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 unaudited Consolidated Financial Statements and
Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
The Company's actual results in the future could differ significantly from the
historical results.

BHE is a holding company that owns a highly diversified portfolio of locally
managed and operated businesses principally engaged in the energy industry and
is a consolidated subsidiary of Berkshire Hathaway. As of May 4, 2023, Berkshire
Hathaway and family members and related or affiliated entities of the late Mr.
Walter Scott, Jr., a former member of BHE's Board of Directors, owned 92% and
8%, respectively, of BHE's voting common stock.

Berkshire Hathaway Energy's operations are organized as eight business segments:
PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican
Energy), NV Energy (which primarily consists of Nevada Power and Sierra
Pacific), Northern Powergrid (which primarily consists of Northern Powergrid
(Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group
(which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE
Transmission (which consists of BHE Canada (which primarily consists of
AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE,
through these locally managed and operated businesses, owns four utility
companies in the U.S. serving customers in 11 states, two electricity
distribution companies in Great Britain, five interstate natural gas pipeline
companies in the U.S., one of which owns a LNG export, import and storage
facility, an electric transmission business in Canada, interests in electric
transmission businesses in the U.S., a renewable energy business primarily
investing in wind, solar, geothermal and hydroelectric projects, one of the
largest residential real estate brokerage firms in the U.S. and one of the
largest residential real estate brokerage franchise networks in the U.S. 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 corporate
entities, corporate functions and intersegment eliminations. Effective January
1, 2023, the Company's unregulated retail energy services business was
transferred to a subsidiary of BHE Renewables. Prior period amounts, which were
previously reported in BHE and Other, have been changed to reflect this activity
in BHE Renewables.

                                       28
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Results of Operations for the First Quarter of 2023 and 2022

Overview

Operating revenue and earnings (loss) on common shares for the Company's reportable segments are summarized as follows (in millions):



                                                         First Quarter
                                           2023         2022              Change
Operating revenue:
PacifiCorp                               $ 1,484      $ 1,297      $   187        14  %
MidAmerican Funding                          920        1,005          (85)       (8)
NV Energy                                    999          693          306        44
Northern Powergrid                           354          315           39        12
BHE Pipeline Group                         1,173        1,035          138        13
BHE Transmission                             205          183           22        12
BHE Renewables                               393          336           57        17
HomeServices                                 875        1,207         (332)      (28)
BHE and Other                                (57)         (41)         (16)       39
Total operating revenue                  $ 6,346      $ 6,030      $   316         5  %

Earnings (loss) on common shares:
PacifiCorp                               $  (120)     $   130      $  (250)           *
MidAmerican Funding                          249          241            8         3
NV Energy                                     34           29            5        17
Northern Powergrid                            11          111         (100)      (90)
BHE Pipeline Group                           369          322           47        15
BHE Transmission                              64           62            2         3
BHE Renewables(1)                             79          145          (66)        (46)
HomeServices                                 (34)          21          (55)           *
BHE and Other                                329       (1,206)       1,535            *

Total earnings (loss) on common shares $ 981 $ (145) $ 1,126

*

(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 increased $1,126 million for the first quarter of 2023
compared to 2022. Included in these results was a pre-tax gain in the first
quarter of 2023 of $717 million ($567 million after-tax) compared to a pre-tax
loss in the first quarter of 2022 of $1,247 million ($985 million after-tax)
related to the Company's investment in BYD Company Limited. Excluding the impact
of this item, adjusted earnings on common shares for the first quarter of 2023
was $414 million, a decrease of $426 million, or 51%, compared to adjusted
earnings on common shares for the first quarter of 2022 of $840 million.

The increase in earnings on common shares for the first quarter of 2023 compared to 2022 were primarily due to the following:



•The Utilities' earnings decreased $237 million for the first quarter of 2023
compared to 2022, primarily from higher operations and maintenance expense,
largely due to an increase in loss accruals, net of expected insurance
recoveries, associated with the 2020 Wildfires. The higher operations and
maintenance expense was partially offset by favorable electric utility margin,
higher allowances for equity and borrowed funds used during construction,
increases in the cash surrender value of corporate-owned life insurance policies
and a favorable income tax benefit from valuation allowance changes on state net
operating loss carryforwards. Electric retail customer volumes increased 2.6%
for the first quarter of 2023 compared to 2022, driven by higher customer usage
and an increase in the average number of customers;
                                       29
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•Northern Powergrid's earnings decreased $100 million for the first quarter of
2023 compared to 2022, primarily due to a deferred income tax charge of $82
million recognized in March 2023 related to the enactment of a new Energy
Profits Levy income tax. Units distributed declined 4.8% due to the unfavorable
impact of weather and lower customer usage;

•BHE Pipeline Group's earnings increased $47 million for the first quarter of
2023 compared to 2022, largely due to a favorable general rate case settlement
at EGTS in 2022 and the impacts of a general rate case, with interim rates
effective January 1, 2023, subject to refund, at Northern Natural Gas;

•BHE Renewables' earnings decreased $66 million for the first quarter of 2023
compared to 2022, primarily due to unfavorable changes in unrealized positions
on derivative contracts due to lower forward electricity price curves;

•HomeServices' earnings decreased $55 million for the first quarter of 2023
compared to 2022, primarily due to lower earnings from brokerage and settlement
services and from mortgage services, reflecting the impact of rising interest
rates and a corresponding decline in home sales; and

•BHE and Other's earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited.

Reportable Segment Results

PacifiCorp



Operating revenue increased $187 million for the first quarter of 2023 compared
to 2022, primarily due to higher retail revenue of $159 million and higher
wholesale and other revenue of $28 million, primarily from higher average
wholesale market prices, partially offset by lower wholesale volumes. Retail
revenue increased primarily due to price impacts of $107 million from higher
average retail rates largely due to tariff changes and product mix and $52
million from higher volumes. Retail customer volumes increased 3.3%, primarily
due to the favorable impact of weather, higher customer usage and an increase in
the average number of customers.

Earnings decreased $250 million for the first quarter of 2023 compared to 2022,
primarily due to higher operations and maintenance expense of $428 million,
partially offset by higher utility margin of $38 million, higher allowances for
equity and borrowed funds used during construction of $21 million and a
favorable income tax benefit from valuation allowance changes on state net
operating loss carryforwards. Operations and maintenance expense was unfavorable
primarily due to an increase in loss accruals, net of expected insurance
recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire
mitigation and vegetation management costs, and higher general and plant
maintenance costs. Utility margin increased primarily due to higher retail rates
and volumes, favorable deferred net power costs and higher average wholesale
market prices, partially offset by higher purchased power and thermal generation
costs and lower wholesale volumes.

MidAmerican Funding



Operating revenue decreased $85 million for the first quarter of 2023 compared
to 2022, primarily due to lower natural gas operating revenue of $70 million and
lower electric operating revenue of $17 million. Natural gas operating revenue
decreased primarily due to a lower average per-unit cost of natural gas sold
resulting in lower purchased gas adjustment recoveries of $61 million (fully
offset in cost of sales) and the unfavorable impact of weather of $5 million.
Electric operating revenue decreased due to lower wholesale and other revenue of
$33 million, partially offset by higher retail revenue of $16 million. Electric
wholesale and other revenue decreased mainly due to lower wholesale volumes of
$22 million and lower average wholesale per-unit prices of $13 million. Electric
retail revenue increased primarily due to higher recoveries through adjustment
clauses of $14 million (largely offset in expense, primarily cost of sales).
Electric retail customer volumes increased 1.0%, primarily due to higher
customer usage, partially offset by the unfavorable impact of weather.

Earnings increased $8 million for the first quarter of 2023 compared to 2022,
primarily due to lower depreciation and amortization expense of $17 million, a
one-time gain on the sale of an investment of $13 million and favorable changes
in the cash surrender value of corporate-owned life insurance policies of $12
million, partially offset by higher operations and maintenance expense of $13
million, lower natural gas utility margin of $8 million and lower electric
utility margin of $7 million. Depreciation and amortization expense decreased
primarily from the impacts of certain regulatory mechanisms, partially offset by
additional assets placed in-service. Operations and maintenance expense
increased due to higher general and plant maintenance costs and unfavorable
property insurance costs. Natural gas utility margin decreased primarily due to
the unfavorable impact of weather. Electric utility margin decreased primarily
due to lower wholesale revenue, partially offset by higher retail revenue and
lower purchased power costs.

                                       30
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NV Energy



Operating revenue increased $306 million for the first quarter of 2023 compared
to 2022, primarily due to higher electric operating revenue of $260 million and
higher natural gas operating revenue of $44 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 $229 million, higher customer volumes of
$8 million, increased base tariff general rates of $8 million at Sierra Pacific
and favorable transmission and wholesale revenue of $7 million. Electric retail
customer volumes increased 2.9%, primarily due to the favorable impact of
weather and an increase in the average number of customers.

Earnings increased $5 million for the first quarter of 2023 compared to 2022,
primarily due to higher electric utility margin of $31 million and favorable
interest and dividend income of $16 million, mainly from carrying charges on
higher deferred energy balances, partially offset by higher operations and
maintenance expenses of $24 million, unfavorable depreciation and amortization
expense of $13 million and increased interest expense of $12 million due to
higher outstanding long-term debt balances. Electric utility margin increased
primarily due to higher electric retail customer volumes, increased base tariff
general rates at Sierra Pacific and higher transmission and wholesale revenue.
Operations and maintenance expense increased primarily due to higher general and
plant maintenance costs and higher customer service operations costs.
Depreciation and amortization expense increased primarily due to additional
assets placed in-service.

Northern Powergrid



Operating revenue increased $39 million for the first quarter of 2023 compared
to 2022, primarily due to higher distribution revenue of $41 million and higher
revenue at CE Gas of $29 million, partially offset by $37 million from the
stronger U.S. dollar. Distribution revenue increased primarily due to the
recovery of Supplier of Last Resort payments of $43 million (fully offset in
cost of sales) and higher tariff rates of $10 million. Also impacting
distribution revenue was a 4.8% decline in units distributed, largely due to the
unfavorable impact of weather and lower customer usage, of $11 million. CE Gas
revenue increased from a gas project that commenced commercial operation in
March 2022 and a solar project that commenced commercial operation in July 2022.

Earnings decreased $100 million for the first quarter of 2023 compared to 2022,
primarily due to a deferred income tax charge of $82 million recognized in March
2023 related to the enactment of a new Energy Profits Levy income tax. Earnings
were also impacted by unfavorable distribution-related operating and
depreciation expenses of $11 million and increased non-service benefit plan
costs of $10 million, partially offset by favorable operating performance at CE
Gas of $8 million from the gas and solar projects that commenced commercial
operations in 2022.

BHE Pipeline Group



Operating revenue increased $138 million for the first quarter of 2023 compared
to 2022, primarily due to higher operating revenue of $71 million at Northern
Natural Gas and $55 million at BHE GT&S. The increase in operating revenue at
Northern Natural Gas was largely due to the impacts of a general rate case, with
interim rates effective January 1, 2023, subject to refund, of $63 million and
higher transportation revenue of $34 million from higher rates in the Field
Area, partially offset by lower gas sales of $25 million (largely offset in cost
of sales) from system balancing activities. The increase in operating revenue at
BHE GT&S was primarily due to an increase in regulated gas transportation and
storage services rates due to the settlement of EGTS' general rate case of $42
million, higher LNG revenue of $16 million at Cove Point, and an increase in
variable revenue related to park and loan activity of $10 million at EGTS,
partially offset by lower non-regulated revenue of $22 million (largely offset
in cost of sales) from lower volumes and unfavorable commodity prices.

Earnings increased $47 million for the first quarter of 2023 compared to 2022,
largely due to higher earnings at Northern Natural Gas of $28 million and higher
earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due
to the impacts of a general rate case of $16 million and higher transportation
revenue in the Field Area, partially offset by higher operations and maintenance
expense. The increase at BHE GT&S is due to a favorable general rate case
settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas
Transmission System, partially offset by higher operations and maintenance
expense and increased cost of gas from the unfavorable revaluation of volumes
retained, due to lower natural gas prices.

BHE Transmission



Operating revenue increased $22 million for the first quarter of 2023 compared
to 2022, primarily due to $26 million of incremental revenue from non-regulated
wind-powered generating facilities acquired in November 2022 and higher other
non-regulated revenue at BHE Canada, partially offset by $12 million from the
stronger U.S. dollar.

                                       31
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Earnings increased $2 million for the first quarter of 2023 compared to 2022,
primarily due to $6 million of incremental earnings at non-regulated
wind-powered generating facilities acquired in November 2022, partially offset
by $3 million from the stronger U.S. dollar.

BHE Renewables



Operating revenue increased $57 million for the first quarter of 2023 compared
to 2022, primarily due to higher wind revenues of $60 million, largely due to
favorable changes in the valuation of certain derivative contracts, and higher
natural gas and electric retail energy services revenue of $23 million,
partially offset by lower solar revenues of $20 million from lower generation
due to weather events in California. Natural gas and electric retail energy
services revenue increased due to higher electric volumes and favorable natural
gas and electric pricing, partially offset by lower natural gas volumes.

Earnings decreased $66 million for the first quarter of 2023 compared to 2022,
primarily due to lower earnings of $79 million from the retail energy services
business, largely due to unfavorable changes in unrealized positions on
derivative contracts caused by lower forward electricity price curves, lower
natural gas and geothermal earnings of $40 million, primarily due to maintenance
outages, and lower solar earnings of $18 million from lower generation due to
weather events in California. These items were partially offset by higher wind
earnings of $74 million, largely due to favorable changes in the valuation of
certain derivative contracts and higher earnings from tax equity investments of
$28 million due to lower equity losses and higher production tax credits.

HomeServices



Operating revenue decreased $332 million for the first quarter of 2023 compared
to 2022, primarily due to lower brokerage and settlement services revenue of
$293 million and lower mortgage revenue of $34 million. The decrease in
brokerage and settlement services revenue resulted from a 29% decrease in closed
transaction volume due to rising interest rates and a corresponding decline in
home sales. The lower mortgage revenue was due to a 41% decrease in funded
volume, primarily due to rising interest rates.

Earnings decreased $55 million for the first quarter of 2023 compared to 2022,
primarily due to lower earnings from brokerage and settlement services of $38
million and mortgage services of $12 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 transaction volume, partially
offset by favorable operating expenses primarily due to lower compensation
costs.

BHE and Other

Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.



Earnings increased $1,535 million for the first quarter of 2023 compared to
2022, primarily due to the $1,552 million favorable comparative change related
to the Company's investment in BYD Company Limited, favorable changes in the
cash surrender value of corporate-owned life insurance policies of $14 million
and $8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock
issued to certain insurance subsidiaries of Berkshire Hathaway. These items were
partially offset by higher BHE corporate interest expense from an April 2022
debt issuance and $17 million of lower federal income tax credits recognized on
a consolidated basis.


                                       32

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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 the Company's Annual Report on Form 10-K for the year
ended December 31, 2022 for further discussion regarding the limitation of
distributions from BHE's subsidiaries.

As of March 31, 2023, 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  $   173          $        19          $         58          $   21          $      18          $              64          $             216          $         394          $    963

Credit facilities(1)         3,500                2,000                 1,509             650                295                        795                      2,725                      -            11,474
Less:
Short-term debt               (755)                   -                     -             (83)               (49)                      (127)                      (805)                     -            (1,819)
Tax-exempt bond support
and letters of credit            -                 (249)                 (363)              -                  -                         (1)                         -                      -              (613)
Net credit facilities        2,745                1,751                 1,146             567                246                        667                      1,920                      -             9,042

Total net liquidity        $ 2,918          $     1,770          $      1,204          $  588          $     264          $             731          $           2,136          $         394          $ 10,005
Credit facilities:
Maturity dates                   2025           2024, 2025            2023, 2025            2025               2025           2023, 2026, 2027           2023, 2024, 2026

(1)Includes $48 million drawn on capital expenditure and other uncommitted credit facilities at Northern Powergrid.

Operating Activities



Net cash flows from operating activities for the three-month periods ended
March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The
decrease was primarily due to changes in working capital and regulatory assets
and unfavorable operating results.

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 three-month periods ended
March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively.
The change was primarily due to higher purchases, net of proceeds from
maturities, of U.S. Treasury Bills totaling $896 million and higher capital
expenditures of $295 million, partially offset by higher proceeds from sales of
marketable securities of $942 million. Refer to "Future Uses of Cash" for a
discussion of capital expenditures.

                                       33
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Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.



Net cash flows from financing activities for the three-month period ended
March 31, 2022, was $(310) million. Sources of cash totaled $405 million and
consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715
million and consisted mainly of repayments of subsidiary debt totaling $193
million, net repayments of short-term debt totaling $165 million and
distributions to noncontrolling interests of $117 million.

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
customer 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.

                                       34
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The Company's historical and forecast capital expenditures, each of which
exclude amounts for non-cash equity AFUDC and other non-cash items, are as
follows (in millions):

                                          Three-Month Periods            Annual
                                            Ended March 31,             Forecast
                                           2022             2023          2023
Capital expenditures by business:
PacifiCorp                          $       374           $   643      $  3,662
MidAmerican Funding                         459               382         2,324
NV Energy                                   272               437         1,751
Northern Powergrid                          169               124           597
BHE Pipeline Group                          205               169         1,431
BHE Transmission                             47                43           191
BHE Renewables                               19                29           269
HomeServices                                 12                11            46
BHE and Other(1)                             (4)               10            12
Total                               $     1,553           $ 1,848      $ 10,283


Capital expenditures by type:
Wind generation                              $   153      $   105      $  2,172
Electric distribution                            388          477         2,071
Electric transmission                            261          291         2,063
Natural gas transmission and storage             103           65

1,097


Solar generation                                  51           40

236


Electric battery and pumped hydro storage          1           40           236
Other                                            596          830         2,408
Total                                        $ 1,553      $ 1,848      $ 10,283

(1)BHE and Other represents amounts related principally to other entities corporate functions and intersegment eliminations.

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 of wind-powered generating facilities at MidAmerican Energy
totaling $75 million and $3 million for the three-month periods ended March 31,
2023 and 2022, respectively. The timing and amount of forecast wind generation
capital expenditures may be substantially impacted by the ultimate outcome of
MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of
additional wind-powered generating facilities totals $1,025 million for the
remainder of 2023.

•Repowering of wind-powered generating facilities at MidAmerican Energy totaling
$5 million and $120 million for the three-month periods ended March 31, 2023 and
2022, respectively. Planned spending for the repowering of wind-powered
generating facilities totals $16 million for the remainder of 2023. MidAmerican
Energy expects its repowered facilities to meet Internal Revenue Service
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 at
PacifiCorp totaling $14 million and $6 million for the three-month periods ended
March 31, 2023 and 2022, respectively. Planned spending for the construction of
additional wind-powered generating facilities and those at acquired sites totals
$807 million for the remainder of 2023.

•Repowering of wind-powered generating facilities at BHE Renewables totaling $25
million for the three-month period ended March 31, 2022. Planned spending for
the repower of wind-powered facilities totals $50 million for the remainder of
2023.

                                       35
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•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 enhancements at the Utilities and
Northern Powergrid, wildfire mitigation, storm damage restoration and repairs
and investments in routine expenditures for distribution needed to serve
existing and expected demand.

•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:



•PacifiCorp's transmission investments primarily reflect costs associated with
Energy Gateway Transmission segments that are expected to be placed in-service
in 2024 through 2028. Expenditures for these projects totaled $110 million and
$96 million for the three-month periods ended March 31, 2023 and 2022,
respectively. Planned spending for these Energy Gateway Transmission segments
totals $898 million for the remainder of 2023.

•Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada
Utilities have 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 the Mira Loma
substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill
substation to the Robinson Summit substation. Expenditures for the expansion
program and other growth projects totaled $42 million and $30 million for the
three-month periods ended March 31, 2023 and 2022, respectively. Planned
spending for the expansion program estimated to be placed in-service in 2026
through 2028 and other growth projects totals $88 million for the remainder of
2023.

•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 to Pipeline 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 at PacifiCorp totaling 377
MWs of new generation and are expected to be placed in-service in 2026. Planned
spending totals $12 million for the remainder of 2023.

•Construction and operation of solar-powered generating facilities at
MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale
solar generation, all of which were placed in-service in 2022. For the
three-month periods ended March 31, 2023 and 2022 solar generation spend totaled
$9 million and $44 million, respectively. Planned spending totals $1 million for
the remainder of 2023.

•Construction of a solar-powered generating facility at Nevada Power totaling
$31 million and $7 million for the three-month periods ended March 31, 2023 and
2022, respectively. Planned spending totals $175 million for the remainder of
2023. Construction includes expenditures for a 150-MW solar photovoltaic
facility with an additional 100 MWs of co-located battery storage that will be
developed in Clark County, Nevada. Commercial operation is expected by the end
of 2023.

•Electric battery and pumped hydro storage includes growth expenditures, including spending for the following:



•Construction at the Nevada Utilities of a 100-MW battery energy storage system
co-located with a 150-MW solar photovoltaic facility that will be developed in
Clark County, Nevada and a 220-MW grid-tied battery energy storage system that
will be developed on the site of the retired Reid Gardner generating station in
Clark 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 the Valmy generating station in Humboldt County, Nevada with commercial
operation expected by the end of 2025. Total spending for the three-month period
ended March 31, 2023, was $39 million with planned spending of $159 million for
the remainder of 2023.

                                       36
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•Other 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 coal combustion residuals.

Material Cash Requirements



As of March 31, 2023, there have been no material changes in cash requirements
from the information provided in Item 7 of the Company's Annual Report on
Form 10-K for the year ended December 31, 2022, other than those disclosed in
Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of
this Form 10-Q.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive
regulation. The discussion below contains material developments to those matters
disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year
ended December 31, 2022, and new regulatory matters occurring in 2023.

PacifiCorp

Utah

In May 2023, PacifiCorp filed its energy balancing account application to recover deferred net power costs from 2022. The filing requested a rate increase of $98 million, or 4.6%, effective on an interim basis July 1, 2023.

Oregon

In April 2023, PacifiCorp filed its transition adjustment mechanism requesting approval to update net power costs for 2024. The filing requested a rate increase of $164 million, or 9.5%, to become effective January 1, 2024.

Wyoming



In March 2023, PacifiCorp filed a general rate case requesting a rate increase
of $140 million, or 21.6%, to become effective January 1, 2024. The requested
rate increase includes recovery of increases in net power costs and new major
capital investments in transmission and wind-powered generating facilities.

In April 2023, PacifiCorp filed its energy cost adjustment and renewable energy credit and sulfur dioxide revenue credit mechanisms to recover deferred net power costs from 2022. The combined filing requested a rate increase of $49 million, or 7.4%, to become effective on an interim basis July 1, 2023.

Washington



In March 2023, PacifiCorp filed a general rate case requesting a two-year rate
plan with a rate increase of $27 million, or 6.6%, to become effective March 1,
2024, and a second rate increase of $28 million, or 6.5%, to become effective
March 1, 2025. The requested rate increase includes recovery of increases in net
power costs and new major capital investments in transmission and wind-powered
generating facilities.

California

In May 2022, PacifiCorp filed a general rate case requesting an overall rate
change of $28 million, or 25.7%, to become effective January 1, 2023. In
November 2022, the CPUC granted the requested rate effective date and directed
PacifiCorp to establish a memorandum account to track the change in rates
beginning January 1, 2023, until the new rates become effective upon the
issuance of a decision in late 2023. PacifiCorp filed rebuttal testimony in
February 2023 with a slight adjustment of an overall rate increase of
$27 million, or 25.0%. Also in February 2023, the CPUC issued a ruling
requesting additional information on PacifiCorp's wildfire and risk analyses and
requested additional information regarding wildfire memorandum accounts. In
March 2023, the CPUC split the general rate case into two tracks. The first
track addresses the general rate case with an expected decision from the CPUC in
late 2023, and the second track addresses the wildfire memorandum accounts with
an expected decision in early 2024.

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MidAmerican Energy

South Dakota



In May 2022, MidAmerican Energy filed a request with the South Dakota Public
Utilities Commission ("SDPUC") for a $7 million, or 6.4%, annual increase in
South Dakota retail natural gas rates. In March 2023, MidAmerican Energy filed a
settlement agreement between all parties allowing a total increase of $6
million, or 5.5%, annual increase in South Dakota retail natural gas rates, upon
completion of the capital investment phase-in adjustment clause. On March 31,
2023, the SDPUC issued an order approving the settlement agreement with final
rates effective April 1, 2023.

Wind PRIME



In January 2022, MidAmerican Energy filed an application with the IUB for
advance ratemaking principles for Wind PRIME. If approved, MidAmerican Energy
expects to proceed with Wind PRIME, which consists of up to 2,042 MWs of new
wind generation and up to 50 MWs of solar generation. If all Wind PRIME
generation is constructed, MidAmerican Energy will own over 9,300 MWs of wind
generation and nearly 200 MWs of solar generation. Wind PRIME is projected to
allow MidAmerican Energy to generate renewable energy greater than or equal to
all of its Iowa retail customers' annual energy needs. MidAmerican Energy
expects to be eligible for 100% PTCs under current tax law for the Wind PRIME
projects. In December 2022, MidAmerican Energy, the Iowa Office of Consumer
Advocate and the Iowa Business Energy Coalition filed a non-unanimous settlement
with the IUB that includes a rate of return of 11.0%. The settlement would
benefit customers by providing an immediate rate decrease through lower retail
fuel costs and future rate increase mitigation through accelerated depreciation
of generation assets. The IUB conducted a hearing on the application and
proposed settlement during the week of February 20, 2023. On April 27, 2023, the
IUB issued its final order regarding the application. The IUB found that
MidAmerican Energy met the statutory requisites for a grant of advance
ratemaking principles and granted the application, but rejected the settlement
and proposed its own principles for the project. MidAmerican Energy is reviewing
the order and assessing options for rejection or motion to reconsider.
MidAmerican Energy must either accept or reject the order, or file a motion for
reconsideration within 20 days and no later than May 17, 2023.

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Iowa Transmission Legislation



In June 2020, Iowa enacted legislation that grants incumbent electric
transmission owners the right to construct, own and maintain electric
transmission lines that have been approved for construction in a federally
registered planning authority's transmission plan and that connect to the
incumbent electric transmission owner's facility. Also known as the Right of
First Refusal, the law provides MidAmerican Energy, as an incumbent electric
transmission owner, the legal right to construct, own and maintain transmission
lines in MidAmerican Energy's service territory that have been approved by the
MISO (or another federally registered planning authority) and are eligible to
receive regional cost allocation. To exercise the legal right, MidAmerican
Energy must notify the IUB within 90 days of any such approval for the
construction of eligible electric transmission lines that it intends to
construct, own and maintain. The law still requires an incumbent electric
transmission owner to obtain a state franchise from the IUB to construct, erect,
maintain or operate an electric transmission line and, upon issuance of a
franchise, the incumbent electric transmission owner must provide the IUB an
estimate of the cost to construct the eligible electric transmission line and,
until the construction is complete, a quarterly report updating the estimated
cost to construct the eligible electric transmission line. In October 2020,
national transmission interests filed a lawsuit that challenged the law on state
constitutional grounds. The suit argues that the law was enacted in violation of
the "single-subject" provision of Iowa's state constitution because it was
"log-rolled" into a late session appropriations bill and violates the equal
protection provision of the Iowa constitution. The State of Iowa defended the
law, and MidAmerican Energy and ITC Midwest both intervened and defended the law
as well. The Iowa district court dismissed the lawsuit in March 2021 for lack of
standing, and the national transmission interests appealed. In June 2022, the
Iowa Court of Appeals upheld the district court's decision, after which the
national transmission interests asked the Iowa Supreme Court to reconsider. In
November 2022, the Iowa Supreme Court granted the motion to reconsider. On March
24, 2023, the Iowa Supreme Court issued an opinion that reversed the lower
courts, held the national transmission interests had standing, and remanded the
case to the district court to consider the state constitutional claims on their
merits. The opinion also imposed a temporary injunction that stayed enforcement
of the law pending a decision on the merits. On April 7, 2023, the State of
Iowa, acting individually, and MidAmerican Energy and ITC Midwest, acting
jointly, filed petitions for rehearing with the Iowa Supreme Court. On April 19,
2023, the national transmission interests filed a reply that (1) expressed its
opposition to the petitions for rehearing, (2) asked the Iowa Supreme Court to
hold that the injunction specifically applied to and precluded advancement of
MidAmerican Energy's Long Range Transmission Projects ("LRTP") Tranche 1
projects, and (3) asked the Iowa Supreme Court to retain the matter and rule on
the constitutional claims on the merits without further briefing or argument. On
April 26, 2023, the Iowa Supreme Court issued an order that denied the petitions
for rehearing without comment and made minor, non-substantive changes to the
decision, with no changes to the injunction. No earlier than May 18, 2023, the
Iowa Supreme Court will remand the case to the district court for further
proceedings on the merits. To this point, MISO has taken no action to reverse or
disrupt its approval of MidAmerican Energy's LRTP Tranche 1 projects. This
matter only potentially affects the manner in which MidAmerican Energy would
secure the right to construct transmission lines that are eligible for regional
cost allocation and are otherwise subject to competitive bidding under the MISO
tariff; it does not negatively affect or implicate MidAmerican Energy's ongoing
rights to construct any other transmission lines, including lines required to
serve new or expanded retail load, connect new generators or meet reliability
criteria.

NV Energy (Nevada Power and Sierra Pacific)

Merger Application



In March 2022, the Nevada Utilities filed a joint application with the PUCN for
authorization to merge Sierra Pacific with and into Nevada Power, with Nevada
Power being the surviving entity. If approved by the PUCN as filed, Nevada Power
will have two distinct electric service territories in northern and southern
Nevada each with their own rates and one natural gas service territory in the
Reno and Sparks area. In October 2022, all parties to the proceedings relating
to the joint application entered into a Stipulation to delay the procedural
schedule. The Nevada Utilities made a supplemental filing on December 30, 2022.
In March 2023, the proceedings relating to the joint application were postponed
to May 2023. In April 2023, the Nevada Utilities filed a notice with the PUCN
requesting to withdraw the joint application to merge into a single corporate
entity and vacate the current procedural schedule, and executed a termination of
the related merger agreement.

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Transportation Electrification Plan ("TEP")



In September 2022, the Nevada Utilities filed an amendment to the 2021 Joint IRP
for the approval of a Distributed Resource Plan amendment to implement the
state's first TEP pursuant to Section 51 of SB 448 and approve proposed tariffs
and schedules to implement the TEP. The 2022 TEP outlines programs, investments
and incentives to accelerate transportation electrification across Nevada. The
Nevada Utilities proposed a budget of $348 million, which represents the maximum
cost over the depreciable life of the TEP's programs and assets, to deploy the
TEP in 2023 through 2024. In March 2023, the PUCN issued an order approving
certain programs in the TEP, authorizing a lower program budget of $70 million
and ordering specific caps on the program management and contingency budget
amounts. The unapproved programs have been deferred for approval in future TEP
filings. The PUCN also granted regulatory asset treatment of the approved
program costs. In April 2023, interveners filed a petition for reconsideration
of the PUCN's March 2023 Order.

Northern Powergrid Distribution Companies



Ofgem has completed the price control review that resulted in a new price
control effective April 1, 2023. The license modifications that give effect to
the price control were published by Ofgem on February 3, 2023 and were subject
to appeal to the Competition and Markets Authority ("CMA") if an appeal was
filed by March 3, 2023. On March 2, 2023, Northern Powergrid sought permission
from the CMA to appeal against the license modifications that give effect to the
RIIO-ED2 price control. The appeal relates to two specific areas:

•Ofgem's misallocation of allowances that is inconsistent with efficient costs; and

•Ofgem's approach to determine rewards for the Business Plan Incentive.

The permission for the appeal was granted by the CMA and the appeal is expected to conclude in the fourth quarter of 2023 in accordance with the timetable required of the CMA. The outcome of this appeal may increase the revenue available to the Company if the CMA amends the price control determination.

BHE Pipeline Group

BHE GT&S



In September 2021, EGTS filed a general rate case for its FERC-jurisdictional
services, with proposed rates to be effective November 1, 2021. EGTS proposed an
annual cost-of-service of approximately $1.1 billion, and requested increases in
various rates, including general system storage rates by 85% and general system
transmission rates by 60%. In October 2021, the FERC issued an order that
accepted the November 1, 2021 effective date for certain changes in rates, while
suspending the other changes for five months following the proposed effective
date, until April 1, 2022, subject to refund. In September 2022, a settlement
agreement was filed with the FERC, which provided for increased service rates
and decreased depreciation rates. Under the terms of the settlement agreement,
EGTS' rates result in an increase to annual firm transmission and storage
services revenues of approximately $160 million and a decrease in annual
depreciation expense of approximately $30 million, compared to the rates in
effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022
through February 2023, including accrued interest, totaled $91 million. In
November 2022, the FERC approved the settlement agreement and the rate refunds
to customers were processed in late February 2023.

Northern Natural Gas



In July 2022, Northern Natural Gas filed a general rate case that proposed an
overall annual cost-of-service of $1.3 billion. This is an increase of $323
million above the cost of service filed in its 2019 rate case of $1.0 billion.
Depreciation on increased rate base and an increase in depreciation and negative
salvage rates account for $115 million of the $323 million increase in the filed
cost of service. Northern Natural Gas has requested increases in various rates,
including transportation and storage reservation rates. In January 2023, the
FERC approved Northern Natural Gas filing to implement its interim rates
effective January 1, 2023, subject to refund and the outcome of hearing
procedures. Procedural hearings are scheduled to begin June 14, 2023.

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BHE Transmission

AltaLink

2024-2025 General Tariff Application



In April 2023, AltaLink filed its 2024-2025 GTA with the AUC with total total
transmission tariffs of C$902.3 million and C$908.6 million for 2024 and 2025,
respectively, which extends AltaLink's previous five-year commitment to maintain
its tariff at or below C$904 million from 2019 to 2023 for another year. The
application also requests the approval to reinstate C$98.9 million cost of
removal to rate base which was not previously approved, based on additional
information filed.

Generic Cost of Capital Proceeding



In January 2022, the AUC initiated the generic cost of capital proceeding. The
proceeding will be conducted in two stages. The first stage will determine the
cost of capital parameters for 2023 and the second stage will consider returning
to a formula-based approach to establish cost of capital adjustments, commencing
in 2024. In March 2022, the AUC issued its decision with respect to the first
stage of the GCOC proceeding by approving the extension of the 2022 return on
equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering
uncertainty and continued volatility of financial markets due to the COVID-19
pandemic. In June 2022, the AUC initiated the second stage to explore a
formula-based approach to determine the return on equity for 2024 and future
test periods.

In February 2023, AltaLink and other stakeholders filed evidence. AltaLink filed
expert evidence recommending a 10.3% return on equity, on a recommended equity
ratio of 40%. Other utilities filed similar recommendations. The Consumers'
Coalition of Alberta, the Utilities Consumer Advocate and the Industrial Power
Consumers Association of Alberta recommended returns on equity ranging from
6.75% to 7.7% and equity ratios ranging from 35% to 37%. AltaLink's expert
witness, as well as all other utility experts, submitted that they are generally
not in favor of implementing a formulaic adjustment mechanism for allowed return
on equity due to the challenges in maintaining the Fair Return Standard through
formulaic adjustments. The interveners are generally in favor of a formula. The
AUC expects to conclude the second stage of the GCOC proceeding in the third
quarter of 2023.

Environmental Laws and Regulations



Each Registrant 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 each Registrant's 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. Each Registrant 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. The discussion
below contains material developments to those matters disclosed in Item 1 of
each Registrant's Annual Report on Form 10-K for the year ended December 31,
2022, and new environmental matters occurring in 2023.

Air Quality Regulations



The Clean Air Act, as well as state laws and regulations impacting air
emissions, provides a framework for protecting and improving the nation's air
quality and controlling sources of air emissions. These laws and regulations
continue to be promulgated and implemented and will impact the operation of
BHE's generating facilities and require them to reduce emissions at those
facilities to comply with the requirements. In addition, the potential adoption
of state or federal clean energy standards, which include low-carbon, non-carbon
and renewable electricity generating resources, may also impact electricity
generators and natural gas providers.

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Mercury and Air Toxics Standards



In March 2011, the EPA proposed a rule that requires coal-fueled generating
facilities to reduce mercury emissions and other hazardous air pollutants
through the establishment of "Maximum Achievable Control Technology" standards.
The final MATS became effective on April 16, 2012, and required that new and
existing coal-fueled generating facilities achieve emission standards for
mercury, acid gases and other non-mercury hazardous air pollutants. Existing
sources were required to comply with the new standards by April 16, 2015, with
the potential for individual sources to obtain an extension of up to one
additional year, at the discretion of the Title V permitting authority, to
complete installation of controls or for transmission system reliability
reasons. The relevant Registrants have completed emission reduction projects and
unit retirements to comply with the final rule's standards for acid gases and
non-mercury metallic hazardous air pollutants.

Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In
April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the
U.S. Supreme Court agreed to hear the MATS appeal on the limited issue of
whether the EPA unreasonably refused to consider costs in determining whether it
is appropriate to regulate hazardous air pollutants emitted by electric
utilities. In June 2015, the U.S. Supreme Court reversed and remanded the MATS
rule, finding that the EPA had acted unreasonably when it deemed cost irrelevant
to the decision to regulate generating facilities, and that cost, including
costs of compliance, must be considered before deciding whether regulation is
necessary and appropriate. In December 2018, the EPA issued a proposed revised
supplemental cost finding for the MATS, as well as the required risk and
technology review under Clean Air Act Section 112. The EPA proposed to determine
that it is not appropriate and necessary to regulate hazardous air pollutant
emissions from generating facilities under Section 112; however, the EPA
proposed to retain the emission standards and other requirements of the MATS
rule, because the EPA did not propose to remove coal- and oil-fueled generating
facilities from the list of sources regulated under Section 112. In May 2020,
the EPA published its decision to repeal the appropriate and necessary findings
in the MATS rule and retain the overall emission standards. The rule took effect
in July 2020. A number of petitions for review were filed in the D.C. Circuit by
parties challenging and supporting the EPA's decision to rescind the appropriate
and necessary finding, which were stayed pending the EPA's plans to revisit the
finding. On January 31, 2022, the EPA proposed several actions relating to the
MATS. The EPA proposed to restore the appropriate and necessary finding to
regulate generating facilities under Clean Air Act Section 112. The EPA
finalized its restoration of the MATS appropriate and necessary finding in
February 2023.

On April 5, 2023, the EPA released a proposal to revise several aspects of the
MATS rule following the agency's review of the 2020 Residual Risk and Technology
Review. The EPA proposes two specific standard changes - one applicable to all
covered units and one specific to the existing lignite subcategory. The EPA
proposes a more stringent standard for emissions of filterable particulate
matter, the surrogate standard for non-mercury metals for coal-fueled electric
generating units. The EPA proposes to reduce the filterable particulate matter
emission standard by two-thirds based on a demonstration that 91% of coal-based
capacity, which has not been identified as retiring before the proposed
compliance period, has an emission rate at or below the proposed limit. The EPA
also proposes to require continuous emissions monitoring for filterable
particulate matter to demonstrate compliance with the revised standard.
Compliance would be due no later than three years after the effective date of a
final rule and the EPA will accept comments on the proposal for 60 days
following its publication in the Federal Register. The relevant Registrants are
not included in the lignite subcategory. The relevant Registrants have
identified that compliance can be achieved with existing controls. Until the EPA
takes final action on the proposal, the full impacts of the rule cannot be
determined.

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Cross-State Air Pollution Rule



The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and
SO2, precursors of ozone and particulate matter, from down-wind sources in the
eastern U.S. to reduce emissions by implementing a plan based on a market-based
cap-and-trade system, emissions reductions, or both. After numerous appeals, the
CSAPR was promulgated to address interstate transport of SO2 and NOx emissions
in 27 Eastern and Midwestern states. In March 2022, the EPA released its Good
Neighbor Rule, which contains proposed revisions to the CSAPR framework and is
intended to address ozone transport for the 2015 ozone NAAQS. In March 2023, the
EPA released the final Good Neighbor Rule. The electric generation sector
remains the key industry regulated by the rule and will have access to emissions
allowance trading beginning in summer 2023. The final rule shifted the maximum
daily backstop rate for coal-fueled generating units, which drives the
installation of new controls or curtailment, to take effect in 2030 instead of
2027. PacifiCorp's Hunter Units 1-3 and Huntington Units 1-2, which do not have
SCR controls, are impacted by the rule. PacifiCorp's 2023 IRP selected the
installation of non-SCR on the Hunter and Huntington Units by 2026 as part of
the preferred portfolio. The level of NOx allowances for the Utah units remains
similar to 2021 levels, with significant reductions for the coal units beginning
in 2026. The daily limit, which takes effect in 2030, will further restrict
operation of units without adequate controls. NV Energy's fossil-fueled units
are also covered by the final rule. North Valmy Units 1 and 2, which do not have
SCR, will require additional controls or reduced operations during the ozone
season if operated beyond 2025. Nevada's regional haze SIP has an enforceable
retirement date for North Valmy Units 1 and 2 of December 31, 2028, and NV
Energy's IRP identified a December 31, 2025, retirement date for the units. The
EPA's updated modeling suggests that Arizona, Iowa and Kansas may be
significantly contributing to nonattainment in downwind states. The EPA intends
to undertake additional assessment of its modeling for these states and will
determine if it is necessary to address obligations for these states in future
actions. The EPA also deferred final action for Wyoming, pending further review
of updated air quality and contribution modeling and analysis. Additional notice
and comment rulemaking, such as a supplemental rule, would be required to
rescind Iowa's approved SIP and incorporate additional states into the program.
The states of Utah and Wyoming challenged the EPA's denial and deferral,
respectively, of their interstate ozone transport SIPs in the Tenth Circuit
Court of Appeals. PacifiCorp also filed petitions with the court opposing the
EPA's action in both states. At the time of filing, at least six other states
have challenged the EPA's action to disapprove SIPs in different regional
federal Courts of Appeal. Until additional rulemaking is completed and
litigation is exhausted, the potential impacts to the relevant Registrants
cannot be determined.

The EPA included additional sectors in the expanded CSAPR program. Relevant to
the Registrants, this includes the pipeline transportation of natural gas.
Requirements for that sector focus on emissions reductions from reciprocating
internal combustion engines involved in the transport of natural gas and take
effect in 2026. There is no access to allowance trading for the non-electric
generation sectors. The EPA excluded emergency engines and engines that do not
operate during the ozone season, included a facility-wide averaging plan and
eased requirements for monitoring. Northern Natural Gas operates 18 affected
units; BHE GT&S operates 157 affected units; and Kern River is not affected by
the final rule.

Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and
implement plans to improve visibility in designated federally protected areas
("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in
Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra
Pacific's fossil-fueled generating facilities are subject to the Clean Air
Visibility Rules. In accordance with the federal requirements, states are
required to submit SIPs that address emissions from sources subject to BART
requirements and demonstrate progress towards achieving natural visibility
requirements in Class I areas by 2064.

In June 2019, the state of Utah incorporated a BART alternative into its SIP for
regional haze planning period one. The BART alternative makes the shutdown of
PacifiCorp's Carbon generating facility enforceable under the SIP and removes
the requirement to install SCR equipment on Hunter Units 1 and 2 and Huntington
Units 1 and 2. The EPA approved the SIP revision with the BART alternative in
October 2020. The EPA's actions also withdrew a prior FIP that required
installation of SCR equipment on Hunter Units 1 and 2 and Huntington Units 1 and
2. On January 19, 2021, Heal Utah, National Parks Conservation Association,
Sierra Club and Utah Physicians for a Healthy Environment filed a petition for
review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. The EPA
defended the SIP, and PacifiCorp and the state of Utah intervened in the
litigation. Oral arguments in HEAL Utah v. EPA were held March 21, 2023. A final
decision from the court is expected by fall 2023. The Utah Air Quality Board
approved the Utah Division of Air Quality's SIP for the regional haze second
planning period on June 6, 2022. The SIP sets mass-based NOx emissions limits
and rate-based SO2 limits for PacifiCorp's Hunter and Huntington generating
facilities to ensure reasonable visibility progress for the second planning
period. The state submitted the SIP to the EPA in August 2022 and the EPA
determined the submission was complete August 22, 2022. The EPA is required to
make a determination on the Utah SIP by August 2023.

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The state of Wyoming issued two regional haze SIPs requiring the installation of
SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled
generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012
and the EPA's approval was upheld on appeal by the Tenth Circuit in October
2014. The EPA's final action on the Wyoming SIP in 2014 approved the state's
plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR
controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units
1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4.
The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave
Johnston Unit 3, where it required the installation of SCR controls by 2019 or,
in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit
3 by 2027, its currently approved depreciable life. The EPA also disapproved a
portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled
generating facility, requiring the installation of SCR controls by 2019.
PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014.
The state of Wyoming and several environmental groups also filed an appeal of
the EPA's final action. In September 2014, the Tenth Circuit issued a stay of
the March 2019 compliance deadline for Wyodak, pending further action by the
Tenth Circuit in the appeal. The parties worked to mediate claims under the
Wyoming regional haze requirements until the abatement on litigation was lifted
in September 2022. Opening briefs were submitted in October 2022. In the
litigation, PacifiCorp objects to the EPA's FIP requiring SCR on the Wyodak
Unit. That requirement in the agency's plan remains stayed by the court.
PacifiCorp has also intervened on behalf of the EPA against claims that Naughton
Units 1 and 2 should have been subject to a SCR requirement. Oral argument will
be held May 16, 2023. PacifiCorp has claimed the Naughton claims are moot but
that a court ruling on the Wyodak claims is necessary to determine whether the
EPA's federal plan complies with the Clean Air Act. Separately, on February 14,
2022, the First Judicial District Court for the State of Wyoming entered a
consent decree reached between the state of Wyoming and PacifiCorp resolving
claims of threatened violations of the Clean Air Act, the Wyoming Environmental
Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim
Bridger facility. No penalties were imposed under the consent decree. Consistent
with the terms and conditions of the consent decree, PacifiCorp must convert Jim
Bridger Units 1 and 2 to natural gas and begin meeting emissions limits
consistent with that conversion by January 1, 2024. The EPA and PacifiCorp
executed an administrative order on consent June 9, 2022, covering compliance
for Jim Bridger Units 1 and 2 under the regional haze rule. The federal order
contains the same emission and operating limits as the Wyoming consent decree
and adds federal approval of the compliance pathway outlined in the state
consent decree, including revision of the SIP to include conversion of Jim
Bridger Units 1 and 2 to natural gas. On December 30, 2022, the Wyoming Air
Quality Division submitted the state-approved revised regional haze SIP
requiring natural gas conversion of Jim Bridger Units 1 and 2 to the EPA for
approval. The plan revision replaces a previous requirement for SCR at the
units. The Wyoming Air Quality Division also issued an air permit for the
natural gas conversion of Jim Bridger Units 1 and 2 on December 28, 2022.
PacifiCorp submitted a notice of compliance to the EPA on March 9, 2023, to
certify completion of the Jim Bridger administrative compliance order through
completion of the requirements to comply with Wyoming's consent decree and
revised SIP submission. PacifiCorp remains subject to the compliance terms of
the Wyoming consent decree as it works to convert Jim Bridger Units 1 and 2 to
natural gas. The EPA is in on-going discussions with Wyoming to finalize a
determination on the SIP revisions, with a decision anticipated by fall 2023.
Wyoming submitted a SIP for the second round of regional haze planning to the
EPA in August 2022 and the EPA determined the submission was complete that same
month. Wyoming determined that no additional controls are necessary on any
Wyoming resources to make reasonable progress under the regional haze rules. The
EPA is required to make a determination on the Wyoming SIP by August 2023.

The state of Colorado regional haze SIP requires SCR equipment at Craig Unit 2
and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of
those regional haze compliance projects are in-service. In addition, in February
2015, the state of Colorado finalized an amendment to its regional haze SIP
relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to
require the installation of SCR controls by 2021. In September 2016, the owners
of Craig Units 1 and 2 reached an agreement with state and federal agencies and
certain environmental groups that were parties to the previous settlement
requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR
installation, or alternatively to remove the unit from coal-fueled service by
August 31, 2021, with an option to convert the unit to natural gas by August 31,
2023, in lieu of SCR installation. The terms of the agreement were approved by
the Colorado Air Quality Board in December 2016, incorporated into an amended
Colorado regional haze SIP in 2017 and approved by the EPA in August 2018.
PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in
its 2023 IRP.

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Nevada, Utah and Wyoming each submitted regional haze SIPs for the regional haze
second planning period to the EPA in August 2022. The EPA has 18 months to
approve or disapprove all or parts of the states' plans. On August 25, 2022, the
EPA promulgated a finding of failure to submit a SIP for the regional haze
second planning period for 15 states, including Iowa. The finding establishes a
two-year deadline for the agency to promulgate FIPs to address the requirements,
unless prior to promulgating a FIP, the state submits, and the agency approves,
a SIP meeting the requirements. The finding says the agency intends to continue
to work with states in developing approvable SIP submittals in a timely manner.
The Iowa Department of Natural Resources continues to work with the EPA on
development of its SIP. On February 13, 2023, Iowa issued a draft SIP and
accepted comment on the draft plan through March 16, 2023. Iowa proposes to
require operational improvements to existing control equipment at MidAmerican
Energy's Louisa Generation Station and Walter Scott Jr. Energy Center - Unit 3.
Iowa anticipates submitting a final plan to the EPA in summer 2023.

Water Quality Standards



In November 2015, the EPA published final effluent limitation guidelines and
standards for the steam electric power generating sector which, among other
things, regulate the discharge of bottom ash transport water, fly ash transport
water, combustion residual leachate and non-chemical metal cleaning wastes. In
November 2019, the EPA proposed updates to the 2015 rule, specifically
addressing flue gas desulfurization wastewater and bottom ash transport water.
The rule took effect in December 2020. The final rule changes the
technology-basis for treatment of flue gas desulfurization wastewater and bottom
ash transport water, revises the voluntary incentives program for flue gas
desulfurization wastewater, and adds subcategories for high-flow units, low
utilization units, and those that will transition away from coal combustion by
2028. While most of the issues raised by this rule are already being addressed
through the CCR rule and are not expected to impose significant additional
requirements, the Dave Johnston generating facility is impacted by the rule's
bottom ash handling requirements at Units 1 and 2. The generating facility
submitted notice to the Wyoming Department of Environmental Quality that it will
either achieve a cessation of coal combustion at Units 1 and 2 by December 31,
2028, or install bottom ash transport treatment technology by December 31, 2025.
On March 8, 2023, the EPA proposed additional changes to the effluent
limitations guidelines to replace the 2020 rule and provide stricter limits for
bottom ash transport water, flue gas desulfurization wastewater and coal
combustion residual leachate. The relevant Registrants use a combination of zero
discharge, enrollment in cessation-of-coal subcategory and dry bottom ash
handling to manage the affected wastestreams. As a result, significant impacts
are not anticipated. However, until the EPA takes final action on the proposal,
the full impacts of the rule cannot be determined. The EPA will accept public
comments through May 30, 2023, and intends to finalize a rule by spring 2024.

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. Estimates are used for, but
not limited to, the accounting for the effects of certain types of regulation,
impairment of goodwill and long-lived assets, pension and other postretirement
benefits, income taxes and revenue recognition - unbilled revenue. For
additional discussion of the Company's critical accounting estimates, see Item 7
of the Company's Annual Report on Form 10-K for the year ended December 31,
2022. There have been no significant changes in the Company's assumptions
regarding critical accounting estimates since December 31, 2022.

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                        PacifiCorp and its subsidiaries
                         Consolidated Financial Section

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                                     PART I

Item 1.Financial Statements

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