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OFFON

PACIFICORP

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PACIFICORP : OR/ Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-Q)

05/03/2021 | 06:04am EDT
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.

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 United States serving customers in 11 states, two electricity
distribution companies in Great Britain, five interstate natural gas pipeline
companies, one of which owns an LNG import, export and storage facility, in the
United States, an electric transmission business in Canada, interests in
electric transmission businesses in the United States, a renewable energy
business primarily investing in wind, solar, geothermal and hydroelectric
projects, the largest residential real estate brokerage firm in the United
States and one of the largest residential real estate brokerage franchise
networks in the United States. 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, corporate functions and
intersegment eliminations.

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Results of Operations for the First Quarter of 2021 and 2020

Overview

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

                                                     First Quarter
                                       2021         2020              Change
Operating revenue:
PacifiCorp                           $ 1,242      $ 1,206      $    36         3  %
MidAmerican Funding                    1,067          686          381        56
NV Energy                                591          622          (31)       (5)
Northern Powergrid                       300          266           34        13
BHE Pipeline Group                     1,093          401          692            *
BHE Transmission                         180          172            8         5
BHE Renewables                           190          178           12         7
HomeServices                           1,232          893          339        38
BHE and Other                            186          103           83        81
Total operating revenue              $ 6,081      $ 4,527      $ 1,554        34  %

(Loss) earnings on common shares:
PacifiCorp                           $   169      $   176      $    (7)       (4) %
MidAmerican Funding                      144          150           (6)       (4)
NV Energy                                 34           20           14        70
Northern Powergrid                       104           87           17        20
BHE Pipeline Group                       383          179          204            *
BHE Transmission                          59           55            4         7
BHE Renewables(1)                         16           95          (79)      (83)
HomeServices                              84           10           74            *
BHE and Other                         (1,027)        (102)        (925)           *

(Loss) earnings on common shares $ (34) $ 670 $ (704)

*

(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

* Not meaningful


Earnings on common shares decreased $704 million for the first quarter of 2021
compared to 2020. The first quarter of 2021 included a pre-tax unrealized loss
of $1,124 million ($818 million after-tax) compared to a pre-tax unrealized gain
in the first quarter of 2020 of $54 million ($39 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 quarter of 2021 was $784
million, an increase of $153 million, or 24%, compared to adjusted earnings on
common shares in the first quarter of 2020 of $631 million.

The decrease in earnings on common shares for the first quarter of 2021 compared
to 2020 was primarily due to the following:
•$204 million higher net income at BHE Pipeline Group, primarily due to $107
million of incremental net income from BHE GT&S, acquired in November 2020,
higher gross margin on gas sales and higher transportation revenue at Northern
Natural Gas, largely due to the favorable impact of the February 2021 polar
vortex weather event, and the impacts of the 2020 rate case settlement at
Northern Natural Gas;
•$79 million lower net income at BHE Renewables, primarily due to lower wind tax
equity investment earnings from net losses on existing tax equity investments,
largely due to the February 2021 polar vortex weather event, partially offset by
increased income tax benefits from projects reaching commercial operation;
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•$74 million higher net income at HomeServices, primarily due to higher earnings
from mortgage services (63% increase in funded mortgage volume) and brokerage
services (35% increase in closed transaction volume) largely attributable to the
favorable interest rate environment; and
•$925 higher net loss at BHE and Other due to the $857 million unfavorable
change in the after-tax unrealized position of the Company's investment in BYD
Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred
Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020,
higher BHE corporate interest expense from debt issuances in March and October
2020 and higher other corporate costs, partially offset by favorable changes in
the cash surrender value of corporate-owned life insurance policies.

Reportable Segment Results

PacifiCorp


Operating revenue increased $36 million for the first quarter of 2021 compared
to 2020, primarily due to higher retail revenue of $20 million and higher
wholesale and other revenue of $16 million. Retail revenue increased due to
higher customer volumes of $15 million and price impacts of $5 million from
changes in sales mix, partially offset by lower rates due to certain general
rate case orders. Retail customer volumes increased 0.3%, primarily due to an
increase in the average number of customers and the favorable impact of weather,
partially offset by lower customer usage. Wholesale and other revenue increased
primarily due to higher wholesale volumes and higher average wholesale market
prices.

Net income decreased $7 million for the first quarter of 2021 compared to 2020,
primarily due to higher depreciation and amortization expense, including the
impacts of a depreciation study effective in January 2021, lower allowances for
equity and borrowed funds used during construction of $12 million and higher
property taxes of $12 million, partially offset by higher utility margin of $29
million and favorable income tax expense from the impacts of ratemaking and
higher PTCs recognized due to new wind-powered generating facilities placed
in-service. Utility margin increased primarily due to the higher retail and
wholesale revenue and lower purchased power costs, partially offset by higher
natural gas-fueled and coal-fueled generation costs and higher net amortization
of deferred net power costs in accordance with established adjustment
mechanisms.

MidAmerican Funding


Operating revenue increased $381 million for the first quarter of 2021 compared
to 2020, primarily due to higher natural gas operating revenue of $303 million
and higher electric operating revenue of $74 million. Natural gas operating
revenue increased due to a higher average per-unit cost of natural gas sold,
primarily due to the February 2021 polar vortex weather event resulting in
higher purchased gas adjustment recoveries of $304 million (offset in cost of
sales). Electric operating revenue increased due to higher retail revenue of $40
million and higher wholesale and other revenue of $32 million mainly from higher
wholesale volumes. Electric retail revenue increased primarily due to $32
million higher recoveries through the energy adjustment clauses (offset
primarily in cost of sales), higher customer volumes of $5 million and price
impacts of $5 million from changes in sales mix. Electric retail customer
volumes increased 4.9% due to the favorable impact of weather and increased
usage of certain industrial customers.

Net income decreased $6 million for the first quarter of 2021 compared to 2020,
primarily due to higher depreciation and amortization expense of $31 million
from additional assets placed in-service and the expiration of a regulatory
mechanism deferring certain depreciation expense and $28 million higher
operations and maintenance expenses, partially offset by a favorable income tax
benefit and favorable changes in the cash surrender value of corporate-owned
life insurance policies. Higher operations and maintenance expenses included
increased costs associated with additional wind-powered generating facilities
placed in-service as well as higher electric and natural gas distribution costs.
The favorable income tax benefit was mainly due to higher PTCs recognized from
higher wind-powered generation, driven primarily by new wind projects placed
in-service, partially offset by the impacts of ratemaking. Electric utility
margin increased $3 million as the higher retail and wholesale revenue was
largely offset by higher generation and purchased power costs.


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NV Energy


Operating revenue decreased $31 million for the first quarter of 2021 compared
to 2020, primarily due to lower electric operating revenue of $22 million and
lower natural gas operating revenue of $9 million. Electric operating revenue
decreased primarily due to lower base tariff general rates of $14 million, lower
retail customer volumes, lower fully-bundled energy rates (offset in cost of
sales) of $4 million and price impacts from changes in sales mix. Electric
retail customer volumes, including distribution only service customers,
decreased 3.2%, primarily due to the impacts of COVID-19, which resulted in
lower distribution only service, industrial and commercial customer usage and
higher residential customer usage, partially offset by the favorable impact of
weather. Natural gas operating revenue decreased due to a lower average per-unit
cost of natural gas sold (offset in cost of sales).

Net income increased $14 million for the first quarter of 2021 compared to 2020,
primarily due to lower operations and maintenance expense of $22 million,
primarily from lower regulatory instructed deferrals and amortizations and lower
plant operations and maintenance costs, favorable changes in the cash surrender
value of corporate-owned life insurance policies, lower interest expense of $7
million and lower income tax expense from the impacts of ratemaking, partially
offset by lower electric utility margin of $18 million and higher depreciation
and amortization expense of $13 million, mainly from the regulatory amortization
of decommissioning costs and higher plant placed in-service. Electric utility
margin decreased primarily due to the lower base tariff general rates at Nevada
Power, lower retail customer volumes and price impacts from changes in sales
mix.

Northern Powergrid

Operating revenue increased $34 million for the first quarter of 2021 compared
to 2020, primarily due to $21 million from the weaker United States dollar and
higher distribution revenue of $13 million, mainly from increased tariff rates
of $10 million. Net income increased $17 million for the first quarter of 2021
compared to 2020, primarily due to the higher distribution revenue and $7
million from the weaker United States dollar.

BHE Pipeline Group


Operating revenue increased $692 million for the first quarter of 2021 compared
to 2020, primarily due to $559 million of incremental revenue at BHE GT&S,
acquired in November 2020, higher gas sales at Northern Natural Gas of $91
million and higher transportation revenue of $33 million at Northern Natural
Gas, largely due to the favorable impacts of the February 2021 polar vortex
weather event. Net income increased $204 million for the first quarter of 2021
compared to 2020, primarily due to $107 million of incremental net income at BHE
GT&S and higher earnings of $98 million at Northern Natural Gas. Northern
Natural Gas' improved performance was primarily due to higher gross margin on
gas sales of $75 million, higher transportation revenue and the impacts of the
2020 rate case settlement.

BHE Transmission

Operating revenue increased $8 million for the first quarter of 2021 compared to
2020, primarily due to $10 million from the stronger United States dollar and
higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020,
partially offset by the impacts of a regulatory decision received in November
2020 at AltaLink. Net income increased $4 million for the first quarter of 2021
compared to 2020, primarily due to higher earnings from the Montana-Alberta
Tie-Line and lower non-regulated interest expense at BHE Canada.
BHE Renewables

Operating revenue increased $12 million for the first quarter of 2021 compared
to 2020, primarily due to higher hydro, geothermal and solar revenues from
higher generation as well as favorable pricing at the geothermal facilities. Net
income decreased $79 million for the first quarter 2021 compared to 2020,
primarily due to lower wind tax equity investment earnings of $93 million,
partially offset by the higher operating revenue. Wind tax equity investment
earnings decreased due to unfavorable results from existing tax equity
investments of $138 million, primarily due to the February 2021 polar vortex
weather event, partially offset by increased income tax benefits from projects
reaching commercial operation.


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HomeServices


Operating revenue increased $339 million for the first quarter of 2021 compared
to 2020, primarily due to higher brokerage revenue of $228 million from a 35%
increase in closed transaction volume and higher mortgage revenue of $92 million
from a 63% increase in funded mortgage volume due to an increase in refinance
activity from the favorable interest rate environment. Net income increased $74
million for the first quarter of 2021 compared to 2020, primarily due to higher
earnings from mortgage services of $36 million and brokerage services of $27
million largely attributable to the favorable interest rate environment.
BHE and Other
Operating revenue increased $83 million for the first quarter of 2021 compared
to 2020, primarily due to higher electricity and natural gas sales revenue at
MidAmerican Energy Services, LLC, from favorable pricing offset by lower
volumes. Net loss increased $925 million for the first quarter of 2021 compared
to 2020, primarily due to the $857 million unfavorable change in the after-tax
unrealized position of the Company's investment in BYD Company Limited, $38
million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain
subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate
interest expense from debt issuances in March and October 2020 and higher other
corporate costs, partially offset by favorable changes in the cash surrender
value of corporate-owned life insurance policies.

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, 2020 for further discussion regarding the limitation of
distributions from BHE's subsidiaries.

As of March 31, 2021, the Company's total net liquidity was as follows (in
millions):
                                                           MidAmerican            NV             Northern              BHE
                       BHE            PacifiCorp             Funding            Energy          Powergrid             Canada               Other              Total

Cash and cash
equivalents         $   418          $       43          $         38          $  103          $      83          $        71          $       520          $ 1,276

Credit facilities     3,500               1,200                 1,509             650                207                  935                3,232           11,233
Less:
Short-term debt           -                 (95)                 (387)            (55)                 -                 (218)              (1,944)          (2,699)
Tax-exempt bond
support and letters
of credit                 -                (218)                 (370)              -                  -                   (2)                   -             (590)
Net credit
facilities            3,500                 887                   752             595                207                  715                1,288            7,944

Total net liquidity $ 3,918 $ 930 $ 790

   $  698          $     290          $       786          $     1,808          $ 9,220
Credit facilities:
Maturity dates            2022                2022            2021, 2022            2022               2023           2021, 2024           2021, 2022





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Operating Activities


Net cash flows from operating activities for the three-month periods ended
March 31, 2021 and 2020 were $1.5 billion and $1.2 billion, respectively. The
increase was primarily due to improved operating results and favorable income
tax cash flows, partially offset by changes in working capital.

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 and
assumptions used for each payment date.

Investing Activities


Net cash flows from investing activities for the three-month periods ended
March 31, 2021 and 2020 were $(1.4) billion and $(1.5) billion, respectively.
The change was primarily due to lower funding of tax equity investments and
lower capital expenditures of $61 million. Refer to "Future Uses of Cash" for
further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2021 was $(191) million. Sources of cash totaled $409 million and consisted of net proceeds from short-term debt. Uses of cash totaled $600 million and consisted mainly of repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $115 million and repayments of subsidiary debt totaling $26 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.


Net cash flows from financing activities for the three-month period ended
March 31, 2020 was $1.4 billion. Sources of cash totaled $4.3 billion and
consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and
subsidiary debt issuances totaling $1.1 billion. Uses of cash totaled $3.0
billion and consisted mainly of repayments of subsidiary debt totaling $1.3
billion, net repayments of short-term debt totaling $1.1 billion, repayments of
BHE senior debt totaling $350 million and common stock repurchases totaling $126
million.

The Company may from time to time seek to acquire its outstanding debt
securities through cash purchases in the open market, privately negotiated
transactions or otherwise. Any debt securities repurchased by the Company may be
reissued or resold by the Company from time to time and will depend on
prevailing market conditions, the Company's liquidity requirements, contractual
restrictions and other factors. The amounts involved may be material.

Future Uses of Cash


The Company has available a variety of sources of liquidity and capital
resources, both internal and external, including net cash flows from operating
activities, public and private debt offerings, the issuance of commercial paper,
the use of unsecured revolving credit facilities, the issuance of equity and
other sources. These sources are expected to provide funds required for current
operations, capital expenditures, acquisitions, investments, debt retirements
and other capital requirements. The availability and terms under which BHE and
each subsidiary has access to external financing depends on a variety of
factors, including regulatory approvals, its credit ratings, investors' judgment
of risk and conditions in the overall capital markets, including the condition
of the utility industry and project finance markets, among other items.

Capital Expenditures


The Company has significant future capital requirements. Capital expenditure
needs are reviewed regularly by management and may change significantly as a
result of these reviews, which may consider, among other factors, impacts to
customers' rates; changes in environmental and other rules and regulations;
outcomes of regulatory proceedings; changes in income tax laws; general business
conditions; load projections; system reliability standards; the cost and
efficiency of construction labor, equipment and materials; commodity prices; and
the cost and availability of capital. Expenditures for certain assets may
ultimately include acquisitions of existing assets.

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The Company's historical and forecast capital expenditures, each of which
exclude amounts for non-cash equity AFUDC and other non-cash items, are as
follows (in millions):
                                                  Three-Month Periods            Annual
                                                    Ended March 31,             Forecast
                                                   2020             2021          2021
        Capital expenditures by business:
        PacifiCorp                          $       366           $   439      $  1,897
        MidAmerican Funding                         472               298         2,200
        NV Energy                                   163               167           854
        Northern Powergrid                          159               179           732
        BHE Pipeline Group                          120               102         1,204
        BHE Transmission                             56                77           279
        BHE Renewables                               12                18            95
        HomeServices                                  7                 8            39
        BHE and Other(1)                              1                 7            78
        Total                               $     1,356           $ 1,295      $  7,378


           Capital expenditures by type:
           Wind generation                        $   273      $    97      $ 1,158
           Electric distribution                      365          427        1,849
           Electric transmission                      185          157        1,006
           Natural gas transmission and storage        49           85        1,032
           Solar generation                             -            4          295
           Other                                      484          525        2,038
           Total                                  $ 1,356      $ 1,295      $ 7,378


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


The Company's historical and forecast capital expenditures consisted mainly of
the following:
•Wind generation expenditures include the following:
•Construction and acquisition of wind-powered generating facilities at
MidAmerican Energy totaling $154 million for the three-month period ended
March 31, 2020. MidAmerican Energy's forecast expenditures in 2021 for the
construction of additional wind-powered generating facilities total $391 million
and include 202 MWs of wind-powered generating facilities expected to be placed
in-service in 2021.
•Repowering of wind-powered generating facilities at MidAmerican Energy totaling
$24 million and $6 million for the three-month periods ended March 31, 2021 and
2020, respectively. The repowering projects entail the replacement of
significant components of older turbines. Planned spending for the repowered
generating facilities totals $379 million for the remainder of 2021. 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 1,078 MWs of
current repowering projects not in-service as of March 31, 2021, 80 MWs are
currently expected to qualify for 100% of the federal PTCs available for 10
years following each facility's return to service, 591 MWs are expected to
qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of
such credits.
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•Construction of wind-powered generating facilities at PacifiCorp totaling $27
million and $89 million for the three-month periods ended March 31, 2021 and
2020, respectively, and includes the 674 MWs of new wind-powered generating
facilities that were placed in-service in 2020 and 516 MWs expected to be placed
in-service in 2021. The energy production from the new wind-powered generating
facilities is expected to qualify for 100% of the federal PTCs available for 10
years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified
1,920 MWs of new wind-powered generating resources that are expected to come
online in 2024. PacifiCorp anticipates that the additional new wind-powered
generation will be a mixture of owned and contracted resources. PacifiCorp
anticipates costs associated with the construction of wind-powered generating
facilities will total an additional $100 million for 2021.
•Repowering existing wind-powered generating facilities at PacifiCorp totaling
$5 million and $16 million for the three-month periods ended March 31, 2021 and
2020, respectively. The repowering projects entail the replacement of
significant components of older turbines. Certain repowering projects were
placed in service in 2019 and 2020 and the remaining repowering projects are
expected to be placed in-service in 2021. The energy production from such
repowered facilities is expected to qualify for 100% of the federal PTCs
available for 10 years following each facility's return to service. Planned
additional spending for certain existing wind-powered generating facilities
totals $6 million for 2021.
•Acquisition and repowering of wind-powered generating facilities at PacifiCorp
totaling $1 million for the three-month period ended March 31, 2021. Planned
additional spending for these wind-powered generating facilities totals $44
million for 2021.
•Electric distribution includes both growth and operating expenditures. Growth
expenditures include new customer connections and enhancements to existing
customer connections. Operating expenditures include ongoing distribution
systems infrastructure needed at the Utilities and Northern Powergrid, wildfire
mitigation, damage restoration and storm damage 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 PacifiCorp's costs for the 140-mile 500-kV
Aeolus-Bridger/Anticline transmission line, which is a major segment of
PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in
November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion
program and AltaLink's directly assigned projects from the Alberta Electric
System Operator. Operating expenditures include 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, the Northern
Natural Gas New Lisbon Expansion and Twin Cities Area Expansion projects.
Operating expenditures include, among other items, asset modernization and
pipeline integrity projects.
•Solar generation includes growth expenditures, including MidAmerican Energy's
current plan for the construction of 117 MWs of small- and utility-scale solar
generation during 2021, of which 37 MWs are expected to be placed in-service in
2021. Nevada Power's solar generation investment includes expenditures for a
150 MWs solar photovoltaic facility with an additional 100 MWs capacity of
co-located battery storage, known as the Dry Lake generating facility.
Commercial operation at Dry Lake is expected by the end of 2023.
•Other capital expenditures includes both growth and operating expenditures,
including 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.

Other Renewable Investments


The Company has invested in projects sponsored by third parties, commonly
referred to as tax equity investments. Under the terms of these tax equity
investments, the Company has entered into equity capital contribution agreements
with the project sponsors that require contributions. The Company has made no
contributions for the three-month period ended March 31, 2021, and has
commitments as of March 31, 2021, subject to satisfaction of certain specified
conditions, to provide equity contributions of $616 million for the remainder of
2021 pursuant to these equity capital contribution agreements as the various
projects achieve commercial operation. Once a project achieves commercial
operation, the Company enters into a partnership agreement with the project
sponsor that directs and allocates the operating profits and tax benefits from
the project.


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Contractual Obligations


As of March 31, 2021, there have been no material changes outside the normal
course of business in contractual obligations from the information provided in
Item 7 of the Company's Annual Report on Form 10-K for the year ended
December 31, 2020 other than the recent financing transactions and renewable tax
equity investments previously discussed.

Quad Cities Generating Station Operating Status


Exelon Generation Company, LLC ("Exelon Generation"), 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 zero emission credits ("ZECs") and recover the costs from
certain ratepayers in Illinois, subject to certain limitations. The proceeds
from the ZECs will provide Exelon Generation 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 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 expands the breadth and scope of the PJM's MOPR, which is effective as
of the PJM's next capacity auction. While the FERC included some limited
exemptions in its order, 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. On October 15, 2020, the FERC issued an order denying requests for
rehearing of its April 16, 2020 order and accepting the PJM's two compliance
filings, subject to a further compliance filing to revise minor aspects of the
proposed MOPR methodology. As part of that order, the FERC also accepted the
PJM's proposal to condense the schedule of activities leading up to the next
capacity auction but did not specify when that schedule would commence given
that a key element of the MOPR level computation remains pending before the FERC
in another proceeding. In November 2020, the PJM announced that the next
capacity auction will be conducted in May 2021.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's
day-ahead and real-time reserves markets that need to be reflected in the
calculation of MOPR levels. In approving reforms to the PJM's reserves markets,
the FERC also directed the PJM to develop a new methodology for estimating
revenues that resources will receive for sales of energy and related services,
which will then be used in calculating a number of parameters and assumptions
used in the capacity market, including MOPR levels. The PJM submitted its new
revenue projection methodology on August 5, 2020. On review of this compliance
filing, the FERC is expected to address how these additional reforms will impact
MOPR levels, the timeline for implementing the new revenue projection
methodology, and the timing for commencing the capacity auction schedule.

Exelon Generation is currently working with the PJM and other stakeholders to
pursue the FRR option as an alternative to the next PJM capacity auction. If
Illinois implements the FRR option, Quad Cities Station could be removed from
the PJM's capacity auction and instead supply capacity and be compensated under
the FRR program. If Illinois cannot implement an FRR program in its PJM zones,
then the MOPR will apply to Quad Cities Station, resulting in higher offers for
its units that may not clear the capacity market. Implementing the FRR program
in Illinois will require both legislative and regulatory changes. MidAmerican
Energy cannot predict whether or when such legislative and regulatory changes
can be implemented or their potential impact on the continued operation of Quad
Cities Station.

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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, 2020 and new regulatory matters occurring in 2021.

PacifiCorp

Utah


In March 2020, PacifiCorp filed its annual EBA application with the UPSC
requesting recovery of $37 million of deferred power costs from customers for
the period January 1, 2019 through December 31, 2019, reflecting the difference
between base and actual net power costs in the 2019 deferral period. This
reflected a 1.0% increase compared to current rates. The UPSC approved the
request in February 2021 for rates effective March 1, 2021.

Oregon


In February 2020, PacifiCorp filed a general rate case, and in December 2020,
the OPUC approved a net rate decrease of approximately $24 million, or 1.8%,
effective January 1, 2021, accepting PacifiCorp's proposed annual credit to
customers of the remaining 2017 Tax Reform benefits over a two-year period.
PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in
response to the OPUC's order reflected a rate decrease of approximately $67
million, or 5.1%, due to the exclusion of the impacts of repowered wind
facilities, new wind facilities and certain other new investments that had not
been placed in service at the time of the filing. Additional compliance filings
will be made to include these investments in rates concurrent when they are
placed in service. In January 2021, the OPUC approved the second compliance
filing to add the remainder of the Ekola Flats wind facility to rates, resulting
in a rate increase of approximately $7 million, or 0.5%, effective January 12,
2021. In April 2021, the OPUC approved the third compliance filing to add the
Foote Creek repowered wind facility and the Pryor Mountain new wind facility to
rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9,
2021.

Wyoming

In September 2018, PacifiCorp filed an application for depreciation rate changes
with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the
rates become effective January 1, 2021. Updates since September 2018 include the
filing of PacifiCorp's 2020 decommissioning studies in which a third­party
consultant was engaged to estimate decommissioning costs associated with
coal-fueled generating facilities and removal of Cholla Unit 4. In April 2020,
PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in
PacifiCorp's depreciation rate study application with ratemaking treatment of
certain matters to be addressed in PacifiCorp's general rate case, including
depreciation for coal-fueled generating facilities and associated incremental
decommissioning costs reflected in decommissioning studies and certain matters
related to the repowering of PacifiCorp's wind-powered generating facilities.
The stipulation was approved by the WPSC during a hearing in August 2020 and a
subsequent written order in December 2020. The general rate case hearing was
rescheduled for February 2021. As a result of the hearing date change,
PacifiCorp filed an application in October 2020 with the WPSC requesting
authorization to defer costs associated with impacts of the depreciation study.
A hearing for this deferral application is scheduled to occur in July 2021.

In March 2020, PacifiCorp filed a general rate case with the WPSC which
reflected recovery of Energy Vision 2020 investments, updated depreciation
rates, incremental decommissioning costs associated with coal-fueled facilities
and rate design modernization proposals. The application also requested a
revision to the ECAM to eliminate the sharing band and requested authorization
to discontinue operations and recover costs associated with the early retirement
of Cholla Unit 4. The proposed increase reflects several rate mitigation
measures that include use of the remaining 2017 Tax Reform benefits to buy down
plant balances, including Cholla Unit 4, and spreading the recovery of the
depreciation of certain coal-fueled generation units over time periods that
extend beyond the depreciable lives proposed in the depreciation rate study. In
September 2020, PacifiCorp filed its rebuttal testimony that modified its
requested increase in base rates from $7 million to $9 million, or 1.3%, and
reflected an update to the rate mitigation measures for using the 2017 Tax
Reform benefits. The WPSC determined that the rebuttal testimony filed
constituted a material and substantial change to the original application and
vacated the hearing that was scheduled for October 2020. The WPSC re-noticed
PacifiCorp's case and rescheduled the hearings. The hearings began February 2021
and were completed in March 2021. The WPSC decision is pending. PacifiCorp has
requested a rate effective date of July 1, 2021.

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In April 2021, PacifiCorp filed its annual ECAM and RRA application with the
WPSC requesting to refund $15 million of deferred net power costs and RECs to
customers for the period January 1, 2020 through December 31, 2020, reflecting
the difference between base and actual net power costs in the 2020 deferral
period. This reflects a 2.4% decrease compared to current rates. PacifiCorp has
requested an interim rate effective date of July 1, 2021.

Idaho


In March 2021, PacifiCorp filed its annual ECAM application with the IPUC
requesting recovery of $14 million for deferred costs in 2020. This filing
includes recovery of the difference in actual net power costs to the base level
in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs,
RECs, and a resource tracking mechanism to match costs with the benefits of new
wind and wind repowering projects until they are reflected in base rates. This
reflects a 1.1% decrease compared to current rates.

California


California Senate Bill 901 requires electric utilities to prepare and submit
wildfire mitigation plans that describe the utilities' plans to prevent, combat
and respond to wildfires affecting their service territories. PacifiCorp
submitted its 2021 California Wildfire Mitigation Plan Update in March 2021.

FERC Show Cause Order


On April 15, 2021, the FERC issued an order to show cause and notice of proposed
penalty related to allegations made by FERC Office of Enforcement staff that
PacifiCorp failed to comply with certain North American Electric Reliability
Corporation (the "NERC") reliability standards associated with facility ratings
on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause
as to why it should not be assessed a civil penalty of $42 million as a result
of the alleged violations. The allegations are related to PacifiCorp's response
to a 2010 industry-wide effort directed by the NERC to identify and remediate
certain discrepancies resulting from transmission facility design and actual
field conditions, including transmission line clearances. PacifiCorp will file a
response to the allegations with the FERC.

MidAmerican Energy

Natural Gas Purchased for Resale


In February 2021, severe cold weather over the central United States caused
disruptions in natural gas supply from the southern part of the United States.
These disruptions, combined with increased demand, resulted in historically high
prices for natural gas purchased for resale to MidAmerican Energy's retail
customers and caused an approximate $245 million increase in natural gas costs
above those normally expected. To mitigate the impact to customers, the IUB
ordered the recovery of these higher costs to be applied to natural gas sales
over the period April 2021 through April 2022. While sufficient liquidity is
available to MidAmerican Energy, the increased costs and longer recovery period
resulted in higher working capital requirements during the three-month period
ended March 31, 2021.


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NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff


In November 2018, the Nevada Utilities made filings with the PUCN to implement
the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed
the CPST to provide certain customers, namely those eligible to file an
application pursuant to Chapter 704B of the Nevada Revised Statutes, with a
market-based pricing option that is based on renewable resources. The CPST
provides for an energy rate that would replace the Base Tariff Energy Rate and
DEAA. The goal is to have an energy rate that yields an all-in effective rate
that is competitive with market options available to such customers. In February
2019, the PUCN granted several intervenors the ability to participate in the
proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May
2020, the Nevada Utilities refiled the CPST incorporating the considerations
raised by the PUCN and other intervenors and a hearing was held in September
2020. In November 2020, the PUCN issued an order approving the tariff with
modified pricing and directing the Nevada Utilities to develop a methodology by
which all eligible participants may have the opportunity to participate in the
CPST program up to a limit with the same proportion of governmental entities'
and non-governmental entities' MWh reserved for potentially interested customers
as filed. In December 2020, the Nevada Utilities filed a petition for
reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN
issued an order reaffirming its order from November 2020 and denying the
petition for a rehearing. In the first quarter of 2021, the Nevada Utilities
filed an update to the CPST program per the November 2020 order and an updated
CPST tariff with the PUCN. An order is expected in the second quarter of 2021.

Natural Disaster Protection Plan


The Nevada Utilities submitted their initial natural disaster protection plan to
the PUCN and filed their first application seeking recovery of 2019 expenditures
in February 2020. In June 2020, a hearing was held and an order was issued in
August 2020 that granted the joint application, made minor adjustments to the
budget and approved the 2019 costs for recovery starting in October 2020. In
October 2020, intervening parties filed petitions for reconsideration.
Intervenors have filed a petition for judicial review with the District Court in
November 2020. In December 2020, the PUCN issued a second modified final order
approving the natural disaster protection plan, as modified, and reopened its
investigation and rulemaking on Senate Bill 329 to address rate design issues
raised by intervenors. The comment period for the reopened investigation and
rulemaking ended in early February 2021 and an order is expected in the second
quarter of 2021. In March 2021, the Nevada Utilities filed an application
seeking recovery of the 2020 expenditures, approval for an update to the initial
natural disaster protection plan that was ordered by the PUCN and filed their
first amendment to the 2020 natural disaster protection plan.

Northern Powergrid Distribution Companies


In December 2020, GEMA, through Ofgem, published its final determinations for
transmission and gas distribution networks in Great Britain. These
determinations do not apply directly to Northern Powergrid, but aspects of the
proposals are capable of application at Northern Powergrid's next price control,
("ED2"), which will begin in April 2023. Regarding allowed return on capital,
Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the
United Kingdom's consumer price index including owner occupiers' housing costs
("CPIH")). In March 2021, all the transmission and gas distribution networks
lodged appeals with the Competition and Markets Authority against Ofgem's
determination for the cost of equity.

In December 2020, in respect of electricity distribution, GEMA published its
decision on the methodology it will use to set the ED2 price control and prices
from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects
of the proposals from the transmission and gas distribution price controls to
electricity distribution.

GEMA published a separate decision in March 2021, confirming that the financial
aspects in respect of electricity distribution would broadly follow the
transmission and gas distribution methodology, setting a working assumption for
a cost of equity at 4.65% (plus CPIH), ahead of the final determinations in late
2022. When placed on a comparable footing, by adjusting for differences in the
assumed equity ratio and the measure of inflation used, the working assumption
for ED2 is approximately 150 basis points lower than the current cost of equity.

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BHE Pipeline Group

BHE GT&S


In January 2020, pursuant to the terms of a previous settlement, Cove Point
filed a general rate case for its FERC-jurisdictional services, with proposed
rates to be effective March 1, 2020. Cove Point proposed an annual
cost-of-service of $182 million. In February 2020, the FERC approved suspending
the changes in rates for five months following the proposed effective date,
until August 1, 2020, subject to refund. In November 2020, Cove Point reached an
agreement in principle with the active participants in the general rate case
proceeding. Under the terms of the agreement in principle, Cove Point's rates
effective August 1, 2020 result in an increase to annual revenues of $4 million
and a decrease in annual depreciation expense of $1 million, compared to the
rates in effect prior to August 1, 2020. The interim settlement rates were
implemented November 1, 2020, and Cove Point's provision for rate refunds for
August 2020 through October 2020 totaled $7 million. The agreement in principle
was reflected in a stipulation and agreement filed with the FERC in January
2021. In March 2021, the FERC approved the stipulation and agreement and the
rate refunds to customers were processed in late April.

BHE Transmission

AltaLink

Tariff Refund Application

In January 2021, driven by the pandemic and economic shutdown that has
negatively impacted all Albertans, AltaLink filed an application with the AUC
that requested approval of tariff relief measures totaling C$350 million over
the three-year period, 2021 to 2023. The tariff relief measures consist of a
proposed refund to customers of C$150 million of previously collected future
income taxes and C$200 million of surplus accumulated depreciation. The future
income tax refund would be evenly distributed over the two-year period, 2021 to
2022, with C$75 million included in each year. The accumulated depreciation
surplus would be refunded over the three-year period, 2021 to 2023, with C$60
million included in 2021 and 2022, and C$80 million in 2023. If approved by the
AUC, these tariff relief measures would have saved customers an estimated C$317
million over the three-year period, 2021 to 2023.

In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application
and approved a 2021 tariff refund in the amount of C$230 million and a net 2021
tariff reduction of C$224 million, which provides Alberta ratepayers with
immediate tariff relief in 2021. The approved 2021 tariff refund includes a
refund of C$150 million of previously collected future income tax and a refund
of C$80 million of accumulated depreciation surplus. Tariff relief measures for
years 2022 and 2023 will be proposed in AltaLink's 2022-2023 GTA.

2019-2021 General Tariff Application


In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the
first three years of its commitment to keep rates lower or flat at the approved
2018 revenue requirement of C$904 million for customers for the next five years.
In addition, AltaLink proposed to provide a further tariff reduction over the
three year period by refunding previously collected accumulated depreciation
surplus of an additional C$31 million. In April 2019, AltaLink filed an update
to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact
of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation
Application. The application requested the approval of revised revenue
requirements of C$879 million, C$882 million and C$885 million for 2019, 2020
and 2021, respectively.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement
application with the AUC. The application consisted of negotiated reductions
that resulted in a net decrease of C$38 million to the three year total revenue
requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019.
However, this was offset by AltaLink's request for an additional C$20 million of
forecast transmission line clearance capital as part of an excluded matter. The
2019-2021 negotiated settlement agreement excluded certain matters related to
the new salvage study and salvage recovery approach, additional capital spending
and incremental asset retirements. AltaLink's salvage proposal is estimated to
save customers C$267 million between 2019 and 2023. Excluded matters were
examined by the AUC in a hearing held in November 2019, with written arguments
filed in January 2020.


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In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021
GTA. The AUC approved the negotiated settlement agreement as filed and rendered
its decision and directions on the excluded matters. The AUC declined to approve
AltaLink's proposed salvage methodology at that time, but indicated it would
initiate a generic proceeding to review the matter on an industry-wide basis.
The AUC approved, on a placeholder basis, C$13 million of the additional C$20
million AltaLink requested for forecast transmission line clearance capital. The
remaining C$7 million of capital investment was reviewed in AltaLink's
subsequent compliance filing. Also, C$3 million of forecast operating expenses
and C$4 million of forecast capital expenditures related to fire risk mitigation
were approved, with an additional C$31 million of capital expenditures reviewed
in the compliance filing. Finally, the AUC approved C$6 million of retirements
for towers and fixtures.

In July 2020, the AUC approved AltaLink's compliance filing establishing revised
revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898
million for 2021, exclusive of the assets transferred to the PiikaniLink Limited
Partnership and the KainaiLink Limited Partnership.

The AUC deferred its decision on AltaLink's proposed salvage methodology
included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider
the broader implications. This generic proceeding was closed and in July 2020,
AltaLink filed an application with the AUC for the review and variance of the
AUC's decision with respect to AltaLink's proposed salvage methodology. In
September 2020, the AUC granted this review on the basis that there were changed
circumstances that could lead the AUC to materially vary or rescind the majority
hearing panel's findings on AltaLink's proposed salvage methodology. In October
2020, AltaLink filed responses to information requests from the AUC, written
argument was filed by intervening parties and written reply argument was filed
by AltaLink. In November 2020, the AUC issued its decision on AltaLink's review
and variance application. The AUC decided to vary the original decision and
approve AltaLink's proposed net salvage method and the revised transmission
tariffs as filed, effective December 2020. The new salvage methodology decreased
the amount of salvage pre-collection resulting in reductions to AltaLink's
revenue requirement from customers by C$24 million, C$27 million and C$31
million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on
the first three years of its commitment to customers to keep rates flat for five
years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021
GTA maintains customer rates below the 2018 level of C$904 million from 2019 to
2021.

In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.

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 continuing to transition to the AUC-approved
salvage recovery method, continuing the use of the flow-through income tax
method, and adding only a 1% increase to operations and maintenance expense,
with the exception of salaries and wages and other expenses. In addition,
similar to the C$80 million refund of the previously collected accumulated
depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide
further similar tariff reductions over the two years by refunding an additional
C$60 million per year. The application requested the approval of transmission
tariff of C$824 million and C$847 million for 2022 and 2023, respectively.

2022 Generic Cost of Capital Proceeding


In December 2020, the AUC initiated the 2022 generic cost of capital proceeding.
This proceeding will consider the return on equity and deemed equity ratios for
2022 and one or more additional test years. Due to the existing uncertainty as a
result of the ongoing COVID-19 pandemic, before establishing a process schedule,
the commission has requested participants to submit comments that address the
following: (i) the continuation of the currently approved return on equity and
deemed equity ratios for a further period of time; (ii) the appropriate test
period for the proceeding; (iii) the scope of the proceeding, including whether
a formula-based approach to return on equity should be utilized; (iv) the
considerations to take into account when establishing the process for the
proceeding; and (v) the avoidance of duplicative evidence and greater
coordination and collaboration between parties.

In January 2021, AltaLink submitted a letter to the AUC stating that due to
ongoing capital market volatility and other COVID-19 related uncertainties there
are reasonable grounds for extending the currently approved 2021 return on
equity and deemed equity ratio on a final basis for 2022. AltaLink further
stated there is insufficient time to complete a full generic cost of capital
proceeding in 2021, in order to issue a decision prior to the beginning of 2022
and a formula-based approach should not be considered at this time. AltaLink
suggested that a proceeding could be restarted in the third quarter of 2021, for
2023 and subsequent years.

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In March 2021, the AUC issued its decision with respect to setting the return on
equity and deemed equity ratios for AltaLink. The AUC approved an equity return
of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and
market uncertainties, the unsettled nature of capital markets, and the need for
certainty and stability for Alberta ratepayers.

In April 2021, the Utilities Consumer Advocate filed an application with the
Court of Appeal of Alberta requesting permission to appeal the AUC's decision
that set the return on equity of 8.5% and equity ratio of 37% on a final basis
for 2022. In the appeal, the Utilities Consumer Advocate alleges that the AUC
erred by failing to fulfil its statutory obligation of establishing a fair
return and by failing to apply procedural fairness.

2019 Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.


In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts
Reconciliation Application. The AUC approved C$128.0 million of the C$128.5
million of gross capital project additions, disallowing C$0.5 million of capital
costs. The AUC also approved the other deferral accounts for taxes other than
income taxes, long-term debt and annual structure payments as filed. AltaLink
filed its compliance filing in April 2021.

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 laws and regulations 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, 2020, and new environmental matters occurring in 2021.

Climate Change


In December 2015, an international agreement was negotiated by 195 nations to
create a universal framework for coordinated action on climate change in what is
referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of
limiting global temperature increase well below 2 degrees Celsius, while urging
efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by
all parties to make nationally determined contributions and pursue domestic
measures aimed at achieving the commitments; commits all countries to submit
emissions inventories and report regularly on their emissions and progress made
in implementing and achieving their nationally determined commitments; and
commits all countries to submit new commitments every five years, with the
expectation that the commitments will get more aggressive. In the context of the
Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by
2025 from 2005 levels. After more than 55 countries representing more than 55%
of global GHG emissions submitted their ratification documents, the Paris
Agreement became effective November 4, 2016. On June 1, 2017, President Trump
announced the United States would begin the process of withdrawing from the
Paris Agreement. The United States completed its withdrawal from the Paris
Agreement on November 4, 2020. President Biden accepted the terms of the climate
agreement January 20, 2021, and the United States completed its reentry February
19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021,
President Biden announced new climate goals to cut GHG 50%-52% economy-wide by
2030 compared to 2005 levels, and to reach 100% carbon pollution-free
electricity by 2035. Additional details on how the United States will implement
these goals is anticipated to be released through fall 2021.

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 as described below.
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GHG Performance Standards


Under the Clean Air Act, the EPA may establish emissions standards that reflect
the degree of emissions reductions achievable through the best technology that
has been demonstrated, taking into consideration the cost of achieving those
reductions and any non-air quality health and environmental impact and energy
requirements. On August 3, 2015, the EPA issued final new source performance
standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for
large natural gas-fueled generating facilities and 1,400 pounds of carbon
dioxide per MWh for new coal-fueled generating facilities with the "Best System
of Emission Reduction" reflecting highly efficient supercritical pulverized coal
facilities with partial carbon capture and sequestration or integrated
gasification combined-cycle units that are co-fired with natural gas or
pre-combustion slipstream capture of carbon dioxide. The new source performance
standards were appealed to the D.C. Circuit and oral argument was scheduled for
April 17, 2017. However, oral argument was deferred and the court held the case
in abeyance for an indefinite period of time. On December 6, 2018, the EPA
announced revisions to new source performance standards for new and
reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission
limits for new coal-fueled facilities to 1,900 pounds per MWh for small units
and 2,000 pounds per MWh for large units. The EPA would define the best system
of emission reduction for new and modified units as the most efficient
demonstrated steam cycle, combined with best operating practices. On January 12,
2021, EPA finalized a rule focused solely on a significant contribution finding
for purposes of regulating source categories' GHG emissions. The final rule sets
no specific regulatory standards and contains no regulatory text, nor does it
address what constitutes the best system of emission reduction for new, modified
and reconstructed electric generating units. EPA confirms in the "significant
contribution" rule that electric generating units remain a listed source
category under Clean Air Act Section 111(b), reaching that conclusion through
the introduction of an emissions threshold framework by which a source category
is deemed to contribute significantly to dangerous air pollution due to their
GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions
in the United States. Under this methodology, no other source category would
qualify for regulation. The significant contribution rule will take effect 60
days after publication in the Federal Register but is expected to be quickly
revisited by the Biden administration. Because the significant contribution rule
did not alter the emission limits or technology requirements of the 2015 rule,
any new fossil-fueled generating facilities will be required to meet the GHG new
source performance standards. The D.C. Circuit vacated the significant
contribution rule April 5, 2021, remanding it for further proceedings.

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.

In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas
must meet a one-hour standard of 75 parts per billion utilizing a three-year
average. The rule utilizes source modeling in addition to the installation of
ambient monitors where SO2 emissions impact populated areas. Attainment
designations were due by June 2012; however, citing a lack of sufficient
information to make the designations, the EPA did not issue its final
designations until July 2013 and determined, at that date, that a portion of
Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard.
MidAmerican Energy's Louisa coal-fueled generating facility is located just
outside of Muscatine County, south of the violating monitor. In its final
designation, the EPA indicated that it was not yet prepared to conclude that the
emissions from the Louisa coal-fueled generating facility contribute to the
monitored violation or to other possible violations, and that in a subsequent
round of designations, the EPA will make decisions for areas and sources outside
Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment
designation will have a material impact on the Louisa coal-fueled generating
facility. Although the EPA's July 2013 designations did not impact PacifiCorp's
nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2
area designations will continue with the deployment of additional SO2 monitoring
networks across the country. On February 25, 2019, the EPA issued a decision to
retain the 2010 SO2 NAAQS without revision.

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The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to
the one-hour SO2 standards and its failure to make certain attainment
designations in a timely manner. In March 2015, the United States District Court
for the Northern District of California ("Northern District of California")
accepted as an enforceable order an agreement between the EPA and Sierra Club to
resolve litigation concerning the deadline for completing the designations. The
Northern District of California's order directed the EPA to complete
designations in three phases: the first phase by July 2, 2016; the second phase
by December 31, 2017; and the final phase by December 31, 2020. The first phase
of the designations require the EPA to designate two groups of areas: 1) areas
that have newly monitored violations of the 2010 SO2 standard; and 2) areas that
contain any stationary source that, according to the EPA's data, either emitted
more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and
had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit
in 2012 and, as of March 2, 2015, had not been announced for retirement.
MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in
which MidAmerican Energy has a majority ownership interest, but does not
operate), are included as units subject to the first phase of the designations,
having emitted more than 2,600 tons of SO2 and having an emission rate of at
least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit
to the EPA updated recommendations and supporting information for the EPA to
consider in making its determinations. Iowa submitted documentation to the EPA
in April 2016 supporting its recommendation that Des Moines, Wapello and
Woodbury Counties be designated as being in attainment of the standard. In July
2016, the EPA's final designations were published in the Federal Register
indicating portions of Muscatine County, Iowa were in nonattainment with the
2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and
Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA
issued the last of its final designations for the 2010 primary SO2 standard.
Included in this round was designation of Converse County, Wyoming as an
Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility
is located in Converse County. No further action by PacifiCorp is required.

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 United States, 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, EPA finalized a rule to close out the CSAPR,
having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed
Clean Air Act interstate transport obligations of 20 eastern states. 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 United States 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 power plants 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 power plants 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 largely as
proposed. Significant new compliance obligations are not anticipated as a result
of the rule.

Regional Haze

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

                                       45
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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 controls at Hunter Units 1 and 2 and Huntington Units 1
and 2 within five years. 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 federal implementation plan ("FIP")
requiring the installation of SCR controls 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 plant enforceable under the SIP and removes the
requirement to install SCR technology 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 plant federally enforceable and adopts as BART the
existing NOx controls and emission limits on the Hunter and Huntington plants.
The proposed approval withdraws the FIP requirements to install SCR 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 plants. 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, which has been stayed pending the Biden
administration's review of the rule.

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,
derivatives, 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, 2020. There have been no significant changes in the Company's
assumptions regarding critical accounting estimates since December 31, 2020.

                                       46
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                        PacifiCorp and its subsidiaries
                         Consolidated Financial Section

                                       47
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                                     PART I

Item 1.Financial Statements

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