PACIFICORP The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Item 8 of this Form 10-K. The Company's actual results in the future could differ significantly from the historical results. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MES, corporate functions and intersegment eliminations.
Results of Operations
Overview
Operating revenue and earnings on common shares for the Company's reportable segments for the years endedDecember 31 are summarized as follows (in millions): 2022 2021 Change 2021 2020 Change Operating revenue: PacifiCorp$ 5,679 $ 5,296 $ 383 7 %$ 5,296 $ 5,341 $ (45) (1) % MidAmerican Funding 4,025 3,547 478 13 3,547 2,728 819 30 NV Energy 3,824 3,107 717 23 3,107 2,854 253 9 Northern Powergrid 1,365 1,188 177 15 1,188 1,022 166 16 BHE Pipeline Group 3,844 3,544 300 8 3,544 1,578 1,966 * BHE Transmission 732 731 1 - 731 659 72 11 BHE Renewables 994 981 13 1 981 936 45 5 HomeServices 5,268 6,215 (947) (15) 6,215 5,396 819 15 BHE and Other 606 541 65 12 541 438 103 24 Total operating revenue$ 26,337 $ 25,150 $ 1,187 5 %$ 25,150 $ 20,952 $ 4,198 20 % Earnings on common shares: PacifiCorp$ 921 $ 889 $ 32 4 %$ 889 $ 741 $ 148 20 % MidAmerican Funding 947 883 64 7 883 818 65 8 NV Energy 427 439 (12) (3) 439 410 29 7 Northern Powergrid 385 247 138 56 247 201 46 23 BHE Pipeline Group 1,040 807 233 29 807 528 279 53 BHE Transmission 247 247 - - 247 231 16 7 BHE Renewables(1) 625 451 174 39 451 521 (70) (13) HomeServices 100 387 (287) (74) 387 375 12 3 BHE and Other (2,017) 1,319 (3,336) * 1,319 3,092 (1,773) (57) Total earnings on common shares$ 2,675 $ 5,669 $ (2,994) (53) %$ 5,669 $ 6,917 $ (1,248) (18) %
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful.
Earnings on common shares decreased$2,994 million for 2022 compared to 2021. Included in these results was a pre-tax loss in 2022 of$1,950 million ($1,540 million after-tax) compared to a pre-tax gain in 2021 of$1,796 million ($1,777 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2022 was$4,215 million , an increase of$323 million , or 8%, compared to adjusted earnings on common shares in 2021 of$3,892 million . 89 --------------------------------------------------------------------------------
The decrease in net income attributable to BHE shareholders for 2022 compared to 2021 was primarily due to:
•The Utilities' earnings increased$84 million reflecting higher electric utility margin and favorable income tax expense, primarily from higher PTCs recognized of$157 million , partially offset by higher operations and maintenance expense and higher depreciation and amortization expense. Electric retail customer volumes increased 2.4% for 2022 compared to 2021, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather; •Northern Powergrid's earnings increased$138 million for 2022 compared to 2021, primarily due to a deferred income tax charge of$109 million related to aJune 2021 enacted increase in theUnited Kingdom corporate income tax rate from 19% to 25% effectiveApril 1, 2023 and favorable earnings from new gas and solar projects, partially offset by$41 million from the strongerU.S. dollar; •BHE Pipeline Group's earnings increased$233 million due to higher earnings at BHE GT&S from the impacts of the EGTS general rate case, favorable income tax adjustments, lower operations and maintenance expense and higher margin from non-regulated activities; •BHE Renewables' earnings increased$174 million , primarily due to higher operating revenue from owned renewable energy projects and higher earnings from tax equity investments, mainly due to the unfavorable impacts from theFebruary 2021 polar vortex weather event; •HomeServices' earnings decreased$287 million , reflecting lower earnings from brokerage and settlement services largely attributable to a decrease in closed units at existing companies and lower earnings from mortgage services mainly from a decrease in funded volumes; and •BHE and Other's earnings decreased$3,336 million , primarily due to the$3,317 million unfavorable comparative change related to the Company's investment in BYD Company Limited. Earnings on common shares decreased$1,248 million for 2021 compared to 2020. Included in these results was a pre-tax gain in 2021 of$1,796 million ($1,777 million after-tax) compared to a pre-tax gain in 2020 of$4,774 million ($3,470 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares in 2021 was$3,892 million , an increase of$445 million , or 13%, compared to adjusted earnings on common shares in 2020 of$3,447 million .
The decrease in net income attributable to BHE shareholders for 2021 compared to 2020 was primarily due to:
•The Utilities' earnings increased$242 million reflecting higher electric utility margin, favorable income tax expense, from higher PTCs recognized of$139 million and the impacts of ratemaking, and lower operations and maintenance expense, partially offset by higher depreciation and amortization expense. Electric retail customer volumes increased 3.8% for 2021 compared to 2020, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather; •Northern Powergrid's earnings increased$46 million , primarily due to higher distribution performance, lower write-offs of gas exploration costs and$16 million from the weakerU.S. dollar, partially offset by the comparative unfavorable impact of deferred income tax charges ($109 million in second quarter 2021 and$35 million in third quarter 2020) related to enacted increases in theUnited Kingdom corporate income tax rate;
•BHE Pipeline Group's earnings increased
•BHE Renewables' earnings decreased$70 million , primarily due to lower tax equity investment earnings from theFebruary 2021 polar vortex weather event, partially offset by earnings from tax equity investment projects reaching commercial operation and higher operating performance from owned renewable energy projects; and •BHE and Other's earnings decreased$1,773 million , primarily due to the$1,693 million unfavorable comparative change related to the Company's investment in BYD Company Limited and$95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued inOctober 2020 , partially offset by favorable comparative consolidated state income tax benefits. 90 --------------------------------------------------------------------------------
Reportable Segment Results
Operating revenue increased$383 million for 2022 compared to 2021, primarily due to higher retail revenue of$263 million and higher wholesale and other revenue of$120 million , largely from higher average wholesale prices. Retail revenue increased primarily due to price impacts of$166 million from higher average retail rates largely due to product mix and tariff changes and$97 million from higher retail volumes. Retail customer volumes increased 1.6%, primarily due to the favorable impact of weather and an increase in the average number of customers, partially offset by lower customer usage. Earnings increased$32 million for 2022 compared to 2021, primarily due to higher utility margin of$235 million and higher allowances for equity and borrowed funds used during construction of$28 million , partially offset by higher operations and maintenance expense of$196 million , higher depreciation and amortization expense of$32 million , mainly from additional assets placed in-service, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and an unfavorable income tax benefit. Utility margin increased primarily due to favorable deferred net power costs, higher retail rates and volumes and higher average wholesale prices, partially offset by higher purchased power and thermal generation costs. Operations and maintenance expense increased mainly due to an increase in loss accruals and other costs associated with theSeptember 2020 wildfires, net of estimated insurance recoveries, and higher general and plant maintenance costs. The unfavorable income tax benefit was largely due to state income tax impacts, partially offset by higher PTCs recognized of$21 million . Operating revenue decreased$45 million for 2021 compared to 2020, primarily due to lower retail revenue of$98 million , partially offset by higher wholesale and other revenue of$53 million . Retail revenue decreased mainly due to$234 million from theUtah andOregon general rate case orders issued in 2020 (fully offset in expense, primarily depreciation) and price impacts of$41 million from lower rates primarily due to certain general rate case orders, partially offset by higher customer volumes of$177 million . Retail customer volumes increased 3.1%, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather. Wholesale and other revenue increased mainly due to higher wheeling revenue, average wholesale prices and REC sales, partially offset by$34 million from the Oregon RAC settlement (fully offset in depreciation expense) recognized in 2020. Earnings increased$148 million for 2021 compared to 2020, primarily due to favorable income tax expense from higher PTCs recognized of$75 million from new wind-powered generating facilities placed in-service, and the impacts of ratemaking, lower operations and maintenance expense of$178 million and higher utility margin of$145 million , partially offset by higher depreciation and amortization expense of$255 million and lower allowances for equity and borrowed funds used during construction of$72 million . Operations and maintenance expense decreased primarily due to lower costs associated with wildfires and the Klamath Hydroelectric Settlement Agreement and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. Utility margin increased primarily due to the higher retail customer volumes, higher wheeling and wholesale revenue and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs, the price impacts from lower retail rates and higher wheeling expenses. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effectiveJanuary 1, 2021 , as well as additional assets placed in-service.MidAmerican Funding Operating revenue increased$478 million for 2022 compared to 2021, primarily due to higher electric operating revenue of$459 million and higher natural gas operating revenue of$27 million . Electric operating revenue increased due to higher wholesale and other revenue of$261 million and higher retail revenue of$198 million . Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of$229 million and higher wholesale volumes of$36 million . Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of$134 million (fully offset in expense, primarily cost of sales) and higher customer volumes of$62 million . Electric retail customer volumes increased 4.3%, primarily due to higher customer usage and the favorable impact of weather. Natural gas operating revenue increased due to higher customer usage of$9 million , the favorable impact of weather of$9 million and the impacts of tax reform of$5 million . 91 -------------------------------------------------------------------------------- Earnings increased$64 million for 2022 compared to 2021, primarily due to higher electric utility margin of$319 million , a favorable income tax benefit and higher natural gas utility margin of$25 million , partially offset by higher depreciation and amortization expense of$254 million , higher operations and maintenance expense of$53 million , unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of$17 million . Electric utility margin increased primarily due to higher wholesale and retail revenues, partially offset by higher purchased power and thermal generation costs. The favorable income tax benefit was mainly due to higher PTCs recognized of$136 million , partially offset by state income tax impacts. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs. Operating revenue increased$819 million for 2021 compared to 2020, primarily due to higher natural gas operating revenue of$430 million and higher electric operating revenue of$390 million . Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of$440 million (fully offset in cost of sales), largely due to theFebruary 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of$198 million and higher wholesale and other revenue of$192 million . Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of$116 million (fully offset in expense, primarily cost of sales), higher customer volumes of$63 million and price impacts of$19 million from changes in sales mix. Electric retail customer volumes increased 5.8% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased primarily due to higher average wholesale prices of$116 million and higher wholesale volumes of$71 million . Earnings increased$65 million for 2021 compared to 2020, primarily due to higher electric utility margin of$190 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of$198 million , higher operations and maintenance expense of$20 million and lower allowances for equity and borrowed funds of$8 million . Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of$64 million , from new wind-powered generating facilities placed in-service, partially offset by state income tax impacts. The increase in depreciation and amortization expense was primarily due to the impacts of certain regulatory mechanisms and additional assets placed in-service. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities.
NV Energy
Operating revenue increased$717 million for 2022 compared to 2021, primarily due to higher electric operating revenue of$668 million and higher natural gas operating revenue of$51 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of$636 million , higher regulatory-related revenue deferrals of$15 million and higher customer volumes of$6 million . Electric retail customer volumes increased 2.2%, primarily due to an increase in the average number of customers, partially offset by the unfavorable impact of weather. Earnings decreased$12 million for 2022 compared to 2021, primarily due to higher operations and maintenance expense of$24 million , higher depreciation and amortization expense of$17 million , higher interest expense of$15 million , unfavorable changes in the cash surrender value of corporate-owned life insurance policies and higher non-service benefit plan costs of$11 million , partially offset by higher interest and dividend income of$36 million from carrying charges on regulatory balances and higher electric utility margin of$32 million . Operations and maintenance expense increased mainly due to higher general and plant maintenance costs and an unfavorable change in earnings sharing at theNevada Utilities . Depreciation and amortization expense increased mainly from additional assets placed in-service. Electric utility margin increased mainly due to higher regulatory-related revenue deferrals of$15 million and higher electric retail customer volumes. Operating revenue increased$253 million for 2021 compared to 2020, primarily due to higher electric operating revenue of$252 million . Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of$229 million , a$120 million one-time bill credit in the fourth quarter of 2020 resulting from a regulatory rate review decision (fully offset in operations and maintenance and income tax expenses) and higher retail customer volumes of$10 million , partially offset by lower base tariff general rates of$71 million atNevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.3%, primarily due to an increase in the average number of customers, higher customer usage and the favorable impact of weather. 92 -------------------------------------------------------------------------------- Earnings increased$29 million for 2021 compared to 2020, primarily due to lower operations and maintenance expense of$90 million , lower income tax expense mainly from the impacts of ratemaking, lower interest expense of$21 million , higher interest and dividend income of$16 million and lower pension expense of$10 million , partially offset by lower electric utility margin of$97 million and higher depreciation and amortization expense of$47 million . Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at theNevada Utilities . Electric utility margin decreased primarily due to lower base tariff general rates atNevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.
Operating revenue increased$177 million for 2022 compared to 2021, primarily due to higher distribution revenue of$167 million and higher revenue of$158 million , due to a gas project that commenced commercial operation inMarch 2022 and a solar project that commenced commercial operation inJuly 2022 , partially offset by$155 million from the strongerU.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier ofLast Resort payments of$135 million (fully offset in cost of sales) and higher tariff rates of$78 million , partially offset by a 4.6% decline in units distributed of$36 million . Earnings increased$138 million for 2022 compared to 2021, primarily due to a deferred income tax charge of$109 million related to aJune 2021 enacted increase in theUnited Kingdom corporate income tax rate from 19% to 25% effectiveApril 1, 2023 , the higher distribution tariff rates and improved earnings of$47 million from the new gas and solar projects, partially offset by$41 million from the strongerU.S. dollar, the decline in units distributed and higher distribution-related operating and depreciation expenses of$25 million . Operating revenue increased$166 million for 2021 compared to 2020, primarily due to higher distribution revenue of$80 million , mainly from increased tariff rates of$40 million and a 3.2% increase in units distributed totaling$26 million , and$77 million from the weakerU.S. dollar. Earnings increased$46 million for 2021 compared to 2020, primarily due to the higher distribution revenue, lower write-offs of gas exploration costs of$36 million ,$16 million from the weakerU.S. dollar, favorable pension expense of$14 million and lower interest expense of$8 million , partially offset by higher income tax expense and higher distribution-related operating and depreciation expenses of$29 million . Earnings in 2021 included a deferred income tax charge of$109 million related to aJune 2021 enacted increase in theUnited Kingdom corporate income tax rate from 19% to 25% effectiveApril 1, 2023 , while earnings in 2020 included a deferred income tax charge of$35 million related to aJuly 2020 enacted increase in theUnited Kingdom corporate income tax rate from 17% to 19% effectiveApril 1, 2020 .
Operating revenue increased$300 million for 2022 compared to 2021, primarily due to higher operating revenue of$242 million at BHE GT&S and$47 million atNorthern Natural Gas . The increase in operating revenue at BHE GT&S was primarily due to higher nonregulated revenue of$109 million (largely offset in cost of sales) from favorable commodity prices, an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of$101 million and higher LNG revenue of$56 million atCove Point , largely from favorable variable revenue, partially offset by lower gas sales of$49 million at EGTS from operational and system balancing activities. The increase in operating revenue atNorthern Natural Gas was mainly due to higher transportation revenue of$63 million offset by lower gas sales of$14 million from system balancing activities. The variances in transportation revenue and gas sales included favorable impacts recognized of$49 million and$77 million , respectively, from theFebruary 2021 polar vortex weather event. Excluding this item, transportation revenue increased$112 million due to higher volumes and rates and gas sales increased$63 million (largely offset in cost of sales).
Earnings increased
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Operating revenue increased $1,966 million for 2021 compared to 2020, primarily
due to $1,828 million of incremental revenue at BHE GT&S, acquired in November
2020 , higher gas sales of $115 million ($38 million largely offset in costs of
sales) at Northern Natural Gas and higher transportation revenue of $29 million
at Kern River largely due to higher rates and volumes, partially offset by lower
transportation revenue of $24 million at Northern Natural Gas primarily due to
lower volumes. The variances in gas sales and transportation revenue at Northern
Natural Gas included favorable impacts of $77 million and $49 million ,
respectively, from the February 2021 polar vortex weather event.
Earnings increased $279 million for 2021 compared to 2020, primarily due to $244
million of incremental earnings at BHE GT&S, favorable earnings of $19 million
at Kern River from the higher transportation revenue and higher earnings of
$15 million at Northern Natural Gas , primarily due to higher gross margin on gas
sales and higher transportation revenue, each due to the favorable impacts of
the February 2021 polar vortex weather event, offset by the lower transportation
revenue.
BHE Transmission
Operating revenue increased
Earnings for 2022 were equal to 2021, primarily due to improved equity earnings
from ETT offset by
Operating revenue increased$72 million for 2021 compared to 2020, primarily due to$47 million from the weakerU.S. dollar, a regulatory decision received inNovember 2020 atAltaLink and higher revenue from the Montana-Alberta Tie Line of$11 million . Earnings increased$16 million for 2021 compared to 2020, primarily due to$12 million from the weakerU.S. dollar, higher earnings from theMontana -Alberta Tie Line and lower nonregulated interest expense at BHE Canada, partially offset by the impact of a regulatory decision received inApril 2020 atAltaLink .
Operating revenue increased$13 million for 2022 compared to 2021, primarily due to higher wind, geothermal, and solar revenues of$140 million from higher generation and pricing, partially offset by lower natural gas revenues of$72 million from lower generation and hedge losses, lower hydro revenues of$28 million due to the transfer of the Casecnan generating facility to the Philippine government inDecember 2021 and$27 million from unfavorable changes in the valuation of certain derivative contracts. Earnings increased$174 million for 2022 compared to 2021, primarily due to higher wind earnings of$214 million , higher geothermal earnings of$16 million and higher solar earnings of$14 million , partially offset by lower natural gas earnings of$44 million and lower hydro earnings of$18 million due to the Casecnan generating facility transfer. Wind earnings increased due to higher earnings from tax equity investments of$153 million , largely as a result of the unfavorable impacts recognized in 2021 from theFebruary 2021 polar vortex weather event and higher production tax credits, and higher earnings from owned projects of$61 million . Operating revenue increased$45 million for 2021 compared to 2020, primarily due to higher natural gas, solar, wind and hydro revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of$30 million . Earnings decreased$70 million for 2021 compared to 2020, primarily due to lower wind earnings of$83 million , largely from lower tax equity investment earnings of$90 million , and lower hydro earnings of$10 million , mainly due to lower income from a declining financial asset balance, partially offset by higher solar earnings of$22 million , mainly due to the higher operating revenue and lower depreciation expense. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of$165 million , primarily due to theFebruary 2021 polar vortex weather event, and lower commitment fee income, partially offset by$87 million of earnings from projects reaching commercial operation. 94 --------------------------------------------------------------------------------
HomeServices
Operating revenue decreased$947 million for 2022 compared to 2021, primarily due to lower brokerage and settlement services revenue of$637 million and lower mortgage revenue of$305 million . The decrease in brokerage and settlement services revenue resulted from an 11% decrease in closed transaction volume driven by 23% fewer closed units at existing companies resulting from rising interest rates and a corresponding slowdown in home sales offset by acquisitions and a 7% increase in average sales price. The lower mortgage revenue was due to a 40% decrease in funded volume, primarily due to a decline in refinance activity resulting from rising interest rates. Earnings decreased$287 million for 2022 compared to 2021, primarily due to lower earnings from brokerage and settlement services of$142 million and mortgage services of$126 million , largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the decrease in closed units at existing companies, partially offset by favorable operating expense variances. Operating revenue increased$819 million for 2021 compared to 2020, primarily due to higher brokerage revenue of$951 million , partially offset by lower mortgage revenue of$169 million from an 8% decrease in funded volume due to a decrease in refinance activity. The increase in brokerage revenue was due to a 21% increase in closed transaction volume at existing companies resulting from increases in average sales price and closed units. Earnings increased$12 million for 2021 compared to 2020, primarily due to higher earnings from brokerage and franchise services of$81 million , largely attributable to the increase in closed transaction volume at existing companies, partially offset by lower earnings from mortgage services of$68 million from the decrease in refinance activity.
BHE and Other
Operating revenue increased$65 million for 2022 compared to 2021, primarily due to higher electric and natural gas sales revenue at MES, from favorable electric volumes and natural gas pricing, including changes in unrealized positions on derivative contracts, offset by lower electric pricing and natural gas volumes. Earnings decreased$3,336 million for 2022 compared to 2021, primarily due to the$3,317 million unfavorable comparative change related to the Company's investment in BYD Company Limited, unfavorable comparative consolidated state income tax benefits, higher BHE corporate interest expense from anApril 2022 debt issuance and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by$75 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries ofBerkshire Hathaway and lower corporate costs. Operating revenue increased$103 million for 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MES, from favorable pricing offset by lower volumes. Earnings decreased$1,773 million for 2021 compared to 2020, primarily due to the$1,693 million unfavorable comparative change related to the Company's investment in BYD Company Limited,$95 million of higher dividends on BHE's 4.00% Perpetual Preferred Stock issued inOctober 2020 to certain subsidiaries ofBerkshire Hathaway , higher corporate costs and higher BHE corporate interest expense from debt issuances in March andOctober 2020 , partially offset by favorable comparative consolidated state income tax benefits and higher earnings of$17 million at MES.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity
separate and apart from BHE and its other subsidiaries. It should not be assumed
that the assets of any subsidiary will be available to satisfy BHE's obligations
or the obligations of its other subsidiaries. However, unrestricted cash or
other assets that are available for distribution may, subject to applicable law,
regulatory commitments and the terms of financing and ring-fencing arrangements
for such parties, be advanced, loaned, paid as dividends or otherwise
distributed or contributed to BHE or affiliates thereof. The Company's long-term
debt may include provisions that allow BHE or its subsidiaries to redeem such
debt in whole or in part at any time. These provisions generally include
make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial
Statements in Item 8 of this Form 10-K for further discussion regarding the
limitation of distributions from BHE's subsidiaries.
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As of December 31, 2022 , the Company's total net liquidity was as follows (in
millions):
BHE Pipeline
MidAmerican NV Northern BHE Group and
BHE PacifiCorp Funding Energy Powergrid Canada HomeServices Other Total
Cash and cash equivalents $ 32 $ 641 $ 261 $ 108 $ 37 $ 56 $ 239 $
217
Credit facilities(1) 3,500 1,200 1,509 650 296 793 2,925 - 10,873 Less: Short-term debt (245) - - - (120) (197) (557) - (1,119) Tax-exempt bond support and letters of credit - (249) (370) - - (1) - - (620) Net credit facilities 3,255 951 1,139 650 176 595 2,368
- 9,134
Total net liquidity$ 3,287 $ 1,592 $ 1,400 $ 758 $ 213 $ 651$ 2,607 $ 217$ 10,725 Credit facilities: Maturity dates 2025 2025 2023, 2025 2025 2025, 2026 2023, 2026, 2027 2023, 2026
(1) Includes
Refer to Note 9 of the Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion regarding the Company's credit facilities, letters of credit, equity commitments and other related items.
Operating Activities
Net cash flows from operating activities for the years ended
Net cash flows from operating activities for the years ended
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the years endedDecember 31, 2022 and 2021 were$(7.8) billion and$(5.8) billion , respectively. The change was primarily due to theJuly 2021 receipt of$1.3 billion due to the termination of the second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement" with Dominion Questar, higher capital expenditures of$894 million and higher cash paid for acquisitions, partially offset by lower funding of tax equity investments. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Net cash flows from investing activities for the years endedDecember 31, 2021 and 2020 were$(5.8) billion and$(13.2) billion , respectively. The change was primarily due to lower funding of tax equity investments, lower cash paid for acquisitions and theJuly 2021 receipt of$1.3 billion due to the termination of the Q-Pipe Purchase Agreement. Refer to "Future Uses of Cash" for further discussion of capital expenditures. 96 --------------------------------------------------------------------------------
OnNovember 1, 2020 , BHE completed its acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Questar, exclusive of theQuestar Pipeline Group . Under the terms of the Purchase and Sale Agreement, datedJuly 3, 2020 , BHE paid approximately$2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"). OnOctober 5, 2020 , BHE entered into the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of theQuestar Pipeline Group from Dominion Questar after receipt of HSR Approval for a cash purchase price of approximately$1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing. Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately$1.3 billion to Dominion Questar onNovember 2, 2020 . OnJuly 9, 2021 , Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Purchase Agreement. OnJuly 14, 2021 , BHE received the Purchase Price Repayment Amount of approximately$1.3 billion in cash.
Financing Activities
Net cash flows from financing activities for the year endedDecember 31, 2022 were$(1.0) billion . Sources of cash totaled$3.9 billion and consisted of proceeds from subsidiary debt issuances of$2.9 billion and proceeds from BHE senior debt issuances of$1.0 billion . Uses of cash totaled$4.9 billion and consisted mainly of repayments of subsidiary debt totaling$1.5 billion , purchases of common stock of$870 million , net repayments of short-term debt totaling$867 million , preferred stock redemptions totaling$800 million and distributions to noncontrolling interests of$524 million . Net cash flows from financing activities for the year endedDecember 31, 2021 were$(3.1) billion . Sources of cash totaled$2.4 billion and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled$5.5 billion and consisted mainly of preferred stock redemptions totaling$2.1 billion , repayments of subsidiary debt totaling$2.0 billion , distributions to noncontrolling interests of$488 million , repayments of BHE senior debt totaling$450 million and net repayments of short-term debt totaling$276 million . Net cash flows from financing activities for the year endedDecember 31, 2020 were$7.1 billion . Sources of cash totaled$11.7 billion and consisted of proceeds from BHE senior debt issuances of$5.2 billion , proceeds from preferred stock issuances of$3.8 billion and proceeds from subsidiary debt issuances totaling$2.7 billion . Uses of cash totaled$4.5 billion and consisted mainly of$2.8 billion for repayments of subsidiary debt, net repayments of short-term debt of$939 million and$350 million for repayments of BHE senior debt.
Debt Repurchases
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Preferred Stock Issuance
OnOctober 29, 2020 , BHE issued$3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries ofBerkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.
Preferred Stock Redemptions
For the years ended
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--------------------------------------------------------------------------------Common Stock Transactions
For the year endedDecember 31, 2022 , BHE purchased 740,961 shares of its common stock held by Mr.Gregory E. Abel , BHE's Chair, for$870 million . The purchase was pursuant to the terms of BHE's Shareholders Agreement.
For the year ended
There were no common stock repurchases for the year ended
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets. The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, by reportable segment for the years endedDecember 31 are as follows (in millions): Historical Forecast 2020 2021 2022 2023 2024 2025 PacifiCorp$ 2,540 $ 1,513 $ 2,166 $ 3,579 $ 3,069 $ 3,986
NV Energy 675 749 1,113 1,614 1,729 1,622
BHE Transmission 372 279 200 203 300 433
BHE Renewables 95 225 138 251 399 316
HomeServices 36 42 48 54 57 57
BHE and Other(1) (130) 21 46 4 2 -
Total $ 6,765 $ 6,611 $ 7,505 $ 9,726 $ 9,192 $ 9,790 (1)BHE and Other includes intersegment eliminations.
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Historical Forecast
2020 2021 2022 2023 2024 2025
Wind generation $ 2,125 $ 1,339 $ 774 $ 2,201 $ 1,710 $ 1,197
Electric distribution 1,705 1,679 1,806 1,860 1,732 2,337
Electric transmission 968 823 1,725 1,973 2,154 2,837
Natural gas transmission and storage 640 1,068 945 824 617 843
Solar generation 16 157 422 248 630 450
Electric battery and pumped hydro
storage - 23 16 317 392 575
Other 1,311 1,522 1,817 2,303 1,957 1,551
Total $ 6,765 $ 6,611 $ 7,505 $ 9,726 $ 9,192 $ 9,790 The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
•Construction and acquisition of wind-powered generating facilities atMidAmerican Energy totaling$72 million for 2022,$540 million for 2021 and$848 million for 2020.MidAmerican Energy placed in-service 294 MWs during 2021 and 729 MWs during 2020. All of these wind-powered generating facilities placed in-service in 2021 and 2020 qualify for 100% of PTCs available. PTCs from these projects are excluded fromMidAmerican Energy's Iowa EAC until these generation assets are reflected in base rates. Planned spending for the construction of wind-powered generating facilities totals$1,232 million in 2023,$1,032 million in 2024 and$740 million in 2025. •Repowering of wind-powered generating facilities atMidAmerican Energy totaling$500 million for 2022,$354 million for 2021 and$37 million for 2020. Planned spending for repowering totals$20 million in 2023,$179 million in 2024 and$84 million in 2025.MidAmerican Energy expects its repowered facilities to meetIRS guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. •Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties atPacifiCorp totaling$23 million for 2022,$118 million for 2021 and$1,148 million for 2020.PacifiCorp placed in-service 516 MWs of new wind-powered generating facilities in 2021 and 674 MWs in 2020. Planned spending for the construction of additional new wind-powered generating facilities and those at acquired sites totals$771 million in 2023,$385 million in 2024 and$251 million in 2025 and is primarily for projects totaling approximately 683 MWs that are expected to be placed in-service in 2023 through 2025. •Construction of wind-powered generating facilities atBHE Renewables totaling$155 million for 2021. InMay 2021 ,BHE Renewables completed the asset acquisition of a 54-MW wind-powered generating facility located inIowa . InDecember 2021 ,BHE Renewables completed asset acquisitions of 158-MW and 200-MW wind-powered generating facilities located inTexas .
•Repowering of wind-powered generating facilities at
•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities andNorthern Powergrid , wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand. 99 --------------------------------------------------------------------------------
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:
•PacifiCorp's transmission investment primarily reflects planned costs for the following Energy Gateway Transmission segments: the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation nearMedicine Bow, Wyoming and the Clover substation nearMona, Utah ; the 59-mile, 230-kV high-voltage transmission line between theWindstar substation nearGlenrock, Wyoming and the Aeolus substation; the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation nearBoardman, Oregon to the Hemingway substation nearBoise, Idaho ; the 14-mile, 345-kV high-voltage transmission line between the Oquirrh substation in theSalt Lake Valley and the Terminal substation near theSalt Lake City Airport ; the 40-mile, 500-kV high-voltage transmission line between the Limber substation in centralUtah and the Terminal substation; and the 195-mile, 500-kV high-voltage transmission line between the Anticline substation nearPoint of Rocks, Wyoming and the Populus substation inDowney, Idaho . Planned spending for these Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028 totals$1,005 million in 2023,$661 million in 2024 and$763 million in 2025. •Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft.Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft.Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft.Churchill substation to theMira Loma substations; and a 38-mile, 345-kV transmission line from the new Ft.Churchill substation to the Robinson Summit substations. Planned spending for the expansion programs estimated to be placed in-service in 2026-2028 totals$46 million in 2023,$380 million in 2024 and$502 million in 2025. •Operating expenditures include spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand. •Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related toPipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
•Construction of solar-powered generating facilities atPacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals$381 million from 2023 through 2025. •Construction of solar-powered generating facilities atMidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022, with total spend of$119 million in 2022 and$132 million in 2021. •Construction of solar-powered generating facility at theNevada Utilities includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed inClark County, Nevada , with commercial operation expected by the end of 2023. •Construction of solar-powered generating facilities atBHE Renewables' includes expenditures for a 48-MW solar photovoltaic facility with an additional 52 MWs of capacity of co-located battery storage inKern County, California , with commercial operation expected byNovember 30, 2024 . Planned spending totals$174 million in 2024.
•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:
•Construction of 38 MWs of new pumped hydro storage on theNorth Umpqua River system expected to be placed in-service in 2024 and 2026 as well as other battery storage projects providing approximately 419 MWs of storage that are expected to be placed in-service in 2026 atPacifiCorp . Planned spending for these project totals$398 million from 2023 through 2025. Planned spending for other pumped hydro storage projects that are expected to be placed in-service beyond 2026 totals$95 million from 2023 through 2025 100 -------------------------------------------------------------------------------- •Construction at theNevada Utilities of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed inClark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the site of the retiredReid Gardner generating station inClark County, Nevada , both with commercial operation expected by the end of 2023. Also, a 200-MW battery energy storage system that will be developed on the site of theValmy generating station inHumboldt County, Nevada with commercial operation expected by the end of 2025.
•Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of CCR.
Off-Balance Sheet Arrangements
The Company has certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, an amount is recorded on the Company's Consolidated Balance Sheets as an equity investment and is increased or decreased for the Company's pro-rata share of earnings or losses, respectively, less any dividends from such investments. Certain equity investments are presented on the Consolidated Balance Sheets net of investment tax credits. As ofDecember 31, 2022 , the Company's investments that are accounted for under the equity method had short- and long-term debt of$2.7 billion , unused revolving credit facilities of$122 million and letters of credit outstanding of$88 million . As ofDecember 31, 2022 , the Company's pro-rata share of such short- and long-term debt was$1.3 billion , unused revolving credit facilities was$61 million and outstanding letters of credit was$43 million . The entire amount of the Company's pro-rata share of the outstanding short- and long-term debt and unused revolving credit facilities is non-recourse to the Company. The entire amount of the Company's pro-rata share of the outstanding letters of credit is recourse to the Company. Although the Company is generally not required to support debt service obligations of its equity investees, default with respect to this non-recourse short- and long-term debt could result in a loss of invested equity. Material Cash Requirements The Company has cash requirements that may affect its consolidated financial condition that arise primarily from long- and short-term debt (refer to Note 9, 10 and 11), operating and financing leases (refer to Note 6), firm commitments (refer to Note 16), letters of credit (refer to Note 9), construction and other development costs (refer to Liquidity and Capital Resources included within this Item 7), uncertain tax positions (refer to Note 12) and AROs (refer to Note 14). Refer, where applicable, to the respective referenced note in Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information.
The Company has cash requirements relating to interest payments of
Regulatory Matters
The Company is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding the Company's general regulatory framework and current regulatory matters.
Quad Cities Generating Station Operating Status
Constellation Energy Generation, LLC ("Constellation Energy"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station ") of whichMidAmerican Energy has a 25% ownership interest, receives financial support for continued operation ofQuad Cities Station from the zero emission standard enacted by theIllinois legislature inDecember 2016 . The zero emission standard requires theIllinois Power Agency to purchase ZECs and recover the costs from certain ratepayers inIllinois , subject to certain limitations. The proceeds from the ZECs provide Constellation Energy additional revenue through 2027 as an incentive for continued operation ofQuad Cities Station .MidAmerican Energy does not receive additional revenue from the subsidy. 101 -------------------------------------------------------------------------------- ThePJM Interconnection, L.L.C. ("PJM") capacity market includes a MinimumOffer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program like theIllinois zero emission standard, resulting in a higher offer that may not clear the capacity market. Prior toDecember 19, 2019 , the PJM MOPR applied only to certain new gas-fueled resources. OnDecember 19, 2019 , theFERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year. While theFERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such asQuad Cities Station . TheFERC denied rehearing of that order onApril 16, 2020 . A number of parties, including Constellation Energy, have filed petitions for review of theFERC's orders in this proceeding, which remain pending before theCourt of Appeals for the Seventh Circuit .MidAmerican Energy cannot predict the outcome of this proceeding. While this litigation is pending, the MOPR applied toQuad Cities Station in the capacity auction for the 2022-2023 planning year inMay 2021 , which preventedQuad Cities Station from clearing in that capacity auction. At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions with theFERC onJuly 30, 2021 , and, onSeptember 29, 2021 , the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR applied in the capacity auction for the 2023-2024 delivery year but did not restrict the offers ofQuad Cities Station , which cleared in the capacity auction. Requests for rehearing of theFERC's notice establishing the effective date for the PJM's proposed market reforms were filed inOctober 2021 and denied by operation of law onNovember 4, 2021 . Several parties have filed petitions for review of theFERC's orders in this proceeding, which remain pending before theCourt of Appeals for the Third Circuit . Assuming the continued effectiveness of theIllinois zero emission standard, Constellation Energy no longer considersQuad Cities Station to be at heightened risk for early retirement. However, to the extent theIllinois zero emission standard does not operate as expected over its full term,Quad Cities Station would be at heightened risk for early retirement. TheFERC provided no new mechanism for accommodating state-supported resources likeQuad Cities Station other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Depending on the outcome of the proceedings related to the PJM MOPR, the continued effectiveness of theIllinois zero emission standard may be undermined unless the PJM adopts further changes to the MOPR orIllinois implements an FRR mechanism, under whichQuad Cities Station would be removed from the PJM's capacity auction.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. The Company believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and the Company is unable to predict the impact of the changing laws and regulations on its operations and financial results.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion regarding environmental laws and regulations.
Collateral and Contingent Features
Debt of BHE and debt and preferred securities of certain of its subsidiaries are
rated by credit rating agencies. Assigned credit ratings are based on each
rating agency's assessment of the rated company's ability to, in general, meet
the obligations of its issued debt or preferred securities. The credit ratings
are not a recommendation to buy, sell or hold securities, and there is no
assurance that a particular credit rating will continue for any given period of
time.
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BHE and its subsidiaries have no credit rating downgrade triggers that would
accelerate the maturity dates of outstanding debt, and a change in ratings is
not an event of default under the applicable debt instruments. The Company's
unsecured revolving credit facilities do not require the maintenance of a
minimum credit rating level in order to draw upon their availability. However,
commitment fees and interest rates under the credit facilities are tied to
credit ratings and increase or decrease when the ratings change. A ratings
downgrade could also increase the future cost of commercial paper, short- and
long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including
derivative contracts, contain credit support provisions that in part base
certain collateral requirements on credit ratings for senior unsecured debt as
reported by one or more of the recognized credit rating agencies. These
agreements may either specifically provide bilateral rights to demand cash or
other security if credit exposures on a net basis exceed specified
rating-dependent threshold levels ("credit-risk-related contingent features") or
provide the right for counterparties to demand "adequate assurance," or in some
cases terminate the contract, in the event of a material adverse change in
creditworthiness. These rights can vary by contract and by counterparty. As of
December 31, 2022 , the applicable entities' credit ratings from the recognized
credit rating agencies were investment grade. If all credit-risk-related
contingent features or adequate assurance provisions for these agreements had
been triggered as of December 31, 2022 , the Company would have been required to
post $704 million of additional collateral. The Company's collateral
requirements could fluctuate considerably due to market price volatility,
changes in credit ratings, changes in legislation or regulation, or other
factors.
Inflation
Historically, overall inflation and changing prices in the economies where BHE's subsidiaries operate have not had a significant impact on the Company's consolidated financial results. In theU.S. andCanada , the Regulated Businesses operate under cost-of-service based rate-setting structures administered by various state and provincial commissions and theFERC . Under these rate-setting structures, the Regulated Businesses are allowed to include prudent costs in their rates, including the impact of inflation. The price control formula used by the Northern Powergrid Distribution Companies incorporates the rate of inflation in determining rates charged to customers. BHE's subsidiaries attempt to minimize the potential impact of inflation on their operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, its impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs and long-term debt issuances. There can be no assurance that such actions will be successful.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. The following critical accounting estimates are impacted significantly by the Company's methods, judgments and assumptions used in the preparation of the Consolidated Financial Statements and should be read in conjunction with the Company's Summary of Significant Accounting Policies included in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
The Regulated Businesses prepare their financial statements in accordance with
authoritative guidance for regulated operations, which recognizes the economic
effects of regulation. Accordingly, the Regulated Businesses defer the
recognition of certain costs or income if it is probable that, through the
ratemaking process, there will be a corresponding increase or decrease in future
regulated rates. Regulatory assets and liabilities are established to reflect
the impacts of these deferrals, which will be recognized in earnings in the
periods the corresponding changes in regulated rates occur.
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The Company continually evaluates the applicability of the guidance for
regulated operations and whether its regulatory assets and liabilities are
probable of inclusion in future regulated rates by considering factors such as a
change in the regulator's approach to setting rates from cost-based ratemaking
to another form of regulation, other regulatory actions or the impact of
competition that could limit the Regulated Businesses' ability to recover their
costs. The Company believes its application of the guidance for regulated
operations is appropriate and its existing regulatory assets and liabilities are
probable of inclusion in future regulated rates. The evaluation reflects the
current political and regulatory climate at the federal, state and provincial
levels. If it becomes no longer probable that the deferred costs or income will
be included in future regulated rates, the related regulatory assets and
liabilities will be recognized in net income, returned to customers or
re-established as AOCI. Total regulatory assets were $5.1 billion and total
regulatory liabilities were $7.4 billion as of December 31, 2022 . Refer to
Note 7 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K
for additional information regarding the Regulated Businesses' regulatory assets
and liabilities.
Impairment of
The Company's Consolidated Balance Sheet as ofDecember 31, 2022 includes goodwill of acquired businesses of$11.5 billion . The Company evaluates goodwill for impairment at least annually and completed its annual review as ofOctober 31, 2022 . Additionally, no indicators of impairment were identified as ofDecember 31, 2022 . Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. The Company uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings or rate base; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, the Company incorporates current market information, as well as historical factors. The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or when the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. As a majority of all property, plant and equipment is used in regulated businesses, the impacts of regulation are considered when evaluating the carrying value of regulated assets. The estimate of cash flows arising from the future use of an asset, for the purposes of impairment analysis, requires the exercise of judgment. Circumstances that could significantly alter the calculation of fair value or the recoverable amount of an asset may include significant changes in the regulatory environment, the business climate, management's plans, legal factors, market price of the asset, the use of the asset, the physical condition of the asset, future market prices, load growth, competition and many other factors over the life of the asset. Any resulting impairment loss is highly dependent on the underlying assumptions and could significantly affect the Company's results of operations.
Pension and Other Postretirement Benefits
Certain of the Company's subsidiaries sponsor defined benefit pension and other postretirement benefit plans that cover the majority of employees. The Company recognizes the funded status of the defined benefit pension and other postretirement benefit plans on the Consolidated Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As ofDecember 31, 2022 , the Company recognized a net asset totaling$206 million for the funded status of the defined benefit pension and other postretirement benefit plans. As ofDecember 31, 2022 , amounts not yet recognized as a component of net periodic benefit cost that were included in net regulatory assets totaled$376 million and in AOCI totaled$527 million . The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including, but not limited to, discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. The Company believes that the key assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for disclosures about the defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year endedDecember 31, 2022 . 104 --------------------------------------------------------------------------------
The Company chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, the Company utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. The Company regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
The Company chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5.00% by 2028, at which point the rate of increase is assumed to remain constant.
The key assumptions used may differ materially from period to period due to
changing market and economic conditions. These differences may result in a
significant impact to pension and other postretirement benefits expense and
funded status. If changes were to occur for the following key assumptions, the
approximate effect on the Consolidated Financial Statements would be as follows
(dollars in millions):
Domestic Plans
Other Postretirement United Kingdom
Pension Plans Benefit Plans Pension Plan
+0.5% -0.5% +0.5% -0.5% +0.5% -0.5%
Effect on December 31, 2022
Benefit Obligations:
Discount rate $ (76) $ 82 $ (21) $ 23 $ (75) $ 86
Effect on 2022 Periodic Cost:
Discount rate $ 5 $ (3) $ 1 $ (1) $ (4) $ 4
Expected rate of return on plan
assets (13) 13 (4) 4 (7) 7
A variety of factors affect the funded status of the plans, including asset returns, discount rates, mortality assumptions, plan changes and the Company's funding policy for each plan.
Income Taxes In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory commissions. The Company's income tax returns are subject to continuous examinations by federal, state, local and foreign income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations is not expected to have a material impact on the Company's consolidated financial results. Refer to Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's income taxes. It is probable the Company's regulated businesses will pass income tax benefit and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to their customers. As ofDecember 31, 2022 , these amounts were recognized as a net regulatory liability of$2.5 billion and will be included in regulated rates when the temporary differences reverse. 105 --------------------------------------------------------------------------------
The Company has not established deferred income taxes on its undistributed
foreign earnings that have been determined by management to be reinvested
indefinitely; however, the Company periodically evaluates its capital
requirements. If circumstances change in the future and a portion of the
Company's undistributed foreign earnings were repatriated, the dividends may be
subject to taxation in the
Revenue Recognition - Unbilled Revenue
Revenue recognized is equal to what the Company has the right to invoice as it corresponds directly with the value to the customer of the Company's performance to date and includes billed and unbilled amounts. The determination of customer invoices is based on a systematic reading of meters, fixed reservation charges based on contractual quantities and rates or, in the case of theGreat Britain distribution businesses, when information is received from the national settlement system. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was$828 million as ofDecember 31, 2022 . Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses, economic impacts and composition of sales among customer classes. Unbilled revenue is reversed in the following month and billed revenue is recorded based on the subsequent meter readings.
Wildfire Loss Contingencies
As a result of several wildfires that have occurred in the Company's service territory and surrounding areas inOregon andCalifornia , the Company is required to evaluate its exposure to potential loss contingencies arising from claims associated with the wildfires. In determining this exposure, the Company is required to assess whether the likelihood of loss for each of the wildfires and lawsuits is remote, reasonably possible or probable, which involves complex judgments based on several variables including available information regarding the cause and origin of the wildfires, investigations, discovery associated with lawsuits and negotiations with various parties. If deemed reasonably possible, the Company is required to estimate the potential loss or range of potential loss and disclose any material amounts. If deemed probable, the Company is required to accrue a loss if reasonably estimable based on the bottom end of the range if no amount within the range of estimated loss is any better than another amount. Many assumptions and variables are involved in determining these estimates, including identifying the various categories of potential loss such as fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages. Within the categories of potential loss, further assumptions are made regarding items such as the types of structures damaged, estimated replacement values associated with those structures, value of personal property, the types of natural resource damage such as timber, the value of that timber, the nature of noneconomic damages such as those arising from personal injuries, other damages the Company may be responsible for if found negligent such as punitive damages, and the amount of any penalties or fines that may be imposed by governmental entities. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding the Company's loss contingencies associated with the 2020 Wildfires and the 2022 McKinney fire.
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