferred credits and liabilities 26 2 5 6 Total derivatives designated as hedging instruments for regulatory purposes $ 56 $ 5 $ 9 $ 9 Gross amounts offset $ (4) $ (4) $ (7) $ (7) Net amounts recognized in the Balance Sheets $ 52 $
1 $ 2 $ 2
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2021 2020
Derivative Category and Balance Sheet Location Assets Liabilities Assets Liabilities
(in millions)
Southern Power
Derivatives designated as hedging instruments in
cash flow and fair value hedges
Energy-related derivatives:
Other current assets/Other current liabilities $ 2 $ - $ 2 $ 2
Other deferred charges and assets/Other deferred
credits and liabilities 1 - - -
Foreign currency derivatives:
Other current assets/Other current liabilities - 16 - 23
Other deferred charges and assets/Other deferred
credits and liabilities - - 87 -
Total derivatives designated as hedging instruments in cash flow and fair value hedges
$ 3 $ 16 $ 89 $ 25
Derivatives not designated as hedging instruments
Energy-related derivatives:
Other current assets/Other current liabilities $ 1 $ - $ - $ 1
Net amounts recognized in the Balance Sheets $ 4 $
16 $ 89 $ 26
Southern Company Gas Derivatives designated as hedging instruments for regulatory purposes Energy-related derivatives: Assets from risk management activities/Other current liabilities $ 15 $
12 $ 6 $ 1
Derivatives designated as hedging instruments in cash flow and fair value hedges Energy-related derivatives: Assets from risk management activities/Other current liabilities $ 5 $
5 $ 1 $ 3
Interest rate derivatives: Assets from risk management activities/Other current liabilities
6 - - -
Other deferred charges and assets/Other deferred
credits and liabilities - 6 - -
Total derivatives designated as hedging instruments in cash flow and fair value hedges
$ 11 $ 11 $ 1 $ 3
Derivatives not designated as hedging instruments
Energy-related derivatives:
Assets from risk management activities/Other current
liabilities $ 8 $ 4 $ 388 $ 330
Other deferred charges and assets/Other deferred
credits and liabilities 1 - 270 232
Total derivatives not designated as hedging
instruments $ 9 $ 4 $ 658 $ 562
Gross amounts recognized $ 35 $ 27 $ 665 $ 566
Gross amounts offset(a) $ (8) $ (11) $ (503) $ (531)
Net amounts recognized in the Balance Sheets (b) $ 27 $ 16 $ 162 $ 35
(a)Gross amounts offset include cash collateral held on deposit in broker margin accounts of $3 million and $28 million at December 31, 2021 and 2020, respectively.
(b)Net amounts of derivative instruments outstanding exclude immaterial premium and intrinsic value associated with weather derivatives for all periods presented.
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At December 31, 2021 and 2020, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
Regulatory Hedge Unrealized Gain (Loss) Recognized in the Balance Sheets
Derivative Category and Balance Sheet Southern Alabama Georgia Mississippi Southern
Location Company Power Power Power Company Gas
(in millions)
At December 31, 2021:
Energy-related derivatives:
Other regulatory assets, current $ (17) $ (6) $ - $ - $ (11)
Other regulatory liabilities, current 107 28 48 27 4 Other regulatory liabilities, deferred 65 22 19 24 - Total energy-related derivative gains (losses) $ 155 $ 44 $ 67 $ 51 $ (7) At December 31, 2020: Energy-related derivatives:
Other regulatory assets, deferred $ (2) $ - $
(1) $ (1) $ -
Other regulatory liabilities, current 12 5 2 1 4
Other regulatory liabilities, deferred 2 1 1 - -
Total energy-related derivative gains
(losses) $ 12 $ 6 $ 2 $ - $ 4
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For the years ended December 31, 2021, 2020, and 2019, the pre-tax effects of cash flow and fair value hedge accounting on AOCI for the applicable Registrants were as follows:
Gain (Loss) From Derivatives Recognized in OCI 2021 2020 2019
(in millions)
Southern Company
Cash flow hedges:
Energy-related derivatives $ 34 $ (8) $ (13)
Interest rate derivatives 5 (26) (57)
Foreign currency derivatives (103) 48 (84)
Fair value hedges(*):
Foreign currency derivatives (3) - -
Total $ (67) $ 14 $ (154)
Georgia Power
Cash flow hedges:
Interest rate derivatives $ - $ (3) $ (59)
Southern Power
Cash flow hedges:
Energy-related derivatives $ 12 $ (2) $ (4)
Foreign currency derivatives (103) 48 (84)
Total $ (91) $ 46 $ (88)
Southern Company Gas
Cash flow hedges:
Energy-related derivatives $ 22 $ (6) $ (9)
Interest rate derivatives - (23) 2
Total $ 22 $ (29) $ (7)
(*)Represents amounts excluded from the assessment of effectiveness for which the difference between changes in fair value and periodic amortization is recorded in OCI.
The pre-tax effects of interest rate derivatives designated as cash flow hedging instruments on AOCI were immaterial for the other Registrants for all years presented.
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The pre-tax effects of cash flow and fair value hedge accounting on income for the years ended December 31, 2021, 2020, and 2019 were as follows:
Location and Amount of Gain (Loss) Recognized in Income on Cash Flow and Fair Value Hedging Relationships
2021 2020 2019
(in millions)
Southern Company
Total cost of natural gas $ 1,619 $ 972 $ 1,319
Gain (loss) on energy-related cash flow hedges(a) 17 (8) (2)
Total depreciation and amortization 3,565 3,518 3,038
Gain (loss) on energy-related cash flow hedges(a) 9 (3) (6)
Total interest expense, net of amounts capitalized (1,837) (1,821) (1,736)
Gain (loss) on interest rate cash flow hedges(a) (27) (26) (20)
Gain (loss) on foreign currency cash flow hedges(a) (24) (23) (24)
Gain (loss) on interest rate fair value hedges(b) (30) 27 42
Total other income (expense), net 456 336 252
Gain (loss) on foreign currency cash flow hedges(a)(c) (104)
114 (24)
Gain (loss) on foreign currency fair value hedges (63) - -
Amount excluded from effectiveness testing recognized in earnings
3 - -
Southern Power
Total depreciation and amortization $ 517 $ 494 $ 479
Gain (loss) on energy-related cash flow hedges(a) 9 (3) (6)
Total interest expense, net of amounts capitalized (147) (151) (169)
Gain (loss) on foreign currency cash flow hedges(a) (24) (23) (24)
Total other income (expense), net 10 19 47
Gain (loss) on foreign currency cash flow hedges(a)(c) (104)
114 (24)
Southern Company Gas
Total cost of natural gas $ 1,619 $ 972 $ 1,319
Gain (loss) on energy-related cash flow hedges(a) 17 (8) (2)
(a)Reclassified from AOCI into earnings.
(b)For fair value hedges, changes in the fair value of the derivative contracts are generally equal to changes in the fair value of the underlying debt and have no material impact on income.
(c)The reclassification from AOCI into other income (expense), net completely offsets currency gains and losses arising from changes in the U.S. currency exchange rates used to record the euro-denominated notes.
The pre-tax effects of cash flow and fair value hedge accounting on income for
interest rate derivatives and energy-related derivatives were immaterial for the
other Registrants for all years presented.
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At December 31, 2021 and 2020, the following amounts were recorded on the balance sheets related to cumulative basis adjustments for fair value hedges:
Cumulative Amount of Fair Value Hedging
Carrying Amount of Adjustment included in Carrying Amount of
the Hedged Item the Hedged Item
Balance Sheet Location of Hedged At December 31, At December 31,
At December 31, Items 2021 2020
2021 At December 31, 2020
(in millions) (in millions)
Southern Company
Securities due within one year $ - $ (1,509) $ - $ (10)
Long-term debt (3,280) - 9 -
Southern Company Gas
Long-term debt $ (493) $ - $ 2 $ -
The pre-tax effects of energy-related derivatives not designated as hedging instruments on the statements of income of Southern Company and Southern Company Gas for the years ended December 31, 2021, 2020, and 2019 were as follows:
Gain (Loss)
Derivatives in Non-Designated
Hedging Relationships Statements of Income Location 2021 2020 2019
(in millions)
Energy-related derivatives Natural gas revenues(*) $ (117) $ 134 $ 223
Cost of natural gas (27) 15 10
Total derivatives in non-designated hedging relationships $ (144) $ 149 $ 233
(*) Excludes the impact of weather derivatives recorded in natural gas revenues of $9 million and $3 million for 2020 and 2019, respectively, as they are accounted for based on intrinsic value rather than fair value. There was no weather derivatives impact for 2021.
The pre-tax effects of energy-related derivatives not designated as hedging instruments were immaterial for all other Registrants for all years presented.
Contingent Features
Southern Company, the traditional electric operating companies, Southern Power,
and Southern Company Gas do not have any credit arrangements that would require
material changes in payment schedules or terminations as a result of a credit
rating downgrade. There are certain derivatives that could require collateral,
but not accelerated payment, in the event of various credit rating changes of
certain Southern Company subsidiaries. At December 31, 2021, the Registrants had
no collateral posted with derivative counterparties to satisfy these
arrangements.
For the applicable Registrants, the fair value of interest rate and
energy-related derivative liabilities with contingent features and the maximum
potential collateral requirements arising from the credit-risk-related
contingent features, at a rating below BBB- and/or Baa3, were immaterial at
December 31, 2021. The maximum potential collateral requirements arising from
the credit-risk-related contingent features for the traditional electric
operating companies and Southern Power include certain agreements that could
require collateral in the event that one or more Southern Company power pool
participants has a credit rating change to below investment grade. Following the
sale of Gulf Power to NextEra Energy, Gulf Power has continued participating in
the Southern Company power pool; however, on December 21, 2021, NextEra Energy
provided a 180-day notice of its intention to cease such participation.
Generally, collateral may be provided by a Southern Company guaranty, letter of
credit, or cash. If collateral is required, fair value amounts recognized for
the right to reclaim cash collateral or the obligation to return cash collateral
are not offset against fair value amounts recognized for derivatives executed
with the same counterparty.
Alabama Power and Southern Power maintain accounts with certain regional
transmission organizations to facilitate financial derivative transactions and
they may be required to post collateral based on the value of the positions in
these accounts and the associated margin requirements. At December 31, 2021,
cash collateral posted in these accounts was immaterial. Southern Company Gas
maintains accounts with brokers or the clearing houses of certain exchanges to
facilitate financial derivative
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transactions. Based on the value of the positions in these accounts and the associated margin requirements, Southern Company Gas may be required to deposit cash into these accounts. At December 31, 2021, cash collateral held on deposit in broker margin accounts was immaterial. The Registrants are exposed to losses related to financial instruments in the event of counterparties' nonperformance. The Registrants only enter into agreements and material transactions with counterparties that have investment grade credit ratings by Moody's and S&P or with counterparties who have posted collateral to cover potential credit exposure. The Registrants have also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate their exposure to counterparty credit risk. Southern Company Gas uses established credit policies to determine and monitor the creditworthiness of counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade financial institution, but may also include cash or U.S. government securities held by a trustee. Prior to entering a physical transaction, Southern Company Gas assigns its counterparties an internal credit rating and credit limit based on the counterparties' Moody's, S&P, and Fitch ratings, commercially available credit reports, and audited financial statements. Southern Company Gas may require counterparties to pledge additional collateral when deemed necessary. Southern Company Gas utilizes netting agreements whenever possible to mitigate exposure to counterparty credit risk. Netting agreements enable Southern Company Gas to net certain assets and liabilities by counterparty across product lines and against cash collateral, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, counterparties are settled net, they are recorded on a gross basis on the balance sheet as energy marketing receivables and energy marketing payables.
The Registrants do not anticipate a material adverse effect on their respective financial statements as a result of counterparty nonperformance.
15. ACQUISITIONS AND DISPOSITIONS
None of the dispositions discussed herein, both individually and combined, represented a strategic shift in operations for the applicable Registrants that has, or is expected to have, a major effect on its operations and financial results; therefore, none of the assets related to the sales have been classified as discontinued operations for any of the periods presented.
Southern Company
In January 2019, Southern Company completed the sale of all of the capital stock of Gulf Power to a wholly-owned subsidiary of NextEra Energy, for an aggregate cash purchase price of approximately $5.8 billion (less $1.3 billion of indebtedness assumed), including the final working capital adjustments. The gain associated with the sale of Gulf Power totaled $2.6 billion pre-tax ($1.4 billion after tax). In July 2019, PowerSecure completed the sale of its utility infrastructure services business for approximately $65 million, including the final working capital adjustments. In contemplation of this sale, a goodwill impairment charge of $32 million was recorded in the second quarter 2019. In December 2019, PowerSecure completed the sale of its lighting business for approximately $9 million, which included cash of $4 million and a note receivable from the buyer of $5 million. In contemplation of this sale, an impairment charge of $18 million was recorded in the third quarter 2019 related to goodwill, identifiable intangibles, and other assets.
In December 2019, Southern Company completed the sale of one of its leveraged lease investments for an aggregate cash purchase price of approximately $20 million. The sale resulted in an immaterial gain.
In connection with the annual impairment analysis of a leveraged lease
investment during the fourth quarter 2020, Southern Company management concluded
that the estimated residual value of the generation assets should be reduced due
to significant uncertainty as to whether the related natural gas generation
assets would continue to operate at the end of the lease term in 2040 and
recorded a $34 million ($17 million after tax) impairment charge. Also during
the fourth quarter 2020, Southern Company management initiated steps to sell the
investment and reclassified it as held for sale at December 31, 2020. In the
fourth quarter 2020 and the second quarter 2021, additional charges of
$18 million ($14 million after tax) and $7 million ($6 million after tax),
respectively, were recorded to further reduce the investment to its estimated
fair value, less costs to sell. On October 29, 2021, Southern Company completed
the sale to the lessee for $45 million. No gain or loss was recognized on the
sale; however, it did result in the recognition of approximately $16 million of
additional tax benefits.
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On December 13, 2021, Southern Company completed the termination of its leasehold interest in assets associated with its two international leveraged lease projects and received cash proceeds of approximately $673 million after the accelerated exercise of the lessee's purchase options. The pre-tax gain associated with the transaction was approximately $93 million ($99 million gain after tax). Alabama Power In August 2020, Alabama Power completed its acquisition of the Central Alabama Generating Station, an approximately 885-MW combined cycle generation facility in Autauga County, Alabama. The total purchase price was $461 million, of which $452 million was related to net assets recorded within property, plant, and equipment on the balance sheet and the remainder primarily related to inventory, current receivables, and accounts payable. Alabama Power assumed an existing power sales agreement under which the full output of the generating facility remains committed to another third party for its remaining term of approximately three years. During the remaining term, the estimated revenues from the power sales agreement are expected to offset the associated costs of operation. See Notes 2 and 9 under "Alabama Power" and "Lessor," respectively, for additional information. On September 23, 2021, Alabama Power entered into an agreement to acquire all of the equity interests in Calhoun Power Company, LLC, which owns and operates the Calhoun Generating Station. See Note 2 under "Alabama Power - Certificates of Convenience and Necessity" for additional information.
Southern Power
Southern Power's acquisition-related costs for the projects discussed under "Asset Acquisitions" and "Construction Projects" below were expensed as incurred and were not material for any of the years presented.
Asset Acquisitions
Southern
Power
Project Approximate Nameplate Ownership PPA
Facility Resource Seller Capacity (MW) Location Percentage COD Contract Period
Asset Acquisitions During 2021
25 years
Invenergy Renewables and
Deuel Harvest(a) Wind LLC 300 Deuel County, SD 100% of Class B February 2021 15 years
Asset Acquisitions During 2020
Invenergy Renewables May
Beech Ridge II Wind LLC 56 Greenbrier County, WV 100% of Class A(b) 2020 12 years
Asset Acquisitions During 2019
DSGP(c) Fuel Cell Bloom Energy 28 Delaware 100% of Class B N/A(d) 15 years(e)
(a)On March 26, 2021, Southern Power acquired a controlling interest in the
project from Invenergy Renewables LLC and, on March 30, 2021, Southern Power
completed a tax equity transaction whereby it sold the Class A membership
interests in the project. Southern Power consolidates the project's operating
results in its financial statements and the tax equity partner and Invenergy
Renewables LLC each own a noncontrolling interest.
(b)In May 2020, Southern Power purchased a controlling interest and now consolidates the project's operating results in its financial statements. The Class B member owns the noncontrolling interest.
(c)During 2019, Southern Power purchased a controlling interest and now consolidates the project's operating results in its financial statements. The Class A and Class C members each own a noncontrolling interest. Southern Power records net income attributable to noncontrolling interests for approximately 10 MWs of the facility. (d)Southern Power's 18-MW share of the facility was repowered between June and August 2019. In December 2019, a Class C member joined the existing partnership between the Class A member and Southern Power and made an investment to repower the remaining 10 MWs.
(e)Remaining PPA contract period at the time of acquisition.
Construction Projects
During 2021, Southern Power completed construction of and placed in service the
Glass Sands wind facility, 73 MWs of the Garland battery energy storage
facility, and 32 MWs of the Tranquillity battery energy storage facility. At
December 31, 2021, total costs of construction incurred for these projects were
$383 million. Southern Power continues construction of the remainder of the
Garland and Tranquillity battery energy storage facilities and expects total
aggregate construction costs to be between $230 million and $270 million. The
ultimate outcome of these matters cannot be determined at this time. See Note 9
under "Lessor" for additional information.
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Project Approximate Nameplate Actual/Expected
Facility Resource Capacity (MW) Location COD PPA Contract Period
Projects Under Construction at December 31, 2021
Tranquillity Solar Storage(a) Battery energy 72 Fresno County, CA November 2021 and 20 years
storage system first quarter 2022(b)
Garland Solar Storage(a) Battery energy 88 Kern County, CA September 2021, 20 years
storage system December 2021,
and first quarter 2022(c)
Projects Completed During 2021
Glass Sands(d) Wind 118 Murray County, OK November 2021 12 years
Projects Completed During 2020
Skookumchuck(e) Wind 136 Lewis and Thurston November 2020 20 years
Counties, WA
Reading(f) Wind 200 Osage and Lyon May 2020 12 years
Counties, KS
(a)In December 2020, Southern Power restructured its ownership of the project,
while retaining the controlling interests, by contributing the Class A
membership interests to an existing partnership and selling 100% of the Class B
membership interests. During the third quarter 2021, Southern Power further
restructured its ownership in the battery energy storage projects and completed
tax equity transactions whereby it sold the Class A membership interests in the
projects. Southern Power consolidates each project's operating results in its
financial statements and the tax equity partner and two other partners each own
a noncontrolling interest.
(b)The facility has a total capacity of 72 MWs, of which 32 MWs were placed in service in November 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.
(c)The facility has a total capacity of 88 MWs, of which 73 MWs were placed in service during 2021 and the remaining MWs are expected to be placed in service later in the first quarter 2022.
(d)In December 2020, Southern Power purchased 100% of the membership interests of the Glass Sands facility.
(e)In 2019, Southern Power purchased 100% of the membership interests of the Skookumchuck facility pursuant to a joint development arrangement. In November 2020, Southern Power completed a tax equity transaction whereby it received $121 million, resulting in 100% ownership of the Class B membership interests. Southern Power subsequently sold a noncontrolling interest in the Class B membership interests and now retains the controlling ownership interest in the facility.
(f)In 2018, Southern Power purchased 100% of the membership interests of the Reading facility pursuant to a joint development arrangement. In June 2020, Southern Power completed a tax equity transaction whereby it received $156 million and owns 100% of the Class B membership interests.
Development Projects
Southern Power continues to evaluate and refine the deployment of the remaining wind turbine equipment purchased in 2016 and 2017 for development and construction projects. Wind projects utilizing equipment purchased in 2016 and 2017, and reaching commercial operation by the end of 2021 and 2022, are expected to qualify for 100% and 80% PTCs, respectively. The significant majority of this equipment either has been deployed to projects that have been completed, are under construction, or are probable of completion, or has been sold to third parties. Gains on wind turbine equipment contributed to various equity method investments totaled approximately $37 million in 2021. Gains on wind turbine equipment sales were immaterial in 2020 and totaled approximately $17 million in 2019.
Sales of Natural Gas and Biomass Plants
In June 2019, Southern Power completed the sale of its equity interests in Plant
Nacogdoches, a 115-MW biomass facility located in Nacogdoches County, Texas, to
Austin Energy, for a purchase price of approximately $461 million, including
final working capital adjustments. Southern Power recorded a gain of $23 million
($88 million after tax) on the sale.
In January 2020, Southern Power completed the sale of its equity interests in
Plant Mankato (including the 385-MW expansion unit completed in May 2019) to a
subsidiary of Xcel Energy Inc. for a purchase price of approximately $663
million, including final working capital adjustments. The sale resulted in a
gain of approximately $39 million ($23 million after tax).
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Plant Nacogdoches and Plant Mankato represented individually significant components of Southern Power. Pre-tax income for these components for the years ended December 31, 2020 and 2019 are presented below:
2020 2019
(in millions)
Earnings before income taxes:
Plant Nacogdoches(a)(b) N/A $ 13
Plant Mankato(a)(c) $ 2 $ 29
(a)Earnings before income taxes reflect the cessation of depreciation and amortization on the long-lived assets being sold upon classification as held for sale (November 2018 for Plant Mankato and April 2019 for Plant Nacogdoches).
(b)2019 amount represents the period from January 1, 2019 to June 13, 2019 (the divestiture date).
(c)2020 amount represents the period from January 1, 2020 to January 17, 2020 (the divestiture date).
Southern Company Gas Sale of Sequent
On July 1, 2021, Southern Company Gas affiliates completed the sale of Sequent to Williams Field Services Group for a total cash purchase price of $159 million, including final working capital adjustments. The pre-tax gain associated with the transaction was approximately $121 million ($92 million after tax). As a result of the sale, changes in state apportionment rates resulted in $85 million of additional tax expense.
Prior to the sale, Southern Company Gas had existing agreements in place in which it guaranteed the payment performance of Sequent. Southern Company Gas will continue to guarantee Sequent's payment performance for a period of time as Williams Field Services Group obtains releases from these obligations. At December 31, 2021, the remaining obligations subject to the payment performance guarantee were immaterial. Changes in the price of natural gas, market conditions, and the number of open contracts may change the amount that Southern Company Gas is required to guarantee for Sequent each month.
Sale of Pivotal LNG and Atlantic Coast Pipeline
In March 2020, Southern Company Gas completed the sale of its interests in Pivotal LNG and Atlantic Coast Pipeline to Dominion Modular LNG Holdings, Inc. and Dominion Atlantic Coast Pipeline, LLC, respectively, with aggregate proceeds of $178 million, including final working capital adjustments. The loss associated with the transactions was immaterial. During 2019, based on the terms of these transactions, Southern Company Gas recorded an asset impairment charge, exclusive of the contingent payments, for Pivotal LNG of approximately $24 million ($17 million after tax) as of December 31, 2019. In connection with the sale, Southern Company Gas was entitled to two $5 million payments contingent upon Dominion Modular LNG Holdings, Inc. meeting certain milestones related to Pivotal LNG. Southern Company Gas received the first payment on April 22, 2021 and expects to receive the second payment in March 2022.
Sale of Natural Gas Storage Facility
In December 2020, Southern Company Gas completed the sale of Jefferson Island to EnLink Midstream, LLC for a total purchase price of $33 million, including estimated working capital adjustments. The gain associated with the sale totaled $22 million pre-tax ($16 million after tax). In 2019, Southern Company Gas recorded a pre-tax impairment charge of $91 million ($69 million after-tax) related to Jefferson Island.
Sale of Triton
In May 2019, Southern Company Gas sold its investment in Triton, a cargo
container leasing company that was aggregated into Southern Company Gas' all
other segment. This disposition resulted in a pre-tax loss of $6 million and a
net after-tax gain of $7 million as a result of reversing a $13 million federal
income tax valuation allowance.
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16. SEGMENT AND RELATED INFORMATION
Southern Company
Southern Company's reportable business segments are the sale of electricity by
the traditional electric operating companies, the sale of electricity in the
competitive wholesale market by Southern Power, and the sale of natural gas and
other complementary products and services by Southern Company Gas. Revenues from
sales by Southern Power to the traditional electric operating companies were
$515 million, $364 million, and $398 million in 2021, 2020, and 2019,
respectively. Revenues from sales of natural gas from Southern Company Gas to
the traditional electric operating companies and Southern Power were immaterial
and $18 million, respectively, in 2021 (which represented sales from Sequent
through June 30, 2021), immaterial and $26 million, respectively, in 2020, and
$14 million and $64 million, respectively, in 2019. The "All Other" column
includes the Southern Company parent entity, which does not allocate operating
expenses to business segments. Also, this category includes segments below the
quantitative threshold for separate disclosure. These segments include providing
distributed energy and resilience solutions and deploying microgrids for
commercial, industrial, governmental, and utility customers, as well as
investments in telecommunications and leveraged lease projects. All other
inter-segment revenues are not material.
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Financial data for business segments and products and services for the years ended December 31, 2021, 2020, and 2019 was as follows:
Electric Utilities
Traditional
Electric
Operating Southern Southern All
Companies Power Eliminations Total Company Gas Other Eliminations Consolidated
(in millions)
2021
Operating revenues $ 16,614 $ 2,216 $ (530) $ 18,300 $ 4,380 $ 582 $ (149) $ 23,113
Depreciation and amortization 2,436 517 - 2,953 536 76 - 3,565
Interest income 20 1 - 21 - 4 (3) 22
Earnings from equity method investments 1 - - 1 50 24 1 76
Interest expense 821 147 - 968 238 631 - 1,837
Income taxes (benefit) 232 (13) - 219 275 (227) - 267
Segment net income (loss)(a)(b)(c)(d)(e)(f) 1,981 266 - 2,247 539 (384) (9) 2,393
Goodwill - 2 - 2 5,015 263 - 5,280
Assets held for sale 39 - - 39 - 3 - 42
Total assets 89,051 13,390 (667) 101,774 23,560 2,975 (775) 127,534
2020
Operating revenues $ 15,135 $ 1,733 $ (371) $ 16,497 $ 3,434 $ 596 $ (152) $ 20,375
Depreciation and amortization 2,447 494 - 2,941 500 77 - 3,518
Interest income 26 4 - 30 5 6 (4) 37
Earnings from equity method investments - - - - 141 12 - 153
Interest expense 825 151 - 976 231 614 - 1,821
Income taxes (benefit) 514 3 - 517 173 (297) - 393
Segment net income (loss)(a)(b)(f)(g)(h) 2,877 238 - 3,115 590 (592) 6 3,119
Goodwill - 2 - 2 5,015 263 - 5,280
Assets held for sale 5 - - 5 - 55 - 60
Total assets 85,486 13,235 (680) 98,041 22,630 3,168 (904) 122,935
2019
Operating revenues $ 15,569 $ 1,938 $ (412) $ 17,095 $ 3,792 $ 690 $ (158) $ 21,419
Depreciation and amortization 1,993 479 - 2,472 487 79 - 3,038
Interest income 38 9 - 47 3 16 (6) 60
Earnings from equity method investments 2 3 - 5 157 - - 162
Interest expense 818 169 - 987 232 517 - 1,736
Income taxes (benefit) 764 (56) - 708 130 960 - 1,798
Segment net income (loss)(a)(f)(i)(j)(k) 2,929 339 - 3,268 585 908 (22) 4,739
Goodwill - 2 - 2 5,015 263 - 5,280
Assets held for sale - 618 - 618 171 - - 789
Total assets 81,063 14,300 (713) 94,650 21,687 3,511 (1,148) 118,700
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(a)Attributable to Southern Company.
(b)For the traditional electric operating companies, includes pre-tax charges at Georgia Power for estimated losses associated with the construction of Plant Vogtle Units 3 and 4 of $1.7 billion ($1.3 billion after tax) in 2021 and $325 million ($242 million after tax) in 2020. See Note 2 under "Georgia Power - Nuclear Construction" for additional information. (c)For Southern Power, includes gains on wind turbine equipment contributed to various equity method investments totaling approximately $37 million pre-tax ($28 million after tax). See Notes 7 and 15 under "Southern Power" for additional information. (d)For Southern Company Gas, includes a pre-tax gain of $121 million ($92 million after tax) related to its sale of Sequent, as well as the resulting $85 million of additional tax expense due to changes in state apportionment rates, and pre-tax impairment charges totaling $84 million ($67 million after tax) related to its equity method investment in the PennEast Pipeline project. See Notes 7 and 15 under "Southern Company Gas" for additional information.
(e)For the "All Other" column, includes a pre-tax gain of $93 million ($99 million gain after tax) associated with the termination of two leveraged leases projects. See Note 15 under "Southern Company" for additional information.
(f)For the "All Other" column, includes pre-tax impairment charges totaling $7 million ($6 million after tax) in 2021, $206 million ($105 million after tax) in 2020, and $17 million ($13 million after tax) in 2019 related to leveraged lease investments. See Notes 9 and 15 under "Southern Company Leveraged Lease" and "Southern Company," respectively, for additional information. (g)For Southern Power, includes a $39 million pre-tax gain ($23 million gain after tax) on the sale of Plant Mankato. See Note 15 under "Southern Power" for additional information. (h)For Southern Company Gas, includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island. See Note 15 under "Southern Company Gas" for additional information. (i)For Southern Power, includes a $23 million pre-tax gain ($88 million gain after tax) on the sale of Plant Nacogdoches. See Note 15 under "Southern Power" for additional information.
(j)For Southern Company Gas, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.
(k)For the "All Other" column, includes the pre-tax gain associated with the sale of Gulf Power of $2.6 billion ($1.4 billion after tax) and the pre-tax loss, including related impairment charges, on the sales of certain PowerSecure business units totaling $58 million ($52 million after tax). See Note 15 under "Southern Company" for additional information.
Products and Services
Electric Utilities' Revenues
Year Retail Wholesale Other Total
(in millions)
2021 $ 14,852 $ 2,455 $ 993 $ 18,300
2020 13,643 1,945 909 16,497
2019 14,084 2,152 859 17,095
Southern Company Gas' Revenues
Gas Gas
Distribution Marketing
Year Operations Services All Other Total
(in millions)
2021 $ 3,656 $ 475 $ 249 $ 4,380
2020 2,902 408 124 3,434
2019 3,001 456 335 3,792
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued) Southern Company and Subsidiary Companies 2021 Annual Report
Southern Company Gas
Southern Company Gas manages its business through three reportable segments - gas distribution operations, gas pipeline investments, and gas marketing services. Prior to the sale of Sequent on July 1, 2021, Southern Company Gas' reportable segments also included wholesale gas services. The non-reportable segments are combined and presented as all other. See Note 15 under "Southern Company Gas" for additional information on the disposition activities described herein. Gas distribution operations is the largest component of Southern Company Gas' business and includes natural gas local distribution utilities that construct, manage, and maintain intrastate natural gas pipelines and gas distribution facilities in four states. Gas pipeline investments consists of joint ventures in natural gas pipeline investments including a 50% interest in SNG and a 50% joint ownership interest in the Dalton Pipeline. These natural gas pipelines enable the provision of diverse sources of natural gas supplies to the customers of Southern Company Gas. Gas pipeline investments also includes a 20% ownership interest in the PennEast Pipeline project, which was cancelled in September 2021, and through its March 24, 2020 sale, included a 5% ownership interest in the Atlantic Coast Pipeline construction project. See Notes 5 and 7 for additional information.
Through July 1, 2021, wholesale gas services provided natural gas asset management and/or related logistics services for each of Southern Company Gas' utilities except Nicor Gas as well as for non-affiliated companies. Additionally, wholesale gas services engaged in natural gas storage and gas pipeline arbitrage and related activities.
Gas marketing services provides natural gas marketing to end-use customers primarily in Georgia and Illinois through SouthStar.
The all other column includes segments and subsidiaries that fall below the quantitative threshold for separate disclosure, including storage and fuels operations. The all other column included Jefferson Island through its sale on December 1, 2020, Pivotal LNG through its sale on March 24, 2020, and the investment in Triton through its sale on May 29, 2019.
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COMBINED NOTES TO FINANCIAL STATEMENTS (continued) Southern Company and Subsidiary Companies 2021 Annual Report
Financial data for business segments for the years ended December 31, 2021, 2020, and 2019 was as follows:
Gas Distribution Gas Pipeline Wholesale Gas Gas Marketing
Operations Investments Services(a) Services Total All Other Eliminations Consolidated
(in millions)
2021
Operating revenues $ 3,679 $ 32 $ 188 $ 475 $ 4,374 $ 38 $ (32) $ 4,380
Depreciation and amortization 482 5 - 18 505 31 - 536
Operating income (loss) 708 21 241 125 1,095 (40) - 1,055
Earnings from equity method investments - 50 - - 50 - - 50
Interest expense 207 25 2 3 237 1 - 238
Income taxes (benefit) 120 27 32 34 213 62 - 275
Segment net income (loss)(b)(c)(d) 412 19 107 88 626 (87) - 539
Total assets 20,917 1,467 31 1,556 23,971 12,114 (12,525) 23,560
2020
Operating revenues $ 2,952 $ 32 $ 74 $ 408 $ 3,466 $ 36 $ (68) $ 3,434
Depreciation and amortization 442 5 1 22 470 30 - 500
Operating income (loss) 655 20 20 119 814 (7) 5 812
Earnings from equity method investments - 141 - - 141 - - 141
Interest expense 192 29 4 3 228 3 - 231
Income taxes (benefit) 114 33 3 28 178 (5) - 173
Segment net income (loss)(e) 390 99 14 89 592 (2) - 590
Total assets 19,090 1,597 850 1,503 23,040 11,336 (11,746) 22,630
2019
Operating revenues $ 3,028 $ 32 $ 294 $ 456 $ 3,810 $ 44 $ (62) $ 3,792
Depreciation and amortization 422 5 1 26 454 33 - 487
Operating income (loss) 573 20 219 112 924 (154) - 770
Earnings from equity method investments - 162 - - 162 (5) - 157
Interest expense 187 30 5 3 225 7 - 232
Income taxes (benefit) 63 58 52 27 200 (70) - 130
Segment net income (loss)(f) 337 94 163 83 677 (92) - 585
Total assets 18,204 1,678 850 1,496 22,228 10,759 (11,300) 21,687
(a)The revenues for wholesale gas services are netted with costs associated with its energy and risk management activities. A reconciliation of operating revenues and intercompany revenues is shown in the following table.
Third Party Gross Intercompany Total Gross Less Gross Gas Operating
Revenues Revenues Revenues Costs Revenues
(in millions)
2021 $ 3,881 $ 90 $ 3,971 $ 3,783 $ 188
2020 4,544 115 4,659 4,585 74
2019 5,703 275 5,978 5,684 294
(b)For gas pipeline investments, includes pre-tax impairment charges totaling
$84 million ($67 million after tax) related to the equity method investment in
the PennEast Pipeline project. See Note 7 under "Southern Company Gas" for
additional information.
(c)For wholesale gas services, includes a pre-tax gain of $121 million ($92 million after tax) related to the sale of Sequent.
(d)For the "All Other" column, includes $85 million of additional tax expense due to changes in state apportionment rates as a result of the sale of Sequent.
(e)For the "All Other" column includes a $22 million pre-tax gain ($16 million gain after tax) on the sale of Jefferson Island.
(f)For the "All Other" column, includes pre-tax impairment charges totaling $115 million ($86 million after tax). See Note 15 under "Southern Company Gas" for additional information.
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