PACIFICORP The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical 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 ofMidAmerican Energy ), NV Energy (which primarily consists ofNevada Power and Sierra Pacific),Northern Powergrid (which primarily consists ofNorthern Powergrid (Northeast) plc andNorthern Powergrid (Yorkshire) plc),BHE Pipeline Group (which primarily consists of BHE GT&S,Northern Natural Gas andKern River ), BHE Transmission (which consists of BHE Canada (which primarily consists ofAltaLink ) and BHEU.S. Transmission),BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies inthe United States serving customers in 11 states, two electricity distribution companies inGreat Britain , five interstate natural gas pipeline companies, one of which owns an LNG import, export and storage facility, inthe United States , an electric transmission business inCanada , interests in electric transmission businesses inthe United States , a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm inthe United States and one of the largest residential real estate brokerage franchise networks inthe 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. 29 --------------------------------------------------------------------------------
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
*
(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 atBHE Pipeline Group , primarily due to$107 million of incremental net income from BHE GT&S, acquired inNovember 2020 , higher gross margin on gas sales and higher transportation revenue atNorthern Natural Gas , largely due to the favorable impact of theFebruary 2021 polar vortex weather event, and the impacts of the 2020 rate case settlement atNorthern Natural Gas ; •$79 million lower net income atBHE Renewables , primarily due to lower wind tax equity investment earnings from net losses on existing tax equity investments, largely due to theFebruary 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation; 30 -------------------------------------------------------------------------------- •$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 inOctober 2020 , higher BHE corporate interest expense from debt issuances in March andOctober 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
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 inJanuary 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.
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 theFebruary 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. 31 --------------------------------------------------------------------------------
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 atNevada 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 weakerUnited 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 weakerUnited States dollar.
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 inNovember 2020 , higher gas sales atNorthern Natural Gas of$91 million and higher transportation revenue of$33 million atNorthern Natural Gas , largely due to the favorable impacts of theFebruary 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 atNorthern 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 strongerUnited States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired inMay 2020 , partially offset by the impacts of a regulatory decision received inNovember 2020 atAltaLink . Net income increased$4 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from theMontana -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 theFebruary 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation. 32 --------------------------------------------------------------------------------
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 atMidAmerican 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,$38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway inOctober 2020 , higher BHE corporate interest expense from debt issuances in March andOctober 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year endedDecember 31, 2020 for further discussion regarding the limitation of distributions from BHE's subsidiaries. As ofMarch 31, 2021 , the Company's total net liquidity was as follows (in millions): MidAmerican NV Northern BHE BHE PacifiCorp Funding Energy Powergrid Canada Other Total Cash and cash equivalents$ 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
$ 698 $ 290 $ 786 $ 1,808 $ 9,220 Credit facilities: Maturity dates 2022 2022 2021, 2022 2022 2023 2021, 2024 2021, 2022 33
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Operating Activities
Net cash flows from operating activities for the three-month periods endedMarch 31, 2021 and 2020 were$1.5 billion and$1.2 billion , respectively. The increase was primarily due to improved operating results and favorable income tax cash flows, partially offset by changes in working capital. The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods endedMarch 31, 2021 and 2020 were$(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
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 endedMarch 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.
34
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The Company's historical and forecast capital expenditures, each of which
exclude amounts for non-cash equity AFUDC and other non-cash items, are as
follows (in millions):
Three-Month Periods Annual
Ended March 31, Forecast
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 atMidAmerican Energy totaling$154 million for the three-month period endedMarch 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 atMidAmerican Energy totaling$24 million and$6 million for the three-month periods endedMarch 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 ofMarch 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. 35 -------------------------------------------------------------------------------- •Construction of wind-powered generating facilities atPacifiCorp totaling$27 million and$89 million for the three-month periods endedMarch 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 atPacifiCorp totaling$5 million and$16 million for the three-month periods endedMarch 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 atPacifiCorp totaling$1 million for the three-month period endedMarch 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 andNorthern 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 includePacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment ofPacifiCorp's Energy Gateway Transmission expansion program, placed in-service inNovember 2020 , theNevada Utilities' Greenlink Nevada transmission expansion program andAltaLink's directly assigned projects from theAlberta 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, includingMidAmerican 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 theDry Lake generating facility. Commercial operation atDry 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 endedMarch 31, 2021 , and has commitments as ofMarch 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. 36
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Contractual Obligations
As ofMarch 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 endedDecember 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 whichMidAmerican Energy has a 25% ownership interest, announced onJune 2, 2016 , its intention to shut downQuad Cities Station onJune 1, 2018 . InDecember 2016 ,Illinois passed legislation creating a zero emission standard, which went into effectJune 1, 2017 . The zero emission standard requires theIllinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers inIllinois , subject to certain limitations. The proceeds from the ZECs will provideExelon Generation additional revenue through 2027 as an incentive for continued operation ofQuad Cities Station .MidAmerican Energy will not receive additional revenue from the subsidy. ThePJM Interconnection, L.L.C. ("PJM") capacity market includes a MinimumOffer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior toDecember 19, 2019 , the PJM MOPR applied only to certain new gas-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 ofQuad Cities Station not receiving capacity revenues in future auctions. OnDecember 19, 2019 , theFERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While theFERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such asQuad Cities Station . TheFERC 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 theFERC's order, the PJM submitted a compliance filing onMarch 18, 2020 , wherein the PJM proposed tariff language reflecting theFERC's directives and a schedule for resuming capacity auctions. OnApril 16, 2020 , theFERC issued an order largely denying requests for rehearing of theFERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted onJune 1, 2020 . OnOctober 15, 2020 , theFERC issued an order denying requests for rehearing of itsApril 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, theFERC 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 theFERC in another proceeding. InNovember 2020 , the PJM announced that the next capacity auction will be conducted inMay 2021 . OnMay 21, 2020 , theFERC 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, theFERC 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 onAugust 5, 2020 . On review of this compliance filing, theFERC 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. IfIllinois 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. IfIllinois cannot implement an FRR program in its PJM zones, then the MOPR will apply toQuad Cities Station , resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program inIllinois 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 ofQuad Cities Station . 37 --------------------------------------------------------------------------------
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 endedDecember 31, 2020 and new regulatory matters occurring in 2021.
InMarch 2020 ,PacifiCorp filed its annual EBA application with the UPSC requesting recovery of$37 million of deferred power costs from customers for the periodJanuary 1, 2019 throughDecember 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 inFebruary 2021 for rates effectiveMarch 1, 2021 .
InFebruary 2020 ,PacifiCorp filed a general rate case, and inDecember 2020 , the OPUC approved a net rate decrease of approximately$24 million , or 1.8%, effectiveJanuary 1, 2021 , acceptingPacifiCorp'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 effectiveJanuary 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. InJanuary 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%, effectiveJanuary 12, 2021 . InApril 2021 , the OPUC approved the third compliance filing to add theFoote Creek repowered wind facility and thePryor Mountain new wind facility to rates, resulting in a rate increase of$14 million , or 1.2%, effectiveApril 9, 2021 .Wyoming InSeptember 2018 ,PacifiCorp filed an application for depreciation rate changes with the WPSC based onPacifiCorp's 2018 depreciation rate study, requesting the rates become effectiveJanuary 1, 2021 . Updates sinceSeptember 2018 include the filing ofPacifiCorp'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. InApril 2020 ,PacifiCorp filed a stipulation with the WPSC resolving all issues addressed inPacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed inPacifiCorp'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 ofPacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing inAugust 2020 and a subsequent written order inDecember 2020 . The general rate case hearing was rescheduled forFebruary 2021 . As a result of the hearing date change,PacifiCorp filed an application inOctober 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 inJuly 2021 . InMarch 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. InSeptember 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 forOctober 2020 . The WPSC re-noticedPacifiCorp's case and rescheduled the hearings. The hearings beganFebruary 2021 and were completed inMarch 2021 . The WPSC decision is pending.PacifiCorp has requested a rate effective date ofJuly 1, 2021 . 38 -------------------------------------------------------------------------------- InApril 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 periodJanuary 1, 2020 throughDecember 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 ofJuly 1, 2021 .
InMarch 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 theLake 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 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 inMarch 2021 .
FERC Show Cause Order
OnApril 15, 2021 , theFERC issued an order to show cause and notice of proposed penalty related to allegations made byFERC Office of Enforcement staff thatPacifiCorp failed to comply with certainNorth American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings onPacifiCorp's bulk electric system. The order directsPacifiCorp 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 toPacifiCorp'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 theFERC .
Natural Gas Purchased for Resale
InFebruary 2021 , severe cold weather over the centralUnited States caused disruptions in natural gas supply from the southern part ofthe United States . These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale toMidAmerican 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 periodApril 2021 throughApril 2022 . While sufficient liquidity is available toMidAmerican Energy , the increased costs and longer recovery period resulted in higher working capital requirements during the three-month period endedMarch 31, 2021 . 39
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NV Energy (Nevada Power and Sierra Pacific)
Price Stability Tariff
InNovember 2018 , theNevada 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. InFebruary 2019 , the PUCN granted several intervenors the ability to participate in the proceeding. InJune 2019 , theNevada Utilities withdrew their filings. InMay 2020 , theNevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held inSeptember 2020 . InNovember 2020 , the PUCN issued an order approving the tariff with modified pricing and directing theNevada 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. InDecember 2020 , theNevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. InJanuary 2021 , the PUCN issued an order reaffirming its order fromNovember 2020 and denying the petition for a rehearing. In the first quarter of 2021, theNevada Utilities filed an update to the CPST program per theNovember 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 inFebruary 2020 . InJune 2020 , a hearing was held and an order was issued inAugust 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting inOctober 2020 . InOctober 2020 , intervening parties filed petitions for reconsideration. Intervenors have filed a petition for judicial review with the District Court inNovember 2020 . InDecember 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 earlyFebruary 2021 and an order is expected in the second quarter of 2021. InMarch 2021 , theNevada 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
InDecember 2020 ,GEMA , through Ofgem, published its final determinations for transmission and gas distribution networks inGreat Britain . These determinations do not apply directly toNorthern Powergrid , but aspects of the proposals are capable of application atNorthern Powergrid's next price control, ("ED2"), which will begin inApril 2023 . Regarding allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using theUnited Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). InMarch 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. InDecember 2020 , in respect of electricity distribution,GEMA published its decision on the methodology it will use to set the ED2 price control and prices fromApril 2023 toMarch 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 inMarch 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. 40 --------------------------------------------------------------------------------
BHE GT&S
InJanuary 2020 , pursuant to the terms of a previous settlement,Cove Point filed a general rate case for itsFERC -jurisdictional services, with proposed rates to be effectiveMarch 1, 2020 .Cove Point proposed an annual cost-of-service of$182 million . InFebruary 2020 , theFERC approved suspending the changes in rates for five months following the proposed effective date, untilAugust 1, 2020 , subject to refund. InNovember 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 effectiveAugust 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 toAugust 1, 2020 . The interim settlement rates were implementedNovember 1, 2020 , andCove Point's provision for rate refunds forAugust 2020 throughOctober 2020 totaled$7 million . The agreement in principle was reflected in a stipulation and agreement filed with theFERC inJanuary 2021 . InMarch 2021 , theFERC approved the stipulation and agreement and the rate refunds to customers were processed in late April. BHE TransmissionAltaLink Tariff Refund Application InJanuary 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 totalingC$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers ofC$150 million of previously collected future income taxes andC$200 million of surplus accumulated depreciation. The future income tax refund would be evenly distributed over the two-year period, 2021 to 2022, withC$75 million included in each year. The accumulated depreciation surplus would be refunded over the three-year period, 2021 to 2023, withC$60 million included in 2021 and 2022, andC$80 million in 2023. If approved by the AUC, these tariff relief measures would have saved customers an estimatedC$317 million over the three-year period, 2021 to 2023. InMarch 2021 , the AUC issued a decision onAltaLink's Tariff Refund Application and approved a 2021 tariff refund in the amount ofC$230 million and a net 2021 tariff reduction ofC$224 million , which providesAlberta ratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund ofC$150 million of previously collected future income tax and a refund ofC$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed inAltaLink's 2022-2023 GTA.
2019-2021 General Tariff Application
InAugust 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 ofC$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 additionalC$31 million . InApril 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 onAltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements ofC$879 million ,C$882 million andC$885 million for 2019, 2020 and 2021, respectively. InJuly 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 ofC$38 million to the three year total revenue requirement applied for inAltaLink's 2019-2021 GTA updated inApril 2019 . However, this was offset byAltaLink's request for an additionalC$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 customersC$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held inNovember 2019 , with written arguments filed inJanuary 2020 . 41
-------------------------------------------------------------------------------- InApril 2020 , the AUC issued its decision with respect toAltaLink'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 approveAltaLink'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 additionalC$20 million AltaLink requested for forecast transmission line clearance capital. The remainingC$7 million of capital investment was reviewed inAltaLink's subsequent compliance filing. Also,C$3 million of forecast operating expenses andC$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additionalC$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approvedC$6 million of retirements for towers and fixtures. InJuly 2020 , the AUC approvedAltaLink's compliance filing establishing revised revenue requirements ofC$895 million for 2019,C$894 million for 2020 andC$898 million for 2021, exclusive of the assets transferred to thePiikaniLink Limited Partnership and theKainaiLink Limited Partnership . The AUC deferred its decision onAltaLink's proposed salvage methodology included inAltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and inJuly 2020 ,AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect toAltaLink's proposed salvage methodology. InSeptember 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 onAltaLink's proposed salvage methodology. InOctober 2020 ,AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed byAltaLink . InNovember 2020 , the AUC issued its decision onAltaLink's review and variance application. The AUC decided to vary the original decision and approveAltaLink's proposed net salvage method and the revised transmission tariffs as filed, effectiveDecember 2020 . The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions toAltaLink's revenue requirement from customers byC$24 million ,C$27 million andC$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 ofC$904 million from 2019 to 2021.
In
2022-2023 General Tariff Application
InApril 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 ofC$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 theC$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 additionalC$60 million per year. The application requested the approval of transmission tariff ofC$824 million andC$847 million for 2022 and 2023, respectively.
2022 Generic Cost of Capital Proceeding
InDecember 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. InJanuary 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. 42 -------------------------------------------------------------------------------- InMarch 2021 , the AUC issued its decision with respect to setting the return on equity and deemed equity ratios forAltaLink . 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 forAlberta ratepayers. InApril 2021 , theUtilities Consumer Advocate filed an application with theCourt 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, theUtilities 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
InMarch 2021 , the AUC issued its decision onAltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approvedC$128.0 million of theC$128.5 million of gross capital project additions, disallowingC$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 inApril 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 endedDecember 31, 2020 , and new environmental matters occurring in 2021.
Climate Change
InDecember 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, theParis Agreement became effectiveNovember 4, 2016 . OnJune 1, 2017 ,President Trump announcedthe United States would begin the process of withdrawing from the Paris Agreement.The United States completed its withdrawal from theParis Agreement onNovember 4, 2020 .President Biden accepted the terms of the climate agreementJanuary 20, 2021 , andthe United States completed its reentryFebruary 19, 2021 . At a Climate Leaders Summit heldApril 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 howthe United States will implement these goals is anticipated to be released through fall 2021.
The Clean Air Act is a federal law administered by theEPA 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 andEPA approval. Some states may adopt additional or more stringent requirements than those implemented by theEPA . The major Clean Air Act programs most directly affecting the Registrants' operations as described below. 43 --------------------------------------------------------------------------------
GHG Performance Standards
Under the Clean Air Act, theEPA 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. OnAugust 3, 2015 , theEPA 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 forApril 17, 2017 . However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. OnDecember 6, 2018 , theEPA 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. TheEPA 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. OnJanuary 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 underClean 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 inthe 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 theFederal 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 ruleApril 5, 2021 , remanding it for further proceedings.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, theEPA 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. InJune 2010 , theEPA 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 byJune 2012 ; however, citing a lack of sufficient information to make the designations, theEPA did not issue its final designations untilJuly 2013 and determined, at that date, that a portion ofMuscatine County, Iowa was in nonattainment for the one-hour SO2 standard.MidAmerican Energy's Louisa coal-fueled generating facility is located just outside ofMuscatine County , south of the violating monitor. In its final designation, theEPA 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, theEPA will make decisions for areas and sources outsideMuscatine County .MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although theEPA 'sJuly 2013 designations did not impactPacifiCorp's nor theNevada Utilities' generating facilities, theEPA 's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. OnFebruary 25, 2019 , theEPA issued a decision to retain the 2010 SO2 NAAQS without revision. 44 -------------------------------------------------------------------------------- TheSierra Club filed a lawsuit against theEPA inAugust 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. InMarch 2015 , theUnited States District Court for the Northern District of California ("Northern District ofCalifornia ") accepted as an enforceable order an agreement between theEPA andSierra Club to resolve litigation concerning the deadline for completing the designations.The Northern District ofCalifornia's order directed theEPA to complete designations in three phases: the first phase byJuly 2, 2016 ; the second phase byDecember 31, 2017 ; and the final phase byDecember 31, 2020 . The first phase of the designations require theEPA 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 theEPA '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 ofMarch 2, 2015 , had not been announced for retirement.MidAmerican Energy's George Neal Unit 4 and theOttumwa Generating Station (in whichMidAmerican 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 theEPA updated recommendations and supporting information for theEPA to consider in making its determinations.Iowa submitted documentation to theEPA inApril 2016 supporting its recommendation thatDes Moines ,Wapello andWoodbury Counties be designated as being in attainment of the standard. InJuly 2016 , theEPA 's final designations were published in theFederal Register indicating portions ofMuscatine County, Iowa were in nonattainment with the 2010 SO2 standard,Woodbury County, Iowa was unclassifiable, andDes Moines andWapello Counties were unclassifiable/attainment. OnMarch 26, 2021 , theEPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation ofConverse County, Wyoming as an Attainment/Unclassifiable area.PacifiCorp's Dave Johnston generating facility is located inConverse County . No further action byPacifiCorp is required.
Cross-State Air Pollution Rule
TheEPA promulgated an initial rule inMarch 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the easternUnited States , includingIowa , 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 implementedJanuary 1, 2015 . InNovember 2015 , theEPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in theFederal Register inOctober 2016 and required additional reductions in NOx emissions beginning inMay 2017 . OnDecember 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 easternUnited 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 ruledSeptember 13, 2019 , that because theEPA 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 theEPA . The D.C. Circuit issued an opinionOctober 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. OnOctober 15, 2020 , theEPA 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, includingIllinois ; theEPA predicts that emissions from the remaining nine states, includingIowa andTexas , will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. TheEPA accepted comment on the proposal throughDecember 15, 2020 . OnMarch 15, 2021 , theEPA finalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. Regional Haze TheEPA 's RegionalHaze Rule , finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some ofPacifiCorp's coal-fueled generating facilities inUtah ,Wyoming ,Arizona andColorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to theClean 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 -------------------------------------------------------------------------------- The state ofUtah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, andHuntington Units 1 and 2. InDecember 2012 , theEPA approved the SO2 portion of theUtah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, theUtah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. InJanuary 2016 , theEPA 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 theUtah regional haze SIP was effectiveAugust 4, 2016 . TheEPA approved in part and disapproved in part theUtah 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 theEPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with theTenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn theEPA 's actions. InJuly 2017 , theEPA issued a letter indicating it would reconsider its FIP decision. In light of theEPA 's grant of reconsideration and theEPA '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 theEPA conducts its reconsideration process. To support the reconsideration,PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. OnJanuary 14, 2019 , the state ofUtah submitted a SIP revision to theEPA , which includes the updated modeling information and additional analysis. OnJune 24, 2019 , the Utah Air Quality Board unanimously voted to approve theUtah regional haze SIP revision, which incorporates a BART alternative intoUtah's regional haze SIP. The BART alternative makes the shutdown ofPacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 andHuntington Units 1 and 2.The Utah Division of Air Quality submitted the SIP revision to theEPA for approval at the end of 2019. InJanuary 2020 , theEPA published its proposed approval of theUtah 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 andHuntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. TheEPA released the final rule approving theUtah Regional Haze SIP Alternative onOctober 28, 2020 . With the approval, theEPA also finalized its withdrawal of the FIP requirements for the Hunter andHuntington plants. TheUtah Regional Haze SIP Alternative took effectDecember 28, 2020 . As a result of these actions, the Tenth Circuit dismissed theUtah regional haze petitions onJanuary 11, 2021 . OnJanuary 19, 2021 , HealUtah ,National Parks Conservation Association ,Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of theUtah Regional Haze SIP Alternative in the Tenth Circuit.PacifiCorp and the state ofUtah 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 endedDecember 31, 2020 . There have been no significant changes in the Company's assumptions regarding critical accounting estimates sinceDecember 31, 2020 . 46 --------------------------------------------------------------------------------PacifiCorp and its subsidiaries Consolidated Financial Section 47 -------------------------------------------------------------------------------- PART I
Item 1.Financial Statements
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