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 businesses principally engaged in the energy industry and is a
consolidated subsidiary of Berkshire Hathaway. As of August 4, 2022, 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, beneficially
owned 92% and 8%, respectively, of BHE's 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, one of which owns a liquefied natural gas ("LNG") export, import and
storage facility, in the U.S., 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, the largest residential real estate brokerage firm 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
entities, including MidAmerican Energy Services, LLC, corporate functions and
intersegment eliminations.

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Results of Operations for the Second Quarter and First Six Months of 2022 and 2021



Overview

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



                                                         Second Quarter                                                     First Six Months
                                     2022             2021                    Change                     2022              2021                    Change
Operating revenue:
PacifiCorp                        $ 1,314          $ 1,298          $   16                 1  %       $  2,611          $  2,540          $   71               3  %
MidAmerican Funding                   897              693             204                29             1,902             1,760             142               8
NV Energy                             899              767             132                17             1,592             1,358             234              17
Northern Powergrid                    345              280              65                23               660               580              80              14
BHE Pipeline Group                    856              706             150                21             1,891             1,799              92                  5
BHE Transmission                      183              182               1                 1               366               362               4               1
BHE Renewables                        294              267              27                10               461               457               4               1
HomeServices                        1,672            1,763             (91)               (5)            2,879             2,995            (116)             (4)
BHE and Other                         152              108              44                41               280               294             (14)             (5)
Total operating revenue           $ 6,612          $ 6,064          $  548                 9  %       $ 12,642          $ 12,145          $  497               4  %

Earnings on common shares:
PacifiCorp                        $    83          $   226          $ (143)              (63) %       $    213          $    395          $ (182)            (46) %
MidAmerican Funding                   204              211              (7)               (3)              445               355              90              25
NV Energy                              93              100              (7)               (7)              122               134             (12)             (9)
Northern Powergrid                     71              (25)             96                    *            182                79             103              *
BHE Pipeline Group                    199              100              99                99               521               483              38               8
BHE Transmission                       62               60               2                 3               124               119               5               4
BHE Renewables(1)                     249              181              68                   38            353               197             156              79
HomeServices                           84              135             (51)              (38)              105               219            (114)            (52)
BHE and Other                       1,839            1,256             583                46               674               229             445              *

Total earnings on common shares $ 2,884 $ 2,244 $ 640

              29  %       $  2,739          $  2,210          $  529              24  %

(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 $640 million for the second quarter of 2022
compared to 2021. The second quarter of 2022 included a pre-tax unrealized gain
of $2,557 million ($2,020 million after-tax) compared to a pre-tax unrealized
gain in the second quarter of 2021 of $1,954 million ($1,420 million after-tax)
on the Company's investment in BYD Company Limited. Excluding the impact of this
item, adjusted earnings on common shares for the second quarter of 2022 was $864
million, an increase of $40 million, or 5%, compared to adjusted earnings on
common shares in the second quarter of 2021 of $824 million.

Earnings on common shares increased $529 million for the first six months of
2022 compared to 2021. The first six months of 2022 included a pre-tax
unrealized gain of $1,310 million ($1,035 million after-tax) compared to a
pre-tax unrealized gain in the first six months of 2021 of $830 million ($602
million after-tax) on the Company's investment in BYD Company Limited. Excluding
the impact of this item, adjusted earnings on common shares for the first six
months of 2022 was $1,704 million, an increase of $96 million, or 6%, compared
to adjusted earnings on commons shares in the first six months of 2021 of $1,608
million.

                                       29
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The increases in earnings on common shares for the second quarter and for the first six months of 2022 compared to 2021 were primarily due to the following:



•The Utilities' earnings decreased $157 million for the second quarter and $104
million for the first six months of 2022 compared to 2021, reflecting higher
operations and maintenance expense, higher depreciation and amortization expense
and unfavorable investment earnings, partially offset by higher electric utility
margin and a favorable income tax benefit from higher PTCs recognized. Electric
retail customer volumes increased 1.3% for the first six months of 2022 compared
to 2021, primarily due to higher customer usage and an increase in the average
number of customers;

•Northern Powergrid's earnings increased $96 million for the second quarter and
$103 million for the first six months of 2022 compared to 2021, primarily due to
a deferred income tax charge of $109 million related to a June 2021 enacted
increase in the United Kingdom corporate income tax rate from 19% to 25%
effective April 1, 2023;

•BHE Pipeline Group's earnings increased $99 million for the second quarter and
$38 million for the first six months of 2022 compared to 2021, largely due to
higher earnings at BHE GT&S from favorable state unitary income tax adjustments,
the impacts of the EGTS general rate case and lower operations and maintenance
expense. In addition, earnings for the first six months decreased from the
effects of higher margins on natural gas sales and higher transportation revenue
in the first quarter of 2021 at Northern Natural Gas from the February 2021
polar vortex weather event;

•BHE Renewables' earnings increased $68 million for the second quarter and $156
million for the first six months of 2022 compared to 2021, primarily due to
higher operating revenue from owned renewable energy projects and higher
earnings from tax equity investments, with the first six months being positively
impacted by the unfavorable impacts in the first quarter of 2021 from the
February 2021 polar vortex weather event;

•HomeServices' earnings decreased $51 million for the second quarter and $114
million for the first six months of 2022 compared to 2021, reflecting lower
earnings from mortgage services mainly from a decrease in funded volumes and
lower earnings from brokerage and settlement services largely attributable to a
decrease in closed units at existing companies; and

•BHE and Other's earnings increased $583 million for the second quarter and $445
million for the first six months of 2022 compared to 2021, mainly due to $600
million and $433 million, respectively, of favorable changes in the after-tax
unrealized position of the Company's investment in BYD Company Limited and lower
dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain
subsidiaries of Berkshire Hathaway, partially offset by lower federal income tax
credits recognized on a consolidated basis.

Reportable Segment Results

PacifiCorp



Operating revenue increased $16 million for the second quarter of 2022 compared
to 2021, primarily due to higher wholesale and other revenue of $30 million,
partially offset by lower retail revenue of $14 million. Wholesale and other
revenue increased primarily due to higher average wholesale prices and higher
wheeling revenue. Retail revenue decreased primarily due to lower retail volumes
of $42 million, partially offset by price impacts of $28 million from higher
average retail rates primarily due to tariff changes. Retail customer volumes
decreased 3.3%, primarily due to the unfavorable impact of weather and lower
customer usage, partially offset by an increase in the average number of
customers.

Earnings decreased $143 million for the second quarter of 2022 compared to 2021,
primarily due to higher operations and maintenance expense of $120 million, an
unfavorable income tax benefit and unfavorable changes in the cash surrender
value of corporate-owned life insurance policies, partially offset by higher
utility margin of $6 million. Operations and maintenance expense increased
mainly due to an increase in the loss accruals associated with the September
2020 wildfires, net of estimated insurance recoveries, and higher general and
plant maintenance costs. Utility margin increased primarily due to lower
purchased power costs and the higher wholesale and other revenue, partially
offset by higher thermal generation costs, the lower retail revenue and lower
deferred net power costs in accordance with established adjustment mechanisms.
The unfavorable income tax benefit was largely due to lower PTCs recognized of
$22 million and the effects of ratemaking of $18 million.


                                       30
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Operating revenue increased $71 million for the first six months of 2022
compared to 2021, primarily due to higher wholesale and other revenue of $45
million and higher retail revenue of $26 million. Wholesale and other revenue
increased primarily due to higher average wholesale prices and higher wheeling
revenue. Retail revenue increased primarily due to price impacts of $43 million
from higher average retail rates largely due to tariff changes, partially offset
by lower retail volumes of $17 million. Retail customer volumes decreased 0.7%,
primarily due to the unfavorable impact of weather and lower customer usage,
partially offset by an increase in the average number of customers.

Earnings decreased $182 million for the first six months of 2022 compared to
2021, primarily due to higher operations and maintenance expense of $138
million, an unfavorable income tax benefit, higher depreciation and amortization
expense of $20 million, mainly from additional assets placed in-service, and
unfavorable changes in the cash surrender value of corporate-owned life
insurance policies, partially offset by higher utility margin of $20 million.
Operations and maintenance expense increased mainly due to an increase in loss
accruals related to the September 2020 wildfires, net of estimated insurance
recoveries, and higher general and plant maintenance costs. Utility margin
increased primarily due to the higher retail, wholesale and other revenues,
partially offset by higher thermal generation costs. The unfavorable income tax
benefit was largely due to lower PTCs recognized of $27 million and the effects
of ratemaking of $27 million.

MidAmerican Funding

Operating revenue increased $204 million for the second quarter of 2022 compared
to 2021, primarily due to higher electric operating revenue of $139 million and
higher natural gas operating revenue of $65 million. Electric operating revenue
increased due to higher retail revenue of $77 million and higher wholesale and
other revenue of $62 million. Electric retail revenue increased primarily due to
higher recoveries through adjustment clauses of $59 million (fully offset in
expense, primarily cost of sales) and higher customer volumes of $11 million.
Electric wholesale and other revenue increased mainly due to higher average
wholesale per-unit prices of $59 million. Electric retail customer volumes
increased 3.3% due to higher customer usage and the favorable impact of weather.
Natural gas operating revenue increased due to higher purchased gas adjustment
recoveries of $63 million (fully offset in cost of sales), primarily from a
higher average per-unit cost of natural gas sold.

Earnings decreased $7 million for the second quarter of 2022 compared to 2021,
primarily due to higher depreciation and amortization expense of $68 million,
unfavorable changes in the cash surrender value of corporate-owned life
insurance policies, higher operations and maintenance expense of $16 million and
higher interest expense of $5 million, partially offset by higher electric
utility margin of $68 million, a favorable income tax benefit and higher
allowances for equity and borrowed funds used during construction of $9 million.
Depreciation and amortization expense increased primarily from the impacts of
certain regulatory mechanisms and additional assets placed in-service. Electric
utility margin increased primarily due to the higher retail and wholesale
revenues, partially offset by higher purchased power costs. The favorable income
tax benefit was largely due to higher PTCs recognized of $39 million from higher
wind-powered generation, partially offset by the effects of ratemaking.

Operating revenue increased $142 million for the first six months of 2022
compared to 2021, primarily due to higher electric operating revenue of
$202 million, partially offset by lower natural gas operating revenue of
$51 million. Electric operating revenue increased due to higher wholesale and
other revenue of $105 million and higher retail revenue of $97 million. Electric
wholesale and other revenue increased mainly due to higher average wholesale
per-unit prices of $78 million and higher wholesale volumes of $28 million.
Electric retail revenue increased primarily due to higher recoveries through
adjustment clauses of $63 million (fully offset in expense, primarily cost of
sales) and higher customer volumes of $28 million. Electric retail customer
volumes increased 4.4% due to higher customer usage and the favorable impact of
weather. Natural gas operating revenue decreased due to lower purchased gas
adjustment recoveries of $71 million (fully offset in cost of sales), primarily
from a lower average per-unit cost of natural gas sold driven largely by the
February 2021 polar vortex weather event, partially offset by the impacts of
certain regulatory recovery mechanisms of $5 million, the impacts of tax reform
of $5 million and the favorable impact of weather of $5 million.

Earnings increased $90 million for the first six months of 2022 compared to
2021, primarily due to higher electric utility margin of $157 million, a
favorable income tax benefit, higher natural gas utility margin of $20 million
and higher allowances for equity and borrowed funds used during construction of
$20 million, partially offset by higher depreciation and amortization expense of
$111 million, unfavorable changes in the cash surrender value of corporate-owned
life insurance policies, higher operations and maintenance expense of $15
million, higher interest expense of $9 million and lower nonregulated utility
margin of $8 million. Electric utility margin increased primarily due to the
higher wholesale and retail revenues, partially offset by higher purchased power
costs. The favorable income tax benefit was mainly due to higher PTCs recognized
of $91 million from higher wind-powered generation, partially offset by the
effects of ratemaking. Depreciation and amortization expense increased primarily
from the impacts of certain regulatory mechanisms and additional assets placed
in-service.

                                       31
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NV Energy



Operating revenue increased $132 million for the second quarter of 2022 compared
to 2021, primarily due to higher electric operating revenue of $123 million and
higher natural gas operating revenue of $8 million. Electric operating revenue
increased primarily due to higher fully-bundled energy rates (fully offset in
cost of sales) of $121 million and higher regulatory-related revenue deferrals
of $11 million, partially offset by unfavorable price impacts from changes in
sales mix of $12 million. Electric retail customer volumes increased 0.4%,
primarily due to an increase in the average number of customers, partially
offset by the unfavorable impact of weather. Natural gas operating revenue
increased primarily due to a higher average per-unit cost of natural gas sold
(fully offset in cost of sales).

Earnings decreased $7 million for the second quarter of 2022 compared to 2021,
mainly due to unfavorable changes in the cash surrender value of corporate-owned
life insurance policies, higher depreciation and amortization expense of $3
million, primarily from additional plant placed in-service, and higher
operations and maintenance expense of $2 million, primarily from an unfavorable
change in earnings sharing at the Nevada Utilities, partially offset by higher
interest and dividend income of $9 million, primarily from carrying charges on
regulatory balances.

Operating revenue increased $234 million for the first six months of 2022
compared to 2021, primarily due to higher electric operating revenue of $213
million and higher natural gas operating revenue of $21 million. Electric
operating revenue increased primarily due to higher fully-bundled energy rates
(fully offset in cost of sales) of $209 million, higher regulatory-related
revenue deferrals of $8 million and higher transmission and wholesale revenue of
$5 million, partially offset by unfavorable price impacts from changes in sales
mix of $7 million. Electric retail customer volumes increased 2.0%, primarily
due to an increase in the average number of customers and higher customer usage,
partially offset by the unfavorable impact of weather. Natural gas operating
revenue increased primarily due to a higher average per-unit cost of natural gas
sold (fully offset in cost of sales).

Earnings decreased $12 million for the first six months of 2022 compared to
2021, mainly due to unfavorable changes in the cash surrender value of
corporate-owned life insurance policies, higher operations and maintenance
expense of $8 million, primarily from an unfavorable change in earnings sharing
at the Nevada Utilities and increased plant operations and maintenance expenses,
and higher depreciation and amortization expense of $6 million, primarily from
additional plant placed in-service, partially offset by higher interest and
dividend income of $14 million, primarily from carrying charges on regulatory
balances.

Northern Powergrid

Operating revenue increased $65 million for the second quarter of 2022 compared
to 2021, primarily due to higher distribution revenue of $60 million and revenue
from a gas project that commenced commercial operation in March 2022 totaling
$40 million, partially offset by $40 million from the stronger U.S. dollar.
Distribution revenue increased due to the recovery of Supplier of Last Resort
payments totaling $45 million (fully offset in cost of sales) and higher tariff
rates of $25 million, partially offset by a 4.0% decline in units distributed of
$9 million.

Earnings increased $96 million for the second quarter of 2022 compared to 2021,
primarily due to a deferred income tax charge of $109 million related to a June
2021 enacted increase in the United Kingdom corporate income tax rate from 19%
to 25% effective April 1, 2023 and the higher distribution tariff rates,
partially offset by higher distribution-related operating and depreciation
expenses of $27 million, including higher storm-related costs, $9 million from
the stronger U.S. dollar and the decline in units distributed.

Operating revenue increased $80 million for the first six months of 2022
compared to 2021, primarily due to higher distribution revenue of $70 million
and revenue from a gas project that commenced commercial operation in March 2022
totaling $50 million, partially offset by $45 million from the stronger U.S.
dollar. Distribution revenue increased due to the recovery of Supplier of Last
Resort payments totaling $45 million (fully offset in cost of sales) and higher
tariff rates of $39 million, partially offset by a 3.3% decline in units
distributed of $12 million.

Earnings increased $103 million for the first six months of 2022 compared to
2021, primarily due to a deferred income tax charge of $109 million related to a
June 2021 enacted increase in the United Kingdom corporate income tax rate from
19% to 25% effective April 1, 2023 and the higher distribution tariff rates,
partially offset by higher distribution-related operating and depreciation
expenses of $27 million, including higher storm-related costs, the decline in
units distributed and $8 million from the stronger U.S. dollar.


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BHE Pipeline Group



Operating revenue increased $150 million for the second quarter of 2022 compared
to 2021, primarily due to higher non-regulated revenue of $58 million (largely
offset in cost of sales) at BHE GT&S from favorable pricing, an increase in
regulated gas transportation and storage services rates due to an agreement in
principle for EGTS' general rate case of $25 million, higher LNG variable
revenue of $25 million at Cove Point, higher transportation revenue of $17
million at Northern Natural Gas due to higher volumes and rates and higher gas
sales of $9 million (largely offset in cost of sales) related to system
balancing activities at Northern Natural Gas.

Earnings increased $99 million for the second quarter of 2022 compared to 2021,
primarily due to higher earnings of $90 million at BHE GT&S largely due to
favorable state unitary income tax adjustments, the impacts of the EGTS general
rate case, lower operations and maintenance expense, favorable valuations of
system gas and higher margin from non-regulated activities.

Operating revenue increased $92 million for the first six months of 2022
compared to 2021, primarily due to higher non-regulated revenue of $69 million
(largely offset in cost of sales) at BHE GT&S from favorable pricing, higher LNG
variable revenue of $38 million at Cove Point and an increase in regulated gas
transportation and storage services rates due to an agreement in principle for
EGTS' general rate case of $25 million, partially offset by lower gas sales of
$32 million related to system balancing activities at Northern Natural Gas,
lower gas sales of $17 million at EGTS used for operational and system balancing
purposes and lower transportation revenue of $3 million at Northern Natural Gas.
The variances in gas sales and transportation revenue at Northern Natural Gas
included favorable impacts recognized in the first quarter of 2021 of $77
million and $49 million, respectively, from the February 2021 polar vortex
weather event. Excluding this item, gas sales increased $45 million (largely
offset in cost of sales) and transportation revenue increased $46 million due to
higher volumes and rates.

Earnings increased $38 million for the first six months of 2022 compared to
2021, primarily due to higher earnings of $99 million at BHE GT&S, partially
offset by lower earnings of $60 million at Northern Natural Gas. Earnings at BHE
GT&S increased mainly due to favorable state unitary income tax adjustments, the
impacts of the EGTS general rate case, lower operations and maintenance expense,
favorable property tax assessments, increased earnings at Cove Point and higher
margin from non-regulated activities. Earnings at Northern Natural Gas decreased
as the higher gross margin on gas sales and higher transportation revenue in the
first quarter of 2021 from the February 2021 polar vortex weather event were
partially offset by the favorable transportation revenue due to higher volumes
and rates.

BHE Transmission

Operating revenue increased $1 million for the second quarter and $4 million for
the first six months of 2022 compared to 2021, primarily due to higher
non-regulated revenue and higher revenue at AltaLink from recovery of higher
costs, partially offset by $7 million from the weaker U.S. dollar.

Earnings increased $2 million for the second quarter and $5 million for the first six months of 2022 compared to 2021, primarily due to the higher non-regulated revenue and improved equity earnings at Electric Transmission Texas, LLC, partially offset by $2 million from the weaker U.S. dollar.

BHE Renewables



Operating revenue increased $27 million for the second quarter of 2022 compared
to 2021, primarily due to higher wind, geothermal and solar revenues of $51
million from higher generation and pricing, partially offset by unfavorable
changes in the valuation of certain derivative contracts totaling $14 million
and lower natural gas revenues of $13 million from lower generation.

Earnings increased $68 million for the second quarter of 2022 compared to 2021,
primarily due to higher wind earnings of $58 million and higher geothermal
earnings of $11 million, largely due to the higher operating revenue and lower
maintenance costs. Wind earnings increased primarily due to higher earnings from
owned projects of $31 million, largely from the higher operating revenue and
favorable production tax credits offset by the unfavorable derivative contract
valuations, and higher earnings from tax equity investments of $27 million,
mainly from higher production tax credits offset by unfavorable performance.

                                       33
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Operating revenue increased $4 million for the first six months of 2022 compared
to 2021, primarily due to higher wind, geothermal and solar revenues of $77
million from higher generation and pricing, partially offset by unfavorable
changes in the valuation of certain derivative contracts totaling $57 million,
lower natural gas revenues of $10 million from lower generation and lower hydro
revenues of $6 million due to the transfer of the Casecnan generating facility
to the Philippine National Irrigation Administration in December 2021.

Earnings increased $156 million for the first six months of 2022 compared to
2021, primarily due to higher wind earnings of $150 million, higher solar
earnings of $10 million, mainly due to the higher operating revenue, and higher
geothermal earnings of $9 million, largely due to the higher operating revenue
and lower maintenance costs, partially offset by lower hydro earnings of $10
million due to the Casecnan generating facility transfer. Wind earnings
increased primarily due to higher earnings from tax equity investments of $123
million, mainly as a result of the unfavorable impacts in the first quarter of
2021 from the February 2021 polar vortex weather event and higher production tax
credits offset by unfavorable performance, and higher earnings from owned
projects of $27 million, largely from the higher operating revenue and favorable
production tax credits offset by the unfavorable derivative contract valuations.

HomeServices

Operating revenue decreased $91 million for the second quarter of 2022 compared to 2021, primarily due to lower mortgage revenue of $63 million from a 29% decrease in funded volume due to a decline in refinance activity and lower brokerage and settlement services revenue of $26 million from a decrease in closed transaction volumes.



Earnings decreased $51 million for the second quarter of 2022 compared to 2021,
primarily due to lower earnings from brokerage and settlement services of $33
million, largely attributable to the decrease in closed units at existing
companies, and lower earnings from mortgage services of $22 million from the
decrease in funded volume.

Operating revenue decreased $116 million for the first six months of 2022
compared to 2021, primarily due to lower mortgage revenue of $160 million from a
34% decrease in funded volume due to a decline in refinance activity, partially
offset by higher brokerage revenue of $67 million from a 3% increase in closed
transaction volume. The increase in brokerage volume was due to acquisitions and
a 10% increase in average sales price at existing companies offset by 15% fewer
closed units at existing companies.

Earnings decreased $114 million for the first six months of 2022 compared to
2021, primarily due to lower earnings from mortgage services of $71 million and
lower earnings from brokerage and settlement services of $49 million due to the
decrease in closed units at existing companies. Earnings from mortgage services
were lower primarily due to the decrease in funded volumes, partially offset by
favorable operating expense variances.

BHE and Other



Operating revenue increased $44 million for the second quarter of 2022 compared
to 2021, primarily due to higher electricity and natural gas sales revenue at
MidAmerican Energy Services, LLC, from favorable pricing and higher electricity
volumes offset by lower natural gas volumes.

Earnings increased $583 million for the second quarter of 2022 compared to 2021,
primarily due to the $600 million favorable comparative change in the after-tax
unrealized position of the Company's investment in BYD Company Limited, lower
corporate costs and $25 million of lower dividends on BHE's 4.00% Perpetual
Preferred Stock issued to certain subsidiaries of Berkshire Hathaway, partially
offset by $41 million of lower federal income tax credits recognized on a
consolidated basis, unfavorable changes in the cash surrender value of
corporate-owned life insurance policies and higher BHE corporate interest
expense from an April 2022 debt issuance.

                                       34
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Operating revenue decreased $14 million for the first six months of 2022 compared to 2021, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from unfavorable pricing offset by higher volumes, partially offset by higher natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes.



Earnings increased $445 million for the first six months of 2022 compared to
2021, primarily due to the $433 million favorable comparative change in the
after-tax unrealized position of the Company's investment in BYD Company
Limited, lower corporate costs, $46 million of lower dividends on BHE's 4.00%
Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway
and higher earnings of $45 million at MidAmerican Energy Services, LLC, mainly
due to favorable changes in unrealized positions on derivative contracts,
partially offset by $95 million of lower federal income tax credits recognized
on a consolidated basis, unfavorable changes in the cash surrender value of
corporate-owned life insurance policies and higher BHE corporate interest
expense from an April 2022 debt issuance.

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, 2021 for further discussion regarding the limitation of
distributions from BHE's subsidiaries.

As of June 30, 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  $    61          $       390          $        497          $   83          $      327          $        60          $             294          $         369          $  2,081

Credit facilities(1)         3,500                1,200                 1,509             650                 259                  835                      3,400                      -            11,353
Less:
Short-term debt               (385)                   -                     -               -                 (15)                (378)                    (1,170)                     -            (1,948)
Tax-exempt bond support
and letters of credit            -                 (218)                 (370)              -                   -                   (1)                         -                      -              (589)
Net credit facilities        3,115                  982                 1,139             650                 244                  456                      2,230                      -             8,816

Total net liquidity        $ 3,176          $     1,372          $      1,636          $  733          $      571          $       516          $           2,524          $         369          $ 10,897
Credit facilities:
Maturity dates                   2025                 2025            2023, 2025            2025          2024, 2026           2023, 2026           2022, 2023, 2026

(1)Includes $15 million drawn on a capital expenditure credit facility at Northern Powergrid Holdings.

Operating Activities



Net cash flows from operating activities for the six-month periods ended
June 30, 2022 and 2021 were $5.1 billion and $4.2 billion, respectively. The
increase was primarily due to changes in working capital and favorable income
tax cash flows.

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.


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Investing Activities



Net cash flows from investing activities for the six-month periods ended
June 30, 2022 and 2021 were $(3.5) billion and $(3.0) billion, respectively. The
change was primarily due to higher capital expenditures of $534 million. Refer
to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities



Net cash flows from financing activities for the six-month period ended June 30,
2022 was $(605) million. Sources of cash totaled $2,188 million and consisted of
proceeds from subsidiary debt issuances totaling $1.2 billion and proceeds from
BHE senior debt issuances totaling $987 million. Uses of cash totaled $2,793
million and consisted mainly of purchases of common stock totaling $870 million,
preferred stock redemptions of $800 million, repayments of subsidiary debt
totaling $542 million, distributions to noncontrolling interests of $246 million
and net repayments of short-term debt totaling $54 million.

For discussions of recent financing and BHE shareholders' equity transactions,
refer to Notes 4 and 10 of Notes to Consolidated Financial Statements in Part I,
Item 1 of this Form 10-Q.

Net cash flows from financing activities for the six-month period ended June 30,
2021 was $(1.2) billion. Sources of cash totaled $784 million and consisted of
proceeds from subsidiary debt issuances totaling $539 million and net proceeds
from short-term debt of $245 million. Uses of cash totaled $2.0 billion and
consisted mainly of repayments of subsidiary debt totaling $1.2 billion,
repayments of BHE senior debt totaling $450 million and distributions to
noncontrolling interests of $234 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
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.

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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):

                                                   Six-Month Periods          Annual
                                                    Ended June 30,           Forecast
                                                   2021          2022          2022
           Capital expenditures by business:
           PacifiCorp                          $      819      $   894

$ 2,279


           MidAmerican Funding                        720          862

1,913


           NV Energy                                  365          541

1,228


           Northern Powergrid                         369          450

776


           BHE Pipeline Group                         308          457         1,252
           BHE Transmission                           156           95           210
           BHE Renewables                              80           60           185
           HomeServices                                18           20            55
           BHE and Other(1)                            13            3            16
           Total                               $    2,848      $ 3,382      $  7,914


           Capital expenditures by type:
           Wind generation                        $   483      $   300

$ 886


           Electric distribution                      817          815

1,763


           Electric transmission                      339          620

1,773


           Natural gas transmission and storage       308          336          976
           Solar generation                            67          100          230
           Other                                      834        1,211        2,286
           Total                                  $ 2,848      $ 3,382      $ 7,914

(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, 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 $5 million and $172 million for the six-month periods ended June 30,
2022 and 2021, respectively. Planned spending for the construction of additional
wind-powered generating facilities totals $106 million for the remainder of
2022.

•Repowering of wind-powered generating facilities at MidAmerican Energy totaling
$214 million and $82 million for the six-month periods ended June 30, 2022 and
2021, respectively. Planned spending for the repowering of wind-powered
generating facilities totals $314 million for the remainder of 2022. 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. The rate at which PTCs are re-established for
a facility depends upon the date construction begins. Of the 593 MWs of current
repowering projects not in-service as of June 30, 2022, 292 MWs are currently
expected to qualify for 80% of the PTCs available for 10 years following each
facility's return to service and 301 MWs are expected to qualify for 60% of such
credits.

•Construction of wind-powered generating facilities at PacifiCorp totaling $4
million and $79 million for the six-month periods ended June 30, 2022 and 2021,
respectively. Construction includes 516 MWs of new wind-powered generating
facilities that were placed in-service in 2021. Planned spending for the
construction of additional wind-powered generating facilities totals $24 million
for the remainder of 2022. The energy production from the new wind-powered
generating facilities placed in-service by the end of 2024 is expected to
qualify for 60% of the federal PTCs available for 10 years once the equipment is
placed in-service.

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•Planned acquisition and repowering of two wind-powered generating facilities by
PacifiCorp totaling $7 million and $2 million (excluding the 2021 sale of wind
turbines) for the six-month periods ended June 30, 2022 and 2021, respectively.
In 2021, PacifiCorp sold wind turbines previously acquired from a third party to
BHE Wind, LLC, an indirect wholly owned subsidiary of BHE, for $6 million. The
repowered facilities are expected to be placed in-service in 2023 and 2024.
Planned spending for acquiring and repowering generating facilities totals $14
million for the remainder of 2022.

•Repowering of wind-powered generating facilities at BHE Renewables totaling $45 million for the six-month period ended June 30, 2022. Planned spending for repowering generating facilities totals $43 million for the remainder of 2022.



•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 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 investment primarily reflects planned costs for the
416-mile, 500-kV high-voltage transmission line between the Aeolus substation
near Medicine Bow, Wyoming and the Clover substation near Mona, Utah; the
59-mile, 230-kV high-voltage transmission line between the Windstar substation
near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV
high-voltage transmission line from the Longhorn substation near Boardman,
Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these
segments totaled $296 million and $35 million for the six-month periods ended
June 30, 2022 and 2021, respectively. Planned spending for these Energy Gateway
Transmission segments to be placed in-service in 2024-2026 totals $614 million
for the remainder of 2022.

•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 the Mira Loma
substations; and a 38-mile, 345-kV transmission line from the new Ft. Churchill
substation to the Robinson Summit substations. Expenditures for the expansion
program and other growth projects totaled $60 million and $41 million for the
six-month periods ended June 30, 2022 and 2021, respectively. Planned spending
for the expansion program estimated to be placed in-service in 2026-2028 and
other growth projects totals $109 million for the remainder of 2022.

•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 the
Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression
projects. Operating expenditures include, among other items, spending for asset
modernization, pipeline integrity projects and natural gas transmission, storage
and liquefied natural gas 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 MidAmerican Energy
totaling 141 MWs of small- and utility-scale solar generation, with total spend
of $77 million and $63 million for the six-month periods ended June 30, 2022 and
2021, respectively and planned spending of $63 million for the remainder of
2022.

•Construction of a solar-powered generating facility at Nevada Power totaling
$23 million and $5 million for the six-month periods ended June 30, 2022 and
2021, respectively and planned spending of $67 million for the remainder of
2022. 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.

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•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 coal combustion residuals.

Material Cash Requirements



As of June 30, 2022, 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, 2021, other than those disclosed in
Notes 4 and 8 of the Notes to Consolidated Financial Statements in Part I, Item
1 of this Form 10-Q.

Quad Cities Generating Station Operating Status



Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation
Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1,
2022), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad
Cities Station") of which MidAmerican Energy has a 25% ownership interest,
announced on June 2, 2016, its intention to shut down Quad Cities Station on
June 1, 2018. In December 2016, Illinois passed legislation creating a zero
emission standard, which went into effect June 1, 2017. The zero emission
standard requires the Illinois Power Agency to purchase ZECs and recover the
costs from certain ratepayers in Illinois, subject to certain limitations. The
proceeds from the ZECs will provide Constellation Energy additional revenue
through 2027 as an incentive for continued operation of Quad Cities Station.
MidAmerican Energy will not receive additional revenue from the subsidy.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer
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, resulting in a
higher offer that may not clear the capacity market. Prior to December 19, 2019,
the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM
MOPR to include existing resources would require exclusion of ZEC compensation
when bidding into future capacity auctions, resulting in an increased risk of
Quad Cities Station not receiving capacity revenues in future auctions.

On December 19, 2019, the FERC 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 in May 2021.
While the FERC included some limited exemptions, no exemptions were available to
state-supported nuclear resources, such as Quad Cities Station. The FERC
provided no new mechanism for accommodating state-supported resources 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. In response to the FERC's order, the
PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed
tariff language reflecting the FERC's directives and a schedule for resuming
capacity auctions. On April 16, 2020, the FERC issued an order largely denying
requests for rehearing of the FERC's December 2019 order but granting a few
clarifications that required an additional PJM compliance filing, which the PJM
submitted on June 1, 2020. A number of parties, including Constellation Energy,
have filed petitions for review of the FERC's orders in this proceeding, which
remain pending before the D.C. Circuit.

As a result, the MOPR applied to Quad Cities Station in the capacity auction for
the 2022-2023 planning year, which prevented Quad 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 at the FERC on July 30, 2021, and, on September
29, 2021, the PJM's proposed MOPR reforms became effective by operation of law.
Under the new tariff provisions, the MOPR will no longer apply to Quad Cities
Station. Requests for rehearing of the FERC's notice establishing the effective
date for the PJM's proposed market reforms were filed in October 2021 and denied
by operation of law on November 4, 2021. Several parties have filed petitions
for review of the FERC's orders in this proceeding, which remain pending before
the Court of Appeals for the Third Circuit. Constellation Energy is strenuously
opposing these appeals.

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Assuming the continued effectiveness of the Illinois zero emission standard,
Constellation Energy no longer considers Quad Cities Station to be at heightened
risk for early retirement. However, to the extent the Illinois zero emission
standard does not operate as expected over its full term, Quad Cities Station
would be at heightened risk for early retirement. The FERC's December 19, 2019
order on the PJM MOPR may undermine the continued effectiveness of the Illinois
zero emission standard unless the PJM adopts further changes to the MOPR or
Illinois implements an FRR mechanism, under which Quad Cities Station would be
removed from the PJM's capacity auction.

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, 2021 and new regulatory matters occurring in 2022.

PacifiCorp

Oregon



In March 2022, PacifiCorp filed a general rate case requesting an overall rate
change of $82 million, or 6.6%, to become effective January 1, 2023, that
includes cost increases associated with the implementation of PacifiCorp's
wildfire mitigation and vegetation management plans. Parties to the case filed
testimony in June 2022. PacifiCorp filed reply testimony in July 2022 supporting
an overall rate increase of $94 million but proposing that the request be capped
at PacifiCorp's original request. A hearing in the rate case will be held in
September 2022 with an order expected in December 2022.

In May 2022, PacifiCorp filed its 2021 power cost adjustment mechanism ("PCAM"),
which is the first time since the mechanism has been in place that a rate change
has been warranted. After consideration of the mechanism's deadband, sharing
band and earnings test, PacifiCorp is requesting recovery of $52 million, or a
4.2% increase, to become effective January 1, 2023. This request is incremental
to the rate change sought in the general rate case.

In July 2022, PacifiCorp filed an application requesting approval of an
automatic adjustment clause with a balancing account to recover costs associated
with implementing PacifiCorp's wildfire protection plan in Oregon. Oregon Senate
Bill 762 provides for utilities to timely recover these costs through an
automatic adjustment clause. The filing requests a rate increase of $20 million,
or 1.6%, to recover incremental costs in 2022. While PacifiCorp requested an
effective date of August 24, 2022, the OPUC has suspended the filing for further
review.

Washington

In June 2021, PacifiCorp filed a power cost only rate case to update baseline
net power costs for 2022. PacifiCorp requested a $13 million, or 3.7%, rate
increase with an effective date of January 1, 2022. In November 2021, PacifiCorp
reached a proposed settlement with most of the parties, which includes an
agreement to adjust the PTC rate in base rates and apply a production factor and
to include a net power cost update as part of the compliance filing. A hearing
was held in January 2022 and the WUTC issued an order approving the settlement
in March 2022. A compliance filing reflecting a $43 million, or 12.2%, increase
was filed in April 2022 with rates effective May 1, 2022.

In June 2022, PacifiCorp filed its 2021 PCAM and the new tracking mechanism for
PTCs approved in the 2021 general rate case. For the 2021 PCAM, PacifiCorp is
requesting recovery of $26 million, or a 6.5% increase. PacifiCorp proposed that
the 2021 PCAM be amortized over two years, rather than the one-year period
required under the current terms of the PCAM. For the new 2021 PTC tracker,
PacifiCorp is seeking recovery of $3 million, or an 0.8% increase. Should the
WUTC approve the proposal to extend the amortization period of the 2021 PCAM
from one to two years, the combined annual increase would be $16 million, or
4.0%, effective January 1, 2023.

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 June
2022, a proposed procedural schedule was developed that would result in a
decision in August 2023.

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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 an increase in its South Dakota retail natural gas rates, which would increase revenue by $7 million annually. If approved, the requested rates would increase retail customers' bills by an average of 6.4%.

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 of 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
secured sufficient safe harbor equipment necessary to remain eligible for 60%
PTCs under current tax law. Procedural hearings with the IUB are scheduled to
begin in October 2022.

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Review



In June 2022, Sierra Pacific filed a regulatory rate review with the PUCN that
requested an annual revenue increase of $88 million, or 9.7%. In addition, a
filing was made to revise depreciation rates based on a study, the results of
which are reflected in the proposed revenue requirement. An order is expected by
the end of 2022 and, if approved, would be effective January 1, 2023.

Senate Bill 448 ("SB 448")



SB 448 was signed into law on June 10, 2021. The legislation is intended to
accelerate transmission development, renewable energy and storage, and
accelerate transportation electrification within the state of Nevada. In
September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP
for the approval of their Transmission Infrastructure for a Clean Energy Economy
Plan that sets forth a plan for the construction of high-voltage transmission
infrastructure, Greenlink North among others, that will be placed into service
no later than December 31, 2028, and requires the IRP to include at least one
scenario that uses sources of supply that will achieve certain reductions in
carbon dioxide emissions. In September 2021, the Nevada Utilities filed an
application for the approval of their Economic Recovery Transportation
Electrification Plan to accelerate transportation electrification in the state
of Nevada. The plan establishes requirements for the contents of the
transportation electrification investment as well as requirements for review,
cost recovery and monitoring. The plan covers an initial period beginning
January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN
issued an order granting the application and accepting the Economic Recovery
Transportation Electrification Plan with some modifications. The PUCN opened
rulemakings to address other regulations that resulted from SB 448. In February
2022, the PUCN adopted regulations regarding the Economic Development Electric
Rate Rider Program to revise the discounted electric rates to ease the economic
burden on small businesses who take advantage of the discounted rates under the
tariff. The remaining two SB 448 rulemakings are ongoing.

ON Line Temporary Rider ("ONTR")



In October 2021, Sierra Pacific filed an application with the PUCN for approval
of the ONTR with corresponding updates to its electric rate tariffs to authorize
recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being
accumulated as a result of the ON Line cost reallocation as well as the related
on-going reallocated revenue requirement. Sierra Pacific's application would
have, if approved by the PUCN as filed, resulted in a one-time rate increase of
$28 million to be collected over a nine-month period starting on April 1, 2022.
In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14
million of the ON Line regulatory asset as a one-time rate increase collectable
over a nine-month period effective April 1, 2022, with the expected remaining
balance at December 31, 2022 to be included in rate base in the 2022 regulatory
rate review for inclusion in the rates set in that case.

                                       41
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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. An order is expected in 2022.

Northern Powergrid Distribution Companies

GEMA, through Ofgem, is undertaking its scheduled review of the electricity
distribution price control to put in place a new price control at the end of the
current period that ends March 2023. The new price control ("ED2") will run for
five years from April 2023 to March 2028. In December 2020 and March 2021, GEMA
published its decision on the methodology it will use to set ED2. This confirmed
that Ofgem will maintain many aspects of the current price control and that the
changes being made will generally follow the template that was set by the price
controls implemented in April 2021 for transmission and gas distribution in
Great Britain. Specific changes include new service standard incentives and
mechanisms to adjust cost allowances in specific circumstances, while others
will be discontinued, and partially updating the allowed return on equity within
the period for changes in the interest rate on government bonds.

In December 2021, Northern Powergrid published and filed its business plan with
Ofgem, setting out its detailed approach for 2023-2028 including the cost
allowances this approach would require. In June 2022, Ofgem published its draft
determinations, which included an allowed cost of equity of 4.75% plus inflation
(calculated using the United Kingdom's consumer price index including owner
occupiers' housing costs). When placed on a comparable footing, by adjusting for
differences in the assumed equity ratio and the measure of inflation used, this
working assumption is approximately two percentage points lower than the current
cost of equity for electricity distribution. Ofgem's proposals also set out cost
allowances and associated expectations. Final values from Ofgem are expected in
late 2022.

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' previous
general rate case was settled in 1998. 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 transportation
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 and the outcome of hearing procedures. In June
2022, the parties reached an agreement in principle and the litigation
procedural schedule was ordered held in abeyance for 90 days to enable the
parties to finalize a settlement. The settlement is expected to be filed by
September 30, 2022. As of June 30, 2022, EGTS' provision for rate refund for
April 2022 through June 2022 totaled $35 million and was included in other
current liabilities on the Consolidated Balance Sheet.

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 reservation rates ranging from approximately 45% in the
Field Area to 120% in the Market Area to be implemented, subject to refund, on
August 1, 2022. In July 2022, the FERC issued an order that suspended the rates
proposed for five months following the proposed effective date, until January 1,
2023, subject to refund and the outcome of hearing procedures.
                                       42
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BHE Transmission

AltaLink

2022-2023 General Tariff Application



In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years
of its commitment to keep rates flat for customers at or below the 2018 level of
C$904 million for the five-year period from 2019 to 2023. The two-year
application achieves flat tariffs by continuing to transition to the
AUC-approved salvage recovery method and continuing the use of the flow-through
income tax method, with an overall year-over-year increase of approximately 2%
in 2022 and 2023 revenue requirements. The application requested the approval of
transmission tariffs of C$824 million and C$847 million for 2022 and 2023,
respectively. In September 2021, AltaLink provided responses to information
requests from the AUC and filed an amended application to reflect certain
adjustments and forecast updates. In November 2021, the AUC approved the 2022
interim refundable transmission tariff at C$57 million per month effective
January 2022.

In January 2022, the AUC issued its decision with respect to AltaLink's
2022-2023 GTA. AltaLink's 2022-2023 GTA reflected its continued commitment to
provide rate stability to customers by maintaining flat tariffs and providing
additional tariff relief measures, including a proposed tariff refund of C$60
million of accumulated depreciation in each of 2022 and 2023. The AUC did not
approve AltaLink's proposed refund due to an anticipated improvement in general
economic conditions in Alberta. In March 2022, AltaLink filed a review and
variance application requesting the AUC to review and vary its decision to deny
AltaLink's proposed C$120 million refund of accumulated depreciation surplus,
given material changes in circumstances since the decision was issued in January
2022. In May 2022, the AUC issued a decision with respect to AltaLink's
application to review and vary its proposed $120 million refund of accumulated
depreciation surplus. The AUC found that a material decline in Alberta's
economic circumstances is not sufficient evidence to warrant the refund. In May
2022, the AUC approved AltaLink's revised total 2022 and 2023 revenue
requirement of C$879 million and C$883 million, respectively, allowing AltaLink
to fully deliver on its flat-for-five commitment to customers.

2023 Generic Cost of Capital Proceeding



In January 2022, the AUC initiated the 2023 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 2023 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.

Environmental Laws and Regulations



Each Registrant is subject to federal, state, local and foreign laws and
regulations regarding climate change, RPS, air and water quality, emissions
performance standards, coal combustion byproduct disposal, hazardous and solid
waste disposal, protected species 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,
2021, and new environmental matters occurring in 2022.

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Climate Change

Affordable Clean Energy Rule



In June 2014, the EPA released proposed regulations to address greenhouse gas
emissions from existing fossil-fueled generating facilities, referred to as the
Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal
calculated state-specific emission rate targets to be achieved based on the
"best system of emission reduction." In August 2015, the final Clean Power Plan
was released, which established the best system of emission reduction as
including: (a) heat rate improvements; (b) increased utilization of existing
combined-cycle natural gas-fueled generating facilities; and (c) increased
deployment of new and incremental non-carbon generation placed in-service after
2012. The Clean Power Plan was stayed by the United States Supreme Court in
February 2016 while litigation proceeded. On June 19, 2019, the EPA repealed the
Clean Power Plan and issued the Affordable Clean Energy rule. In the Affordable
Clean Energy rule, the EPA determined that the best system of emission reduction
for existing coal-fueled generating facilities is limited to actions that can be
taken at a point source facility, specifically heat rate improvements, and
identified a set of candidate technologies and measures that could improve heat
rates. Measures taken to meet the standards of performance must be achieved at
the source itself. The Affordable Clean Energy rule was challenged by
environmental and health groups in the D.C. Circuit. On January 19, 2021, the
D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA,
finding that the rule "rested critically on a mistaken reading of the Clean Air
Act" that limited the best system of emission reduction to actions taken at a
facility. In October 2021, the United States Supreme Court agreed to hear an
appeal of that decision. Arguments in the case were held February 28, 2022, and
on June 30, 2022, the United States Supreme Court issued its decision regarding
the scope of the EPA's authority to regulate greenhouse gas emissions under the
Clean Air Act. The United States Supreme Court held that the "generation
shifting" approach in the Clean Power Plan exceeded the powers granted to the
EPA by Congress, although the court did not address whether the EPA may only
adopt measures applied at the individual source as it did in the Affordable
Clean Energy rule. A key area where the EPA went astray was using the Clean
Power Plan to give states the option to promulgate regulations that would
encourage "generation shifting," or moving away from higher-polluting power
sources like coal to lower-polluting sources like natural gas or renewables. The
United States Supreme Court found that type of regulation, which would impact
larger economic forces beyond the fence lines of individual generating
facilities, is not permitted under Section 111(d) of the Clean Air Act. The
United States Supreme Court reversed the D.C. Circuit's vacatur of the
Affordable Clean Energy rule and remanded the case for further proceedings. The
ruling has no immediate impact on the Registrants, as there is no Section 111(d)
rule currently in effect. The Biden administration plans to propose by March
2023 its own rule to replace the Clean Power Plan and Affordable Clean Energy
rule.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a
framework for protecting and improving the nation's air quality and controlling
sources of air emissions. The implementation of new standards is generally
outlined in SIPs, which are a collection of regulations, programs and policies
to be followed. SIPs vary by state and are subject to public hearings and EPA
approval. Some states may adopt additional or more stringent requirements than
those implemented by the EPA. The major Clean Air Act programs most directly
affecting the Registrants' operations are described below.

National Ambient Air Quality Standards



Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six
principal pollutants, consisting of carbon monoxide, lead, NOx, particulate
matter, ozone and SO2, considered harmful to public health and the environment.
Areas that achieve the standards, as determined by ambient air quality
monitoring, are characterized as being in attainment, while those that fail to
meet the standards are designated as being nonattainment areas. Generally,
sources of emissions in a nonattainment area that are determined to contribute
to the nonattainment are required to reduce emissions. Currently, with the
exceptions described in the following paragraphs, air quality monitoring data
indicates that all counties where the relevant Registrant's major emission
sources are located are in attainment of the current NAAQS.

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On June 4, 2018, the EPA published final ozone designations for much of the U.S.
Relevant to the Registrants, these designations include classifying Yuma County,
Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch
Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with
the 2015 ozone standard. These areas were required to meet the 2015 standard
three years from the August 3, 2018, effective date. All other areas relevant to
the Registrants were designated attainment/unclassifiable with this same action.
However, on January 29, 2021, the D.C. Circuit vacated several provisions of the
2018 implementing rules for the 2015 ozone standards for contravening the Clean
Air Act. The EPA and environmental groups finalized a consent decree in January
2022 that sets deadlines for the agency to approve or disapprove the "good
neighbor" provisions of interstate ozone plans of dozens of states. Relevant to
the Registrants, the EPA must, by April 30, 2022, propose to approve or
disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan,
Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On
February 22, 2022, the EPA published a series of proposed decisions to
disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the
Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New
York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's
SIP after re-analyzing the state's data. The EPA must finalize the proposed
rules by December 15, 2022. In addition, the EPA must, by December 15, 2022,
approve or disapprove the interstate plans of Arizona, California, Nevada and
Wyoming. On April 15, 2022, the EPA issued its final rule approving Iowa's SIP
as meeting the good neighbor provisions for the 2015 ozone standard. On May 24,
2022, the EPA disapproved the Utah and Wyoming interstate ozone SIPs. Until the
EPA takes final action consistent with this decree, additional impacts to the
relevant Registrants cannot be determined.
Separately, on March 28, 2022, the EPA proposed determinations as to whether
certain areas have achieved levels of ground-level ozone pollution that meet the
2008 and 2015 ozone NAAQS. Relevant to the Registrants, the Southern Wasatch
Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone
standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch
Front in Utah are proposed to have not met the 2015 ozone, will be reclassified
as Moderate Non-Attainment, and will have until August 3, 2024 to meet the
standard. Until the EPA takes final action on the proposal and the affected
states submit any required SIPs, the relevant Registrants cannot determine the
impacts of the proposed rule.

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., including Iowa, 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.

The first phase of the rule was implemented January 1, 2015. In November 2015,
the EPA released a proposed rule that would further reduce NOx emissions in
2017. The final "CSAPR Update Rule" was published in the Federal Register in
October 2016 and required additional reductions in NOx emissions beginning in
May 2017. On December 6, 2018, the EPA finalized a rule to close out the CSAPR,
having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully
addressed Clean Air Act interstate transport obligations of 20 eastern states.
The EPA determined that 2023 is an appropriate future analytic year to evaluate
remaining good neighbor obligations and that there will be no remaining
nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in
the eastern U.S. in that year. Accordingly, the 20 CSAPR Update-affected states
would not contribute significantly to nonattainment in, or interfere with
maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the
CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit.
The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind
states to continue to significantly contribute to downwind air quality problems
beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy
that did not fully address interstate ozone transport, and remanded the CSAPR
Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019,
finding that because the CSAPR Close-Out Rule relied on the same faulty
reasoning as the CSAPR Update Rule, the CSAPR Close-Out Rule must be vacated. On
October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from
generating facilities in 12 states in the CSAPR trading program in response to
the D.C. Circuit's decision to vacate the CSAPR Update Rule. The rule is
intended to fully resolve 21 upwind states' remaining good neighbor obligations
under the 2008 ozone NAAQS. Additional emissions reductions are required at
generating facilities in 12 states, including Illinois; the EPA predicts that
emissions from the remaining nine states, including Iowa and Texas, will not
significantly contribute to downwind states' ability to attain or maintain the
ozone standard. The EPA accepted comment on the proposal through December 15,
2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update Rule largely
as proposed. Significant new compliance obligations are not anticipated as a
result of the rule. In June 2021, a new lawsuit was filed that challenges the
Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court.
Until litigation is exhausted, the relevant Registrants cannot determine whether
additional action may be required.

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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. The rule focuses on reductions of NOx, precursors to ozone
formation and covers 26 states. Relevant to the Registrants, four states are
included in the cross-state program for the first time - California, Nevada,
Utah and Wyoming. Iowa is not included in the proposal. In a separate but
related action in February 2022, the EPA proposed to approve the good neighbor
provisions of Iowa's SIP addressing ozone transport and the 2015 ozone standard.
The EPA proposes to retain emissions allowance trading for generating
facilities. Beginning in 2023, emissions budgets would be set at the level of
reductions achievable through immediately available measures such as
consistently operating existing emissions controls. Starting in 2026, emissions
budgets would be set at levels achievable by the installation of SCR controls at
certain generating facilities. The proposal also includes additional industries
beyond the power sector for the first time, with a focus on the top NOx emitting
stationary source categories. These include natural gas pipeline compressor
stations, pulp and paper mills, cement production, iron and steel boilers and
furnaces, glass furnaces, chemical manufacturing and petroleum and coal product
manufacturing. These sources will not have access to trading and will instead be
subject to rate-based limits that are assigned for each source category. The EPA
accepted comments on the proposal through June 21, 2022. Until the EPA takes
final action consistent with this decree, impacts to the relevant Registrants
cannot be determined.

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.

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The state of Utah issued a regional haze SIP requiring the installation of SO2,
NOx and particulate matter controls on Hunter Units 1 and 2 and Huntington
Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah
regional haze SIP and disapproved the NOx and particulate matter portions.
Subsequently, the Utah Division of Air Quality completed an alternative BART
analysis for Hunter Units 1 and 2 and Huntington Units 1 and 2. In January 2016,
the EPA published two alternative proposals to either approve the Utah SIP as
written or reject the Utah SIP relating to NOx controls and require the
installation of SCR equipment at Hunter Units 1 and 2 and Huntington Units 1 and
2 within five years. The EPA's final action on the Utah regional haze SIP was
effective August 4, 2016. The EPA approved in part and disapproved in part the
Utah regional haze SIP and issued a FIP requiring the installation of SCR
equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years
of the effective date of the rule. PacifiCorp and other parties filed requests
with the EPA to reconsider and stay that decision, as well as filed motions for
stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth
Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA
issued a letter indicating it would reconsider its FIP decision. In light of the
EPA's grant of reconsideration and the EPA's position in the litigation, the
Tenth Circuit held the litigation in abeyance and imposed a stay of the
compliance obligations of the FIP for the number of days the stay is in effect
while the EPA conducts its reconsideration process. To support the
reconsideration, PacifiCorp undertook additional air quality modeling using the
Comprehensive Air Quality Model with Extensions dispersion model. On January 14,
2019, the state of Utah submitted a SIP revision to the EPA, which includes the
updated modeling information and additional analysis. On June 24, 2019, the Utah
Air Quality Board unanimously voted to approve the Utah regional haze
SIP revision, which incorporates a BART alternative into Utah's regional haze
SIP. 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 Utah
Division of Air Quality submitted the SIP revision to the EPA for approval at
the end of 2019. In January 2020, the EPA published its proposed approval of the
Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon
generating facility federally enforceable and adopts as BART the existing NOx
controls and emission limits on the Hunter and Huntington generating facilities.
The proposed approval withdraws the FIP requirements to install SCR equipment on
Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final
rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With
the approval, the EPA also finalized its withdrawal of the FIP requirements for
the Hunter and Huntington generating facilities. The Utah Regional Haze SIP
Alternative took effect December 28, 2020. As a result of these actions, the
Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. 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. PacifiCorp and
the state of Utah moved to intervene in the litigation. After review of the rule
by the Biden administration, the EPA determined it would defend the rule, and
briefing in the case is ongoing. A date for oral arguments has not been
scheduled. The Utah Air Quality Board approved the Utah Division of Air
Quality's SIP for the regional haze second planning period on April 6, 2022. The
public comment period is anticipated to begin in early May 2022. The proposed
plan sets mass-based emissions limits for PacifiCorp's Hunter and Huntington
generating facilities to ensure reasonable visibility progress for the second
planning period. The division proposes to add existing SO2 emission limits for
all five Hunter and Huntington units as enforceable regional haze controls. The
division also proposes new enforceable mass-based NOx emission limits for both
generating facilities based on actual emissions. The state is on track to submit
a final implementation plan to the EPA in August 2022.

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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. In addition, the EPA initially proposed in June 2012 to disapprove
portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA
withdrew its initial proposed actions on the NOx and particulate matter SIP and
the proposed FIP, published a re-proposed rule in June 2013, and finalized its
determination in January 2014, which aligns more closely with the SIP proposed
by the state of Wyoming. The EPA's final action on the Wyoming SIP 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
within five years (i.e., by 2019). The EPA action became final on March 3, 2014.
PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014.
The state of Wyoming also filed an appeal of the EPA's final action, as did the
Powder River Basin Resource Council, National Parks Conservation Association and
Sierra Club. 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 EPA, U.S. Department of Justice, state of Wyoming and
PacifiCorp executed a settlement agreement December 16, 2020, removing the
requirement to install SCR in lieu of monthly and annual NOx emissions limits.
The settlement agreement was subject to a comment period which ended July 6,
2021. Litigation in the Tenth Circuit remains stayed pending finalization of the
settlement agreement. The EPA did not proceed with final approval of the
settlement agreement for Wyodak and is currently engaged with Wyoming and
PacifiCorp concerning alternative paths for resolution. On February 5, 2019,
PacifiCorp submitted a reasonable progress reassessment permit application and
reasonable progress determination for Jim Bridger Units 1 and 2, seeking a
rescission of the December 2017 permit requiring the installation of SCR, to be
replaced with a permit imposing plant-wide emission limits to achieve better
modeled visibility, fewer overall environmental impacts and lower costs of
compliance. In May 2020, the Wyoming Air Quality Division issued a permit
approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the
four Jim Bridger units and submitted a regional haze SIP revision to the EPA.
The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable
progress reassessment application and incorporates PacifiCorp's proposed
emission limits in lieu of the requirement to install SCR systems on Jim Bridger
Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency
suspension order under Section 110(g) of the Clean Air Act, allowing the
operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA
and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA
proposed to reject the SIP revisions. The EPA took comment on the proposal
through February 17, 2022. 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 under Sections 201 and 209(a) of the Wyoming
Environmental Quality Act, 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 and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must
convert both units to natural gas and begin meeting emissions limits consistent
with that conversion by January 1, 2024. In addition, PacifiCorp must propose an
RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and
4. Wyoming issued its proposed implementation plan for second planning period
reasonable progress on February 18, 2022 and accepted comments through March 23,
2022. 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. The order includes a
one-year deadline to complete the SIP revision. The proposed SIP revision
reflecting these agreements is currently being evaluated under parallel
processes by the state of Wyoming and the EPA. The Wyoming Department of
Environmental Quality submitted the Jim Bridger Units 1 and 2 proposed SIP
revision to federal land managers for a 60-day consultation on June 7, 2022. The
federal land managers must complete review and provide comments by August 8,
2022. For the second round of regional haze planning, Wyoming determined that no
controls will be necessary on any Wyoming resources to make reasonable progress.
It is estimated that the state will submit a final state-approved implementation
plan to the EPA in August 2022.

In February 2022, NV Energy received 30-day notice letters from the Nevada
Division of Environmental Protection regarding the reopening and revision of the
Valmy and Tracy Generating Station's Title V air quality operating permits to
add federally enforceable retirement dates of December 31, 2028 for Valmy Units
1 and 2 and December 31, 2031 for Tracy Unit 4. The enforceable retirement dates
will implement Nevada's SIP for the regional haze second planning period. The
revised permits were received in March and April 2022. The Nevada Division of
Environmental Protection accepted public comment on its SIP through July 25,
2022, and is on track to submit the final SIP to the EPA in August 2022.
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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,
2021. There have been no significant changes in the Company's assumptions
regarding critical accounting estimates since December 31, 2021.

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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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