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'sactual results in the future could differ significantly from the historical results. Berkshire Hathaway Energy'soperations are organized as eight business segments: PacifiCorp, MidAmerican Funding(which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Powerand Sierra Pacific), Northern Powergrid(which primarily consists of Northern Powergrid (Northeast) plcand Northern Powergrid (Yorkshire)plc), BHE Pipeline Group(which primarily consists of BHE GT&S, Northern Natural Gasand Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S.Transmission), BHE Renewablesand HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United Statesserving 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 Statesand 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. 29 --------------------------------------------------------------------------------
First quarter 2021 and 2020 operating results
The operating revenue and profit on common shares for the reportable segments of the company are summarized as follows (in millions):
First Quarter 2021 2020 Change Operating revenue: PacifiCorp
$ 1,242 $ 1,206 $ 363 % 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 $ 1,55434 % (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) profit on ordinary shares
(1) Includes tax attributes of disregarded entities which are not required to pay income taxes and whose profits are directly taxable to BHE.
* Not significant
Earnings on common shares decreased
$704 millionfor the first quarter of 2021 compared to 2020. The first quarter of 2021 included a pre-tax unrealized loss of $1,124 million( $818 millionafter-tax) compared to a pre-tax unrealized gain in the first quarter of 2020 of $54 million( $39 millionafter-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 millionof 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 2021polar 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 2021polar 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 millionunfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 millionof 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 2020and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.
Segment results to report
Operating revenue increased
$36 millionfor the first quarter of 2021 compared to 2020, primarily due to higher retail revenue of $20 millionand higher wholesale and other revenue of $16 million. Retail revenue increased due to higher customer volumes of $15 millionand price impacts of $5 millionfrom 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 millionfor 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 millionand higher property taxes of $12 million, partially offset by higher utility margin of $29 millionand 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 millionfor the first quarter of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $303 millionand 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 2021polar 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 millionand higher wholesale and other revenue of $32 millionmainly from higher wholesale volumes. Electric retail revenue increased primarily due to $32 millionhigher recoveries through the energy adjustment clauses (offset primarily in cost of sales), higher customer volumes of $5 millionand price impacts of $5 millionfrom 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 millionfor the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $31 millionfrom additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense and $28 millionhigher 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 millionas the higher retail and wholesale revenue was largely offset by higher generation and purchased power costs. 31 --------------------------------------------------------------------------------
Operating revenue decreased
$31 millionfor the first quarter of 2021 compared to 2020, primarily due to lower electric operating revenue of $22 millionand 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 millionand 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 millionfor 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 millionand lower income tax expense from the impacts of ratemaking, partially offset by lower electric utility margin of $18 millionand 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 PowergridOperating revenue increased $34 millionfor the first quarter of 2021 compared to 2020, primarily due to $21 millionfrom the weaker United Statesdollar and higher distribution revenue of $13 million, mainly from increased tariff rates of $10 million. Net income increased $17 millionfor the first quarter of 2021 compared to 2020, primarily due to the higher distribution revenue and $7 millionfrom the weaker United Statesdollar.
Operating revenue increased
$692 millionfor the first quarter of 2021 compared to 2020, primarily due to $559 millionof incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales at Northern Natural Gasof $91 millionand higher transportation revenue of $33 millionat Northern Natural Gas, largely due to the favorable impacts of the February 2021polar vortex weather event. Net income increased $204 millionfor the first quarter of 2021 compared to 2020, primarily due to $107 millionof incremental net income at BHE GT&S and higher earnings of $98 millionat 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 millionfor the first quarter of 2021 compared to 2020, primarily due to $10 millionfrom the stronger United Statesdollar 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 2020at AltaLink. Net income increased $4 millionfor the first quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana- AlbertaTie-Line and lower non-regulated interest expense at BHE Canada. BHE RenewablesOperating revenue increased $12 millionfor 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 millionfor 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 2021polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation. 32 --------------------------------------------------------------------------------
Operating revenue increased
$339 millionfor the first quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $228 millionfrom a 35% increase in closed transaction volume and higher mortgage revenue of $92 millionfrom a 63% increase in funded mortgage volume due to an increase in refinance activity from the favorable interest rate environment. Net income increased $74 millionfor the first quarter of 2021 compared to 2020, primarily due to higher earnings from mortgage services of $36 millionand brokerage services of $27 millionlargely attributable to the favorable interest rate environment. BHE and Other Operating revenue increased $83 millionfor 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 millionfor the first quarter of 2021 compared to 2020, primarily due to the $857 millionunfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 millionof 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 2020and 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, 2020for 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 $ 1,276Credit 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 $ 9,220Credit facilities: Maturity dates 2022 2022 2021, 2022 2022 2023 2021, 2024 2021, 2022 33
Net cash flows from operating activities for the three-month periods ended
March 31, 2021and 2020 were $1.5 billionand $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.
Net cash flows from investing activities for the three-month periods ended
March 31, 2021and 2020 were $(1.4) billionand $(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.
Net cash flow from financing activities for the three-month period ended
For an analysis of recent financing transactions, refer to note 5 of the notes to the consolidated financial statements in part I, point 1 of this form 10-Q.
Net cash flows from financing activities for the three-month period ended
March 31, 2020was $1.4 billion. Sources of cash totaled $4.3 billionand consisted of proceeds from BHE senior debt issuances totaling $3.2 billionand subsidiary debt issuances totaling $1.1 billion. Uses of cash totaled $3.0 billionand 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 millionand 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.
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 -------------------------------------------------------------------------------- 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 $ 1,897MidAmerican 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 $ 7,378Capital expenditures by type: Wind generation $ 273 $ 97 $ 1,158Electric 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 others represent amounts mainly related 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 Energytotaling $154 millionfor the three-month period ended March 31, 2020. MidAmerican Energy'sforecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 millionand include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021. •Repowering of wind-powered generating facilities at MidAmerican Energytotaling $24 millionand $6 millionfor the three-month periods ended March 31, 2021and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $379 millionfor the remainder of 2021. MidAmerican Energyexpects 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. 35 -------------------------------------------------------------------------------- •Construction of wind-powered generating facilities at PacifiCorptotaling $27 millionand $89 millionfor the three-month periods ended March 31, 2021and 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's2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorpanticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorpanticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 millionfor 2021. •Repowering existing wind-powered generating facilities at PacifiCorptotaling $5 millionand $16 millionfor the three-month periods ended March 31, 2021and 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 millionfor 2021. •Acquisition and repowering of wind-powered generating facilities at PacifiCorptotaling $1 millionfor the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 millionfor 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'scosts for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp'sEnergy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities'Greenlink Nevada transmission expansion program and AltaLink'sdirectly 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'scurrent 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 Lakegenerating facility. Commercial operation at Dry Lakeis 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 millionfor 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
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, 2020other than the recent financing transactions and renewable tax equity investments previously discussed.
Quad Cities Power Plant 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 Energyhas a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Stationon June 1, 2018. In December 2016, Illinoispassed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agencyto 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 Generationadditional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energywill 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 Stationnot receiving capacity revenues in future auctions. On December 19, 2019, the FERCissued 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 FERCincluded some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERCprovided 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'sorder, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC'sdirectives and a schedule for resuming capacity auctions. On April 16, 2020, the FERCissued an order largely denying requests for rehearing of the FERC's December 2019order 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 FERCissued an order denying requests for rehearing of its April 16, 2020order 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 FERCalso 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 FERCin another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021. On May 21, 2020, the FERCissued 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 FERCalso 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 FERCis 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 Generationis currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinoisimplements the FRR option, Quad Cities Stationcould be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinoiscannot 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 Illinoiswill require both legislative and regulatory changes. MidAmerican Energycannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station. 37 --------------------------------------------------------------------------------
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, 2020and new regulatory matters occurring in 2021.
March 2020, PacifiCorpfiled its annual EBA application with the UPSC requesting recovery of $37 millionof deferred power costs from customers for the period January 1, 2019through 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 2021for rates effective March 1, 2021.
February 2020, PacifiCorpfiled 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'sproposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp'scompliance filing to reset base rates effective January 1, 2021in 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 Creekrepowered wind facility and the Pryor Mountainnew wind facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021. WyomingIn September 2018, PacifiCorpfiled an application for depreciation rate changes with the WPSC based on PacifiCorp's2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018include the filing of PacifiCorp's2020 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, PacifiCorpfiled a stipulation with the WPSC resolving all issues addressed in PacifiCorp'sdepreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp'sgeneral 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'swind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020and 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, PacifiCorpfiled an application in October 2020with 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, PacifiCorpfiled 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, PacifiCorpfiled its rebuttal testimony that modified its requested increase in base rates from $7 millionto $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'scase and rescheduled the hearings. The hearings began February 2021and were completed in March 2021. The WPSC decision is pending. PacifiCorphas requested a rate effective date of July 1, 2021. 38 -------------------------------------------------------------------------------- In April 2021, PacifiCorpfiled its annual ECAM and RRA application with the WPSC requesting to refund $15 millionof deferred net power costs and RECs to customers for the period January 1, 2020through 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. PacifiCorphas requested an interim rate effective date of July 1, 2021.
March 2021, PacifiCorpfiled its annual ECAM application with the IPUC requesting recovery of $14 millionfor 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 Side2 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.
CaliforniaSenate 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. PacifiCorpsubmitted its 2021 California Wildfire Mitigation Plan Update in March 2021.
FERC justification order
April 15, 2021, the FERCissued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcementstaff that PacifiCorpfailed to comply with certain North American Electric Reliability Corporation(the "NERC") reliability standards associated with facility ratings on PacifiCorp'sbulk electric system. The order directs PacifiCorpto show cause as to why it should not be assessed a civil penalty of $42 millionas a result of the alleged violations. The allegations are related to PacifiCorp'sresponse 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. PacifiCorpwill file a response to the allegations with the FERC.
Natural gas purchased for resale
February 2021, severe cold weather over the central United Statescaused 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'sretail customers and caused an approximate $245 millionincrease 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 2021through 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. 39
NV Energy (Nevada Power and Sierra Pacific)
Price stability tariff
November 2018, the Nevada Utilitiesmade filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilitieshave 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 Utilitieswithdrew their filings. In May 2020, the Nevada Utilitiesrefiled 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 Utilitiesto 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 Utilitiesfiled a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilitiesfiled an update to the CPST program per the November 2020order and an updated CPST tariff with the PUCN. An order is expected in the second quarter of 2021.
Natural disaster protection plan
The Nevada Utilitiessubmitted 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 2020that 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 2021and an order is expected in the second quarter of 2021. In March 2021, the Nevada Utilitiesfiled 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 electricity distribution companies
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'snext 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'sconsumer 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, GEMApublished its decision on the methodology it will use to set the ED2 price control and prices from April 2023to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution. GEMApublished 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. 40 --------------------------------------------------------------------------------
January 2020, pursuant to the terms of a previous settlement, Cove Pointfiled a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Pointproposed an annual cost-of-service of $182 million. In February 2020, the FERCapproved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Pointreached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point'srates effective August 1, 2020result in an increase to annual revenues of $4 millionand 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'sprovision for rate refunds for August 2020through October 2020totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERCin January 2021. In March 2021, the FERCapproved the stipulation and agreement and the rate refunds to customers were processed in late April. BHE Transmission AltaLinkTariff Refund Application In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLinkfiled an application with the AUC that requested approval of tariff relief measures totaling C$350 millionover the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 millionof previously collected future income taxes and C$200 millionof surplus accumulated depreciation. The future income tax refund would be evenly distributed over the two-year period, 2021 to 2022, with C$75 millionincluded in each year. The accumulated depreciation surplus would be refunded over the three-year period, 2021 to 2023, with C$60 millionincluded in 2021 and 2022, and C$80 millionin 2023. If approved by the AUC, these tariff relief measures would have saved customers an estimated C$317 millionover the three-year period, 2021 to 2023. In March 2021, the AUC issued a decision on AltaLink'sTariff Refund Application and approved a 2021 tariff refund in the amount of C$230 millionand a net 2021 tariff reduction of C$224 million, which provides Albertaratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 millionof previously collected future income tax and a refund of C$80 millionof accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed in AltaLink's2022-2023 GTA.
General rate request 2019-2021
August 2018, AltaLinkfiled 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 millionfor customers for the next five years. In addition, AltaLinkproposed 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, AltaLinkfiled an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 millionand C$885 millionfor 2019, 2020 and 2021, respectively. In July 2019, AltaLinkfiled 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 millionto the three year total revenue requirement applied for in AltaLink's2019-2021 GTA updated in April 2019. However, this was offset by AltaLink'srequest for an additional C$20 millionof 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'ssalvage proposal is estimated to save customers C$267 millionbetween 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020. 41
April 2020, the AUC issued its decision with respect to AltaLink's2019-2021 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'sproposed 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 millionof the additional C$20 million AltaLinkrequested for forecast transmission line clearance capital. The remaining C$7 millionof capital investment was reviewed in AltaLink'ssubsequent compliance filing. Also, C$3 millionof forecast operating expenses and C$4 millionof forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 millionof capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 millionof retirements for towers and fixtures. In July 2020, the AUC approved AltaLink'scompliance filing establishing revised revenue requirements of C$895 millionfor 2019, C$894 millionfor 2020 and C$898 millionfor 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnershipand the KainaiLink Limited Partnership. The AUC deferred its decision on AltaLink'sproposed salvage methodology included in AltaLink's2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLinkfiled an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink'sproposed 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'sproposed salvage methodology. In October 2020, AltaLinkfiled 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'sreview and variance application. The AUC decided to vary the original decision and approve AltaLink'sproposed 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'srevenue requirement from customers by C$24 million, C$27 millionand C$31 millionfor the years 2019, 2020 and 2021, respectively. AltaLinkdelivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink'sapproved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 millionfrom 2019 to 2021.
General tariff request 2022-2023
April 2021, AltaLinkfiled 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 millionfor 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 millionrefund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLinkproposed to provide further similar tariff reductions over the two years by refunding an additional C$60 millionper year. The application requested the approval of transmission tariff of C$824 millionand C$847 millionfor 2022 and 2023, respectively.
Generic procedure on the cost of capital 2022
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, AltaLinksubmitted 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. AltaLinkfurther 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. AltaLinksuggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years. 42 -------------------------------------------------------------------------------- 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 Albertaratepayers. In April 2021, the Utilities Consumer Advocatefiled an application with the Court of Appeal of Albertarequesting 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 Advocatealleges 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
March 2021, the AUC issued its decision on AltaLink's2019 Deferral Accounts Reconciliation Application. The AUC approved C$128.0 millionof the C$128.5 millionof gross capital project additions, disallowing C$0.5 millionof 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. AltaLinkfiled 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.
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 Statesagreed 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 ParisAgreement became effective November 4, 2016. On June 1, 2017, President Trumpannounced the United Stateswould begin the process of withdrawing from the Paris Agreement. The United Statescompleted its withdrawal from the ParisAgreement on November 4, 2020. President Bidenaccepted the terms of the climate agreement January 20, 2021, and the United Statescompleted its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Bidenannounced 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 Stateswill implement these goals is anticipated to be released through fall 2021.
The Clean Air Act is a federal law administered by the
EPAthat 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 EPAapproval. 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. 43 --------------------------------------------------------------------------------
GHG performance standards
Under the Clean Air Act, the
EPAmay 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 EPAissued 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 EPAannounced revisions to new source performance standards for new and reconstructed coal-fueled units. EPAproposes 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 EPAwould 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, EPAfinalized 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. EPAconfirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section111(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 Registerbut 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
EPAsets 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 EPAfinalized 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 EPAdid not issue its final designations until July 2013and determined, at that date, that a portion of Muscatine County, Iowawas in nonattainment for the one-hour SO2 standard. MidAmerican Energy'sLouisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPAindicated 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 EPAwill make decisions for areas and sources outside Muscatine County. MidAmerican Energydoes not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013designations did not impact PacifiCorp'snor 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 EPAissued a decision to retain the 2010 SO2 NAAQS without revision. 44 -------------------------------------------------------------------------------- The Sierra Clubfiled a lawsuit against the EPAin August 2013with 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 Districtof California") accepted as an enforceable order an agreement between the EPAand Sierra Clubto resolve litigation concerning the deadline for completing the designations. The Northern Districtof California'sorder directed the EPAto 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 EPAto 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'sGeorge Neal Unit 4 and the Ottumwa Generating Station(in which MidAmerican Energyhas 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 EPAupdated recommendations and supporting information for the EPAto consider in making its determinations. Iowasubmitted documentation to the EPAin April 2016supporting its recommendation that Des Moines, Wapelloand WoodburyCounties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Registerindicating portions of Muscatine County, Iowawere in nonattainment with the 2010 SO2 standard, Woodbury County, Iowawas unclassifiable, and Des Moinesand WapelloCounties were unclassifiable/attainment. On March 26, 2021, the EPAissued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyomingas an Attainment/Unclassifiable area. PacifiCorp's Dave Johnstongenerating facility is located in Converse County. No further action by PacifiCorpis required.
Interstate Air Pollution Rule
EPApromulgated an initial rule in March 2005to 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 EPAreleased a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Registerin October 2016and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPAfinalized 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. EPAdetermined 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 Statesin 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 EPAallowed 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 EPAproposed 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 EPApredicts that emissions from the remaining nine states, including Iowaand Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPAaccepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPAfinalized 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'scoal-fueled generating facilities in Utah, Wyoming, Arizonaand Coloradoand 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 -------------------------------------------------------------------------------- The state of Utahissued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and HuntingtonUnits 1 and 2. In December 2012, the EPAapproved the SO2 portion of the Utahregional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Qualitycompleted an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPApublished 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 Utahregional haze SIP was effective August 4, 2016. The EPAapproved in part and disapproved in part the Utahregional 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. PacifiCorpand other parties filed requests with the EPAto 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 EPAissued 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 EPAconducts its reconsideration process. To support the reconsideration, PacifiCorpundertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utahsubmitted 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 Utahregional haze SIP revision, which incorporates a BART alternative into Utah'sregional haze SIP. The BART alternative makes the shutdown of PacifiCorp'sCarbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and HuntingtonUnits 1 and 2. The Utah Division of Air Qualitysubmitted the SIP revision to the EPAfor approval at the end of 2019. In January 2020, the EPApublished its proposed approval of the UtahRegional 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 Huntingtonplants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPAreleased the final rule approving the UtahRegional Haze SIP Alternative on October 28, 2020. With the approval, the EPAalso finalized its withdrawal of the FIP requirements for the Hunter and Huntingtonplants. The UtahRegional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utahregional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Cluband Utah Physicians for a Healthy Environment filed a petition for review of the UtahRegional Haze SIP Alternative in the Tenth Circuit. PacifiCorpand the state of Utahmoved 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 -------------------------------------------------------------------------------- PacifiCorpand its subsidiaries Consolidated Financial Section 47 -------------------------------------------------------------------------------- PART I
Item 1: financial statements
© Edgar Online, source