Quad Cities Generating Station Operating Status
Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.
On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.
Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019 and new regulatory matters occurring in 2020.
PacifiCorp
Multi-State ProcessOperating revenue increased $154 million for the second quarter of 2021 compared to 2020, primarily due to higher retail revenue of $124 million and higher wholesale and other revenue of $30 million. Retail revenue increased due to higher customer volumes of $132 million, partially offset by price impacts of $8 million from lower rates due to certain general rate case orders. Retail customer volumes increased 11.6%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wheeling revenue and wholesale volumes, partially offset by lower average wholesale market prices.
InNet income increased $59 million for the second quarter of 2021 compared to 2020, primarily due to higher utility margin of $96 million, favorable income tax expense, from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and lower property taxes of $9 million, partially offset by higher depreciation and amortization expense of $65 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $17 million and higher operations and maintenance expense of $12 million. Utility margin increased primarily due to the higher retail, wheeling and wholesale revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power costs and higher thermal generation costs.
Operating revenue increased $190 million for the first six months of 2021 compared to 2020, primarily due to higher retail revenue of $144 million and higher wholesale and other revenue of $46 million. Retail revenue increased due to higher customer volumes of $148 million, partially offset by price impacts of $4 million from lower rates due to certain general rate case orders. Retail customer volumes increased 5.7%, primarily due to higher customer usage, the favorable impact of weather and an increase in the average number of customers. Wholesale and other revenue increased primarily due to higher wholesale volumes, higher wheeling revenue and higher average wholesale market prices.
Net income increased $52 million for the first six months of 2021 compared to 2020, primarily due to higher utility margin of $125 million and favorable income tax expense from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, partially offset by higher depreciation and amortization expense of $77 million, including the impacts of a depreciation study effective January 1, 2021, lower allowances for equity and borrowed funds used during construction of $29 million and higher operations and maintenance expense of $17 million. Utility margin increased primarily due to the higher retail, wholesale and wheeling revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher thermal generation costs and higher purchased power costs.
MidAmerican Funding
Operating revenue increased $77 million for the second quarter of 2021 compared to 2020, primarily due to higher electric operating revenue of $68 million and higher natural gas operating revenue of $11 million. Electric operating revenue increased due to higher retail revenue of $48 million and higher wholesale and other revenue of $20 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher customer volumes of $30 million, higher recoveries through adjustment clauses of $16 million (largely offset in cost of sales), and price impacts of $2 million from changes in sales mix. Electric retail customer volumes increased 9.2% due to increased usage of certain industrial customers and the favorable impact of weather. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $17 million (offset in cost of sales), partially offset by a 4.8% decrease in customer volumes.
Net income increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $36 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $34 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and unfavorable changes in the cash surrender value of corporate-owned life insurance policies. 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 primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.
Operating revenue increased $458 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $314 million and higher electric operating revenue of $142 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold resulting in higher purchased gas adjustment recoveries of $321 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event, partially offset by a 1.3% decrease in customer volumes. Electric operating revenue increased due to higher retail revenue of $90 million and higher wholesale and other revenue of $52 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $48 million (largely offset in cost of sales), higher customer volumes of $35 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 7.0% due to increased usage of certain industrial customers and the favorable impact of weather.
Net income decreased $3 million for the first six months of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $65 million, from additional assets placed in-service and a regulatory mechanism deferring certain depreciation expense in 2020, and $30 million higher operations and maintenance expenses, partially offset by higher electric utility margin of $39 million, 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 primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs.
NV Energy
Operating revenue increased $72 million for the second quarter of 2021 compared to 2020 due to higher electric operating revenue, which increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $77 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $15 million at Nevada Power. Electric retail customer volumes increased 11.2%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather.
Net income increased $2 million for the second quarter of 2021 compared to 2020, primarily due to lower income tax expense from the impacts of ratemaking and lower interest expense of $6 million, partially offset by higher depreciation and amortization expense of $12 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $4 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.
Operating revenue increased $41 million for the first six months of 2021 compared to 2020, primarily due to higher electric operating revenue of $51 million, partially offset by lower natural gas operating revenue of $10 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $73 million, higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers, partially offset by lower base tariff general rates of $24 million at Nevada Power. Electric retail customer volumes increased 4.4%, primarily due to the impacts from COVID-19 recovery and the favorable impact of weather. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold (offset in cost of sales).
Net income increased $16 million for the first six months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $21 million, primarily from lower regulatory instructed deferrals and amortizations, lower income tax expense from the impacts of ratemaking, lower interest expense of $12 million, lower pension costs and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $24 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service, and lower electric utility margin of $22 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers.
Northern Powergrid
Operating revenue increased $59 million for the second quarter of 2021 compared to 2020, primarily due to $31 million from the weaker United States dollar and higher distribution revenue of $26 million, mainly from 10.9% higher units distributed of $16 million and increased tariff rates of $9 million.
Net income decreased $84 million for the second quarter of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue.
Operating revenue increased $93 million for the first six months of 2021 compared to 2020, primarily due to $52 million from the weaker United States dollar and higher distribution revenue of $39 million, mainly from increased tariff rates of $19 million and 4.7% higher units distributed of $16 million.
Net income decreased $67 million for the first six months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to an enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue and $6 million from the weaker United States dollar.
BHE Pipeline Group
Operating revenue increased $481 million for the second quarter of 2021 compared to 2020, primarily due to $487 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher gas sales at Northern Natural Gas of $14 million (largely offset in cost of sales), partially offset by lower transportation revenue of $27 million at Northern Natural Gas, primarily due to lower volumes and rates.
Net income increased $36 million for the second quarter of 2021 compared to 2020, primarily due to $66 million of incremental net income at BHE GT&S, partially offset by lower earnings of $34 million at Northern Natural Gas, largely due to the lower transportation revenue and a favorable adjustment in 2020 from a rate case settlement.
Operating revenue increased $1,173 million for the first six months of 2021 compared to 2020, primarily due to $1,047 million of incremental revenue at BHE GT&S, higher gas sales of $77 million and higher transportation revenue of $49 million at Northern Natural Gas, each due to the favorable impacts of the February 2021 polar vortex weather event, and higher gas sales at Northern Natural Gas of $28 million (largely offset in cost of sales), partially offset by lower transportation revenue of $50 million at Northern Natural Gas, primarily due to lower volumes and rates.
Net income increased $240 million for the first six months of 2021 compared to 2020, primarily due to $173 million of incremental net income at BHE GT&S and higher earnings of $64 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales and higher transportation revenue, each due to the favorable impacts of the February 2021 polar vortex weather event, partially offset by the lower transportation revenue due to lower volumes and rates.
BHE Transmission
Operating revenue increased $13 million for the second quarter of 2021 compared to 2020, primarily due to $20 million from the stronger United States dollar, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.
Operating revenue increased by $21 million for the first six months of 2021 compared to 2020, primarily due to $31 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.
Net income increased $4 million for the first six months of 2021 compared to 2020, primarily due to $8 million from the stronger United States dollar, higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada, partially offset by the impacts of favorable regulatory decisions received in April and November 2020 at AltaLink.
BHE Renewables
Operating revenue increased $23 million for the second quarter of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal and wind revenues from higher generation as well as higher capacity payments at a natural gas facility, partially offset by an unfavorable change in the valuation of a power purchase agreement of $12 million.
Net income increased $43 million for the second quarter 2021 compared to 2020, primarily due to higher wind earnings of $32 million, largely from tax equity investment projects reaching commercial operation, and higher solar earnings of $9 million, mainly due to the higher operating revenue and lower depreciation expense.
Operating revenue increased $35 million for the first six months of 2021 compared to 2020, primarily due to higher natural gas, solar, geothermal, hydro and wind revenues from higher generation, as well higher capacity payments at a natural gas facility and favorable pricing at the geothermal facilities, partially offset by an unfavorable change in the valuation of a power purchase agreement of $14 million.
Net income decreased $36 million for the first six months of 2021 compared to 2020, primarily due to lower wind earnings of $62 million, largely from lower tax equity investment earnings of $58 million, partially offset by higher solar earnings of $16 million, mainly due to the higher operating revenue and lower depreciation expense, and higher geothermal earnings of $11 million. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $134 million, primarily due to the February 2021 polar vortex weather event, partially offset by $78 million of earnings from projects reaching commercial operation. Geothermal earnings increased primarily due to higher natural gas margins and the higher geothermal revenue, partially offset by higher operations and maintenance expense.
HomeServices
Operating revenue increased $570 million for the second quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $589 million from a 72% increase in closed transaction volume resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $51 million due to a 62% decrease in refinance activity.
Net income increased $76 million for the second quarter of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $54 million, largely due to the increase in closed transaction volume, and mortgage services of $12 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement offset by the decrease in refinancing activity.
Operating revenue increased $909 million for the first six months of 2021 compared to 2020, primarily due to higher brokerage revenue of $816 million from a 56% increase in closed transaction volume, resulting from increases in closed units and average sales price, and higher mortgage revenue of $41 million from a 26% increase in funded mortgage volume.
Net income increased $150 million for the first six months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $79 million, largely due to the increase in closed transaction volume, and mortgage services of $48 million, largely attributable to an unfavorable 2020 contingent earn-out remeasurement and the increase in funded mortgage volume.
BHE and Other
Operating revenue increased $3 million for the second quarter of 2021 compared to 2020, primarily due to higher electricity sales revenue at MidAmerican Energy Services, LLC, from higher volumes offset by unfavorable pricing.
Net income increased $993 million for the second quarter of 2021 compared to 2020, primarily due to the $1,012 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $48 million of higher federal income tax credits recognized on a consolidated basis and higher net income of $8 million at MidAmerican Energy Services, LLC, partially offset by higher other corporate costs, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and unfavorable changes in the cash surrender value of corporate-owned life insurance policies.
Operating revenue increased $86 million for the first six months 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 income increased $68 million for the first six months of 2021 compared to 2020, primarily due to the $155 million favorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $42 million of higher federal income tax credits recognized on a consolidated basis, favorable changes in the cash surrender value of corporate-owned life insurance policies and higher net income of $12 million at MidAmerican Energy Services, LLC, partially offset by $75 million of dividends on BHE's 4.00% Perpetual Preferred Stock, higher other corporate costs and higher BHE corporate interest expense.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of June 30, 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 | $ | 526 | | | $ | 44 | | | $ | 31 | | | $ | 79 | | | $ | 17 | | | $ | 57 | | | $ | 577 | | | $ | 1,331 | |
| | | | | | | | | | | | | | | |
| Credit facilities | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 222 | | | 867 | | | 3,541 | | | 11,489 | |
| Less: | | | | | | | | | | | | | | | |
| Short-term debt | — | | | (301) | | | — | | | (74) | | | (15) | | | (262) | | | (1,884) | | | (2,536) | |
| Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | |
| Net credit facilities | 3,500 | | | 681 | | | 1,139 | | | 576 | | | 207 | | | 604 | | | 1,657 | | | 8,364 | |
| | | | | | | | | | | | | | | |
| Total net liquidity | $ | 4,026 | | | $ | 725 | | | $ | 1,170 | | | $ | 655 | | | $ | 224 | | | $ | 661 | | | $ | 2,234 | | | $ | 9,695 | |
| Credit facilities: | | | | | | | | | | | | | | | |
| Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2023 | | 2022, 2025 | | 2021, 2022 | | |
| | | | | | | | | | | | | | | |
Operating Activities
Net cash flows from operating activities for the six-month periods ended June 30, 2021 and 2020 were $4.2 billion and $1.9 billion, respectively. The increase was primarily due to favorable income tax cash flows, improved operating results and 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 six-month periods ended June 30, 2021 and 2020 were $(3.0) billion and $(3.8) billion, respectively. The change was primarily due to lower funding of tax equity investments, partially offset by higher capital expenditures of $55 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the six-month period ended June 30, 2021 was $(1.2) billion. Uses of cash totaled $2.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.2 billion, repayments of BHE senior debt totaling $450 million and distributions to noncontrolling interests of $234 million. Sources of cash totaled $793 million and consisted primarily of proceeds from subsidiary debt issuances totaling $539 million and net proceeds from short-term debt totaling $245 million.
For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Net cash flows from financing activities for the six-month period ended June 30, 2020 was $2.8 billion. Sources of cash totaled $5.7 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.4 billion, net repayments of short-term debt totaling $920 million, 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.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Six-Month Periods | | Annual |
| Ended June 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| Capital expenditures by business: | | | | | |
| PacifiCorp | $ | 973 | | | $ | 819 | | | $ | 1,782 | |
| MidAmerican Funding | 824 | | | 720 | | | 2,170 | |
| NV Energy | 366 | | | 365 | | | 842 | |
| Northern Powergrid | 312 | | | 369 | | | 760 | |
| BHE Pipeline Group | 196 | | | 308 | | | 1,225 | |
| BHE Transmission | 222 | | | 156 | | | 269 | |
| BHE Renewables | 26 | | | 80 | | | 181 | |
| HomeServices | 14 | | | 18 | | | 37 | |
BHE and Other(1) | (140) | | | 13 | | | 78 | |
| Total | $ | 2,793 | | | $ | 2,848 | | | $ | 7,344 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
| Capital expenditures by type: | | | | | |
| Wind generation | $ | 718 | | | $ | 483 | | | $ | 1,156 | |
| Electric distribution | 743 | | | 817 | | | 1,842 | |
| Electric transmission | 527 | | | 339 | | | 919 | |
| Natural gas transmission and storage | 178 | | | 308 | | | 1,099 | |
| Solar generation | 1 | | | 67 | | | 288 | |
| Other | 626 | | | 834 | | | 2,040 | |
| Total | $ | 2,793 | | | $ | 2,848 | | | $ | 7,344 | |
(1)BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation expenditures include the following:
◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $172 million for 2021 and $388 million for 2020. Planned spending for the construction of additional wind-powered generating facilities totals $198 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $82 million for 2021 and $19 million for 2020. Planned spending for repowering generating facilities totals $284 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of June 30, 2021, 80 MWs are currently expected to qualify for 100% of the 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.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $79 million and $395 million for the six-month periods ended June 30, 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 completed negotiationsanticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the Multi-State Process Workgroup,construction of wind-powered generating facilities will total an additional $39 million for 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $3 million and $46 million for the six-month periods ended June 30, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first six months of 2021. The energy production from these existing 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 repowering of wind-powered generating facilities totals $47 million for 2021.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $55 million for the six-month period ended June 30, 2021. In May 2021, BHE Renewables completed the asset acquisition of a 54 MW wind-powered generating facility located in Iowa. BHE Renewables anticipates costs to complete construction of this facility will total an additional $30 million in 2021.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 141 MWs of small- and utility-scale solar generation during 2021, of which 61 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.
•Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.
Other Renewable Investments
The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made no contributions for the six-month period ended June 30, 2021, and has commitments as of June 30, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $766 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.
Contractual Obligations
As of June 30, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 other than the recent financing transactions and renewable tax equity investments previously discussed.
Quad Cities Generating Station Operating Status
Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new cost allocation agreement,gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, Protocol. The agreement establisheswherein the PJM proposed tariff language reflecting the FERC's directives and a common allocation methodschedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding.
On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in Utah, Oregon, Wyoming, Idahocalculating a number of parameters and California through 2023assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and a separate methodthe timing for Washington duringcommencing the same time periodcapacity auction schedule.
Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that is basedmay not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on a system approachthe continued operation of Quad Cities Station.
In May 2021, the PJM conducted its capacity auction as scheduled, and because Illinois has not implemented an FRR program, the MOPR applied to Quad Cities Station in the capacity auction. The MOPR prevented Quad Cities Station from clearing in the auction.
Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for cost allocationsearly retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism under which Quad Cities Station would be removed from the PJM's capacity auction. At the direction of the PJM Board of Managers, the PJM and provides a path forward for Washingtonits stakeholders are considering MOPR reforms to achieve compliance with Washington's newly-enacted Clean Energy Transformation Act.ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which the PJM filed at the FERC on July 30, 2021.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The agreement establishes a processdiscussion 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 Protocol signatoriesand new regulatory matters occurring in 2021.
PacifiCorp
Utah
In March 2020, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $37 million of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to resolve remaining outstanding cost-allocationscurrent rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.
In March 2021, PacifiCorp filed its annual Energy Balancing Account application with the UPSC requesting recovery of $2 million of deferred net power costs from customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflected a $36 million reduction or 1.7% decrease compared to be implementedcurrent rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The updated recovery request reflects a $31 million reduction, or 1.5% decrease compared to current rates.
In August 2021, PacifiCorp filed an application with the UPSC for alternative cost recovery of a major plant addition to recover the incremental revenue requirement related to the delayed portions of the Pryor Mountain and TB Flats wind-powered generating facilities that are not currently reflected in rates from the last general rate case. PacifiCorp's request results in a new, permanentnet decrease of $4 million, or 0.2%, in base rates effective January 1, 2022. Requested recovery of $7 million for the capital-related cost is offset by $7 million related to forecast PTCs and long-term allocation method at$4 million in net power cost savings. Actual PTCs and net power cost will be trued-up in the end of the four years. Energy Balancing Account.
Oregon
In December 2019,February 2020, PacifiCorp submitted the 2020 Protocol to the UPSC, the OPUC, the WPSC and the IPUC for approval. WUTC approval of the agreement is being sought in thefiled a general rate case, filing submittedand in December 2019, and CPUC approval will be requested in a future general rate case. In January 2020, the OPUC issued anapproved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order adoptingreflected a rate decrease of approximately $67 million, or 5.1%, due to the 2020 Protocol. The WPSC heldexclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings have been made to include these investments in rates concurrent with 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-powered generating facility to rates, resulting in a hearing and issued a bench decision approving the 2020 Protocol in March 2020.rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2020,2021, the UPSCOPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the IPUC issued orders approvingPryor Mountain new wind-powered generating facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.
In July 2021, in accordance with the OPUC's December 2020 Protocol.general rate case order, PacifiCorp filed an application with the OPUC to initiate the review of PacifiCorp's estimated decommissioning and other closure costs per third-party studies associated with its coal-fueled generating facilities. The application requested an initial rate increase of $35 million, or 2.8%, effective January 1, 2022, to recover the incremental costs from those approved in the last general rate case.
Wyoming
Depreciation Rate Study
In September 2018, PacifiCorp filed applicationsan application for depreciation rate changes with the UPSC, the OPUC, the WPSC the WUTC and the IPUC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Based on the proposed depreciation rates, annual depreciation expense would increase approximately $300 million. Parties to the applications in each state have since evaluated the study and updates provided by PacifiCorp and have participated in multi-party discussions. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities.
In December 2019, PacifiCorp incorporated the depreciation rate study into its general rate case filing with the WUTC, which was later updated to incorporate the 2020 decommissioning studies. In July 2020, PacifiCorp filed a stipulation with the WUTC resolving all issues addressed in PacifiCorp's depreciation rate study application. The stipulation is subject to the WUTC's approval and an order is expected by the end of 2020.
In March 2020, PacifiCorp filed a partial settlement stipulation with the UPSC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and established a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities and equipment replaced as a result of PacifiCorp's wind repowering projects. The second phase is scheduled to conclude in November 2020. The stipulation provides for the treatmentremoval of Cholla Unit 4 to be addressed in PacifiCorp's pending general rate case. In April 2020, the UPSC approved the stipulation as filed.
In March 2020, PacifiCorp filed motions with the OPUC to remove matters associated with its coal-fueled generating facilities from the depreciation rate study and instead expand its general rate case to address depreciation rates and decommissioning costs associated with its coal-fueled generating facilities. In April 2020, the motions were granted by the OPUC. In August 2020, PacifiCorp filed an all‑party stipulation with the OPUC resolving all remaining issues in the depreciation study. A final decision on the stipulation is pending.
4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case. The general rate case, will determine ratemaking treatment of Cholla Unit 4; Wyoming's share ofincluding depreciation for coal-fueled generating facilities including additionaland associated incremental decommissioning costs identifiedreflected in PacifiCorp's 2020 decommissioning studies;studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent bench decisionwritten order in AugustDecember 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study.
In June 2020, PacifiCorp filed a partial settlement stipulation with the IPUC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and proposes a secondary phase to the proceeding be established in order to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities. In August 2020, the IPUC approved the stipulation and authorized a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal‑fueled generating facilities.
As a result of delaying the general rate case filing in Idaho to 2021 for an anticipated effective date of January 1, 2022, PacifiCorp reached a separate agreement with parties to defer the incremental depreciation expense from the 2018 depreciation study for one year, during 2021. In October 2020, a settlement stipulation was filed with the IPUC to defer the incremental decommissioning expense from the 2020 decommissioning studies for one year, during 2021, consistent with the treatment of the incremental depreciation expense.
Retirement Plan Settlement Charge
During 2018, the PacifiCorp Retirement Plan incurred a settlement charge as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018. In December 2018, PacifiCorp submitted filings with the UPSC, the OPUC, the WPSC and the WUTC seeking approval to defer the settlement charge. Also in December 2018, an advice letter was filed with the CPUC requesting a memorandum account to track the costs associated with pension and postretirement settlements and curtailments. In October 2019, the request for a memorandum account was re-filed as an application with the CPUC. In 2019, the WUTC approved the requested deferral, while the UPSC and the WPSC denied the request. In January 2020, the OPUC issued an order denying PacifiCorp's request. In April 2020, the CPUC approved the request to establish a memorandum account effective December 31, 2018.
COVID-19
In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID‑19 with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC. In April 2020, as ordered by the CPUC, PacifiCorp filed to establish the COVID‑19 Pandemic Protections Memorandum Account. The memorandum account was approved in September 2020, retroactive to March 4, 2020. In April 2020, the WPSC approved PacifiCorp's application to defer costs associated with COVID‑19, subject to a public notice period, and required associated benefits arising from COVID‑19 to be offset against the deferred costs. During the public notice period, one party to the proceeding filed a petition for a rehearing of the matter. The WPSC has scheduled a A hearing for this matter in April 2021. In July, September and October 2020, the IPUC, the UPSC and the OPUC, respectively, approved PacifiCorp's applications to defer costs associated with COVID‑19, requiring associated benefits arising from COVID‑19 to be offset against the deferred costs.
Utah
In March 2019, PacifiCorp filed its annual EBAdeferral application with the UPSC requesting recovery of $24 million, or 1.1%, of deferred net power costs from customers for the period January 1, 2018 through December 31, 2018, reflecting the difference between base and actual net power costs in the 2018 deferral period. The rate change was approved by the UPSC effective May 1, 2019 on an interim basis. Following a decision from the Utah Supreme Court in June 2019 that found the UPSC did not have authority to approve interim rates in conjunction with the EBA, the UPSC directed PacifiCorp to terminate the interim rate change pending final approval in the proceeding. The hearing on final approval was held in February 2020, and the UPSC issued an order approving full recovery of the 2018 deferred costs beginning April 1, 2020.
In May 2019, Utah House Bill 411 went into effect. The legislation, among other things, authorizes the UPSC to approve a renewable energy program for communities seeking 100% renewable electricity. Participating cities were required to adopt a resolution with a goal to be on 100% renewable electricity by 2030 before December 31, 2019. Twenty-four communitiesJuly 2021. Public deliberations are expected in Utah, including Salt Lake City, passed the resolution before December 31, 2019. Customers within a participating community may opt out of the program and maintain existing rates. Rates approved for the program may not result in any shift of costs or benefits to nonparticipating customers. The program details, including costs, are being developed with the communities for a future filing with the UPSC.
In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million, or 1.0%, of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. Hearings are scheduled for January 2021 for rates effective March 1,August 2021.
In March 2020, Utah's governor signed Utah House Bill 66, Wildland Fire Planning and Cost Recovery Amendments, which requires PacifiCorp to prepare a wildfire protection plan to be approved by the UPSC. All investments, including the cost of capital, made to implement an approved plan are recoverable in rates. The bill also provides a potential liability safe harbor if PacifiCorp is in compliance with its approved wildfire mitigation plan. In addition, the legislation clarifies the standard for real property losses and eliminates the current standard of treble damages awarded for tree losses. The first wildland fire protection plan was filed with the UPSC in June 2020 and was approved by the UPSC in October 2020.
In March 2020, Utah's governor signed Utah House Bill 396, Electric Vehicle Charging Infrastructure Amendments, which directs the UPSC to enable PacifiCorp to recover in rates up to $50 million of electric vehicle infrastructure. The legislation also prohibits a third‑party from generating electricity onsite to directly resell to customers through electric vehicle charging infrastructure.
In May 2020, PacifiCorp filed a general rate case with the UPSC requesting an increase in base rates of $96 million, or 4.8%, which PacifiCorp proposed to be implemented over a three-year period with 2.6% effective January 1, 2021, 1.1% effective January 1, 2022 and 1.1% effective January 1, 2023. The increase reflects recovery of Energy Vision 2020 investments, updated depreciation rates, a wildland fire mitigation cost tracking mechanism to implement Utah House Bill 66, and rate design modernization proposals. The application also requests 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 balance in the Sustainable Transportation and Energy Plan regulatory liability account to buy-down the undepreciated plant balance of certain coal-fueled generation units, including Cholla Unit 4, and the use of a portion of the deferred income tax benefits associated with 2017 Tax Reform to buy-down certain regulatory assets and further depreciate the Dave Johnston plant balance. Hearings are scheduled for November 2020.
Oregon
In December 2018, PacifiCorp filed a 2019 RAC application requesting recovery of costs associated with repowering of approximately 900 MWs of company-owned and installed wind facilities expected to be completed in 2019. The associated net power cost and PTC benefits were previously included in the 2019 TAM. An all-party settlement was approved by the OPUC in September 2019, providing for a total rate increase of $24 million, or 1.8%, subject to final cost updates with rates to be increased as the repowering projects are completed. The first rate increase of $9 million, or 0.7%, was effective October 1, 2019 for four repowered facilities, the second rate increase of $1 million, or 0.1%, was effective December 1, 2019 for one repowered facility and the third rate increase of $5 million, or 0.4%, was effective January 1, 2020 for two repowered facilities. A final rate increase of $5 million, or 0.4%, was effective April 1, 2020 for the two remaining repowered facilities that were placed in service by the end of March 2020. As part of the settlement, parties agreed that the Oregon‑allocated net book value of certain undepreciated equipment replaced as a result of the applicable repowering projects would be depreciated and offset with excess deferred income taxes resulting from 2017 Tax Reform. During the nine-month period ended September 30, 2020, accelerated depreciation of $40 million and offsetting amortization of excess deferred income taxes was recognized associated with the two remaining repowered facilities included in the 2019 RAC. In October 2020, PacifiCorp filed its annual update for plants placed into service in 2019 requesting an overall rate increase of $2 million, or 0.2%, effective November 1, 2020. The rate increase is expected to be in effect until January 1, 2021 when new rates from the general rate case reset the RAC rates to zero.
In November 2019, PacifiCorp filed a 2020 RAC application requesting an annual increase in rates of $1 million, or 0.1%, associated with repowering the Glenrock III wind facility effective April 1, 2020 and an annual increase in rates of $3 million, or 0.3%, associated with repowering the Dunlap wind facility effective October 15, 2020. As part of its application, PacifiCorp proposed to offset the Oregon-allocated net book value of the replaced wind equipment in this filing with PacifiCorp's OATT revenue related deferral from 2017 through 2019. An all-party settlement was filed in January 2020 supporting the filed request and was approved by the OPUC in March 2020. Based on a final cost update for the Glenrock III wind facility, and including the net power cost and PTC benefits, a 0.02% rate decrease became effective April 1, 2020. In September 2020, PacifiCorp filed for a rate change after the repowered Dunlap wind facility was placed in service. Based on the final cost update for the Dunlap wind facility, and including the net power cost and PTC benefits, an additional rate increase of $2 million, or 0.1%, became effective September 18, 2020. As a result of the settlement, accelerated depreciation of $34 million and offsetting amortization of PacifiCorp's OATT deferral was recognized during the nine-month period ended September 30, 2020 associated with undepreciated equipment replaced as a result of the repowering of the Glenrock III and Dunlap wind facilities.
In November 2019, PacifiCorp requested authorization to establish an automatic adjustment clause and rate schedule for the costs and revenues related to the Oregon Corporate Activity Tax ("OCAT") that applies to tax years beginning on or after January 1, 2020. Concurrent with this filing, PacifiCorp also requested authorization to defer the OCAT expense. In January 2020, the OPUC authorized the automatic adjustment clause, rate schedule and application for deferral. PacifiCorp began recovering the estimated OCAT expense effective February 1, 2020. The recovery adjustment for 2020 is 0.41% and the rate is being applied as a percentage surcharge on customers' bills.
In February 2020, PacifiCorp filed a general rate case in Oregon requesting a total rate increase of $71 million, or 5.4%, effective January 1, 2021. The rate case includes a separate tariff rider to recover costs associated with the early retirement of Cholla Unit 4 for an increase of $17 million annually from January 2021 through April 2025 and an annual credit to customers of $25 million for amortization of remaining deferred income tax benefits associated with 2017 Tax Reform over a three-year period beginning January 2021. The request for the increase in base rates reflects recovery of Energy Vision 2020 investments, updated depreciation rates and rate design modernization proposals. In June 2020, PacifiCorp filed reply testimony requesting a revised net rate increase of $67 million, or 5.0%, on January 1, 2021. The reply testimony includes a proposal to offset the costs associated with the early retirement of Cholla Unit 4 with a portion of the deferred income tax benefits associated with 2017 Tax Reform rather than recovering these costs through a separate tariff as proposed in the initial filing. The revised net rate increase also includes PacifiCorp's proposal to provide an annual credit to customers of $6 million for amortization of the remaining deferred income tax benefits associated with 2017 Tax Reform over a two-year period beginning January 2021. In August 2020, PacifiCorp filed its surrebuttal testimony requesting a revised net rate increase of $41 million, or 3.1%, effective January 1, 2021. This includes the proposed annual credit to customers of the remaining deferred income tax benefits associated with 2017 Tax Reform that was modified to $7 million. PacifiCorp also filed a partial stipulation that would settle all rate design and rate spread issues in the general rate case. In PacifiCorp's closing brief filed in October 2020, PacifiCorp modified the requested net rate increase to $40 million, or 3.0%, to accept the OPUC staff adjustment correcting the ongoing advanced meter infrastructure operating costs reflected in the case.
In February 2020, PacifiCorp submitted its annual TAM filing in Oregon requesting a decrease of $49 million, or 3.7%, effective January 1, 2021 based on forecast net power costs and loads for the calendar year 2021. The filing includes the customer benefits of new and repowered wind resources, including an increase in PTCs. In June 2020, PacifiCorp filed reply testimony in its annual TAM with updated forecast net power costs resulting in a rate decrease of $47 million, or 3.6%, effective January 1, 2021. In August 2020, PacifiCorp filed a stipulation with the OPUC settling all issues in the proceeding. The terms of the stipulation result in an overall rate decrease based on the June update of $50 million, or 3.8%, effective January 1, 2021. In October 2020, the OPUC approved the stipulation. The overall rate impact will be finalized when the final update that incorporates the terms of the stipulation is filed in November 2020.
In September 2020, PacifiCorp filed an application for deferred accounting associated with restoring service to customers and repairing, replacing and restoring damaged utility facilities due to wildfires in Oregon.
Wyoming
In July 2019, Wyoming Senate Enrolled Act No. 74 ("SEA 74") went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fueled generation facility in Wyoming before it can receive recovery in rates for capital costs associated with new generation facilities built, in whole or in part, to replace the retiring coal-fueled generation facility. The electric utility is obligated to purchase the electricity from the facility through a power purchase agreement at a price that is no greater than the utility's avoided cost as determined by the WPSC. Costs associated with an approved power purchase agreement are expected to be recoverable in rates from Wyoming customers. In March 2020, the Wyoming governor signed Senate Enrolled Act No. 23, which allows a 1 MW or greater customer to purchase electricity from a coal-fueled generation facility purchased from an electric utility under SEA 74. PacifiCorp is working with the WPSC and other stakeholders on rules to implement the legislation. The overall impacts of this legislation cannot be determined at this time.
In March 2020, PacifiCorp filed a general rate case with the WPSC requesting an increase in base rates of $7 million, or 1.1%, effective January 1, 2021. The increase reflectswhich 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 requestsrequested a revision to the ECAM to eliminate the sharing band and requestsrequested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that proposed an increase tomodified its requested increase in base raterates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC is re-noticingre-noticed PacifiCorp's case and rescheduled the hearings. The hearings forbegan February 2021 and were completed in March 2021. In May 2021, the WPSC approved a $7 million base revenue requirement increase that includes the Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and rate design proposals to be offset by returning the remaining 2017 Tax Reform benefits to customers over the next three years. The WPSC also approved revisions to the ECAM to adjust the sharing band from 70/30 to 80/20 and to include PTCs within the mechanism. PacifiCorp's proposals for extended recovery of the depreciation of certain coal-fueled generation units and use of remaining 2017 Tax Reform benefits to buy down certain plant balances were denied. The WPSC decision results in an overall net decrease of 3.5% with a rate effective date sometime after the hearingof July 1, 2021. A final written order was issued in July 2021.
In March 2020, the Wyoming governor signed House of Representatives Enrolled Act No. 79, which requires the WPSC to adopt a standard to specify a percentage of an electric utility's electricity to be generated from coal‑fueled generation utilizing carbon capture technology by no later than 2030. The bill allows electric utilities to implement a surcharge not to exceed 2% of customer bills to recover costs to comply with the standard. PacifiCorp is working with the WPSC and other stakeholders on rules to implement the legislation. The overall impacts of this legislation cannot be determined at this time.
In April 2020,2021, PacifiCorp filed its annual ECAM and RRARenewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism application with the WPSC requesting recovery of $7to refund $15 million or 1.0% of deferred net power costs fromand RECs to customers for the period January 1, 20192020 through December 31, 2019,2020, reflecting the difference between base and actual net power costs in the 20192020 deferral period. The rate change went into effect onThis reflects a 2.4% decrease compared to current rates. PacifiCorp has requested an interim basisrate effective date of July 1, 2021, which was approved by the WPSC in June 15, 2020. This increase will be offset in part by continued rate credits associated with 2017 Tax Reform benefits and bonus depreciation2021. A hearing has been scheduled for which minor adjustments are proposed to go into effect in the same timeframe. The hearing is set for December 2020.November 2021.
Washington
In November 2019, PacifiCorp submitted its 2019 decoupling filing with the WUTC for the twelve months ended June 30, 2019. In January 2020, the WUTC approved PacifiCorp's 2019 decoupling filing, which resulted in a $12 million surcredit to customers effective February 1, 2020.
In December 2019, PacifiCorp submitted its 2021, Washington general rate case requesting an overall decrease to rates of $4 million, or 1.1%, effective January 1, 2021. The case includes a proposed ten-year annual surcredit of $7 million to customers primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The case also includes a request for approval of a new cost allocation methodology, updated depreciation rates, recovery of Energy Vision 2020 investments, and rate design modernization proposals. In April 2020, PacifiCorp submitted supplemental testimony and exhibits to incorporate the impacts of the recently completed decommissioning studies for PacifiCorp's coal-fueled generating resources and update net power costs. The updates resulted in a revised request for an overall increase to rates of $11 million, or 3.2%. The parties subsequently reached a settlement in principle. In July 2020, the resulting all-party settlement was filed reflecting a rate decrease of $4 million or 1.2%. The settlement adjusts the current $8 million annual surcredit associated with 2017 Tax Reform that was set to expire January 1, 2021 to a five-year annual surcredit of $12 million, primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The settlement also includes approval of the new cost allocation methodology, updated depreciation rates and rate design modernization proposals. While recovery of the Energy Vision 2020 investments is reflected in the settlement, revenue associated with those investments placed into service after May 1, 2020 will be subject to a prudency review in a separate filing in 2021 to address the cost recovery. In October 2020, PacifiCorp filed a petition for rehearing and motionpower cost only rate case to amend the settlement stipulation to reflect an increase to net power costs. In the settlement, parties had agreed to offset any increase toupdate baseline net power costs in the October update with the power cost adjustment mechanism deferral account balance.for 2022. The October update resulted in anproposed $13 million, or 3.7%, rate increase greater than the balance in the deferral account. To maintain the intenthas a requested effective date of the settlement to update net power costs and decrease rates for customers, PacifiCorp and the parties to the settlement reached an agreement to reflect this difference in the deferral account for future ratemaking. In November 2020, PacifiCorp and parties filed joint testimony supporting the amended settlement. The settlement is subject to approval by the WUTC.January 1, 2022.
Idaho
In April 2020,March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $21$14 million or 3.0%, for deferred costs in 2019.2020, a 1.1% decrease compared to current rates. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, RECs, and a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. This deferral is partially offset by $3 million related to amortization of excess deferred income taxes stemming from 2017 Tax Reform and net of recovery for a regulatory asset related to the prior depreciation study. In May 2020,2021, PacifiCorp updated the requested recovery to correct for certain load related data reflected in the initial application, and the IPUC issued an order approving the application as filed withapproved recovery of $10 million for deferred costs, a 2.5% decrease compared to current rates, effective June 1, 2020.2021.
In March 2020, PacifiCorp filed a notice of intent to file a general rate case with the IPUC. However, in June 2020, PacifiCorp negotiated a settlement with parties that allowed PacifiCorp to avoid filing a general rate case in 2020. The parties will support PacifiCorp's proposal to defer the incremental depreciation expense from the 2018 depreciation study duringMay 2021, request deferred accounting treatment for unrecovered investment and closure costs when Cholla Unit 4 is retired, use a portion of the deferred income tax benefits associated with 2017 Tax Reform to buy-down Cholla Unit 4 and offset future rate increases, and include the Pryor Mountain wind facility and the repowering of the Foote Creek I wind facility in the resource tracking mechanism. In return, PacifiCorp will delay filing a general rate case until 2021 with rates effective January 1, 2022. In July 2020, PacifiCorp filed the general rate case settlement stipulation and the related application for an accounting order.
California
In April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1IPUC requesting a $19 million, or 0.9%7.0%, revenue requirement increase effective January 1, 2019. A CPUC decision was issued2022. This is the first general rate case PacifiCorp has filed in FebruaryIdaho since 2011. The rate case includes recovery of Energy Vision 2020 resultinginvestments, Pryor Mountain wind-powered generating facilities, repowering Foote Creek, new investment in a $6 million, or 5.1%,transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate decrease effective February 6, 2020.design modernization proposals. The CPUC's final orderapplication also resulted in an additional rate decreaserequested recovery of $6 million, or 5.1%, over the next three years due todecommissioning and closure costs associated with the amortizationearly retirement of excess deferred income taxes attributed to 2017 Tax Reform.Cholla Unit 4.
California
California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. In January 2020, the CPUC approved the resolution establishing procedural rules for the review and disposition of 2020 Wildfire Mitigation Plans. PacifiCorp submitted its 20202021 California Wildfire Mitigation Plan Update in February 2020 for whichMarch 2021.
FERC Show Cause Order
On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it received approval in June 2020.
should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. In December 2019,July 2021, PacifiCorp filed an application notifyingits answer to the CPUCFERC's show cause order denying the alleged violation of the early retirement of the Cholla Unit 4 generating facility and requesting authorization to establish a memorandum account associated with the retirement and decommissioning of Cholla Unit 4.certain NERC reliability standards. The memorandum account would be used to track costs associated with the unrecovered plant balance, decommissioning and other closure-related costs until PacifiCorp requests recoveryFERC's reply is due in its next general rate case or other proceeding. In July 2020, the CPUC issued a decision approving the requested memorandum account with an effective date of December 27, 2019.
In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and Greenhouse Gas ("GHG") Allowance costs. The application includes a $7 million, or 6.7% decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade Program. If this application is approved, this would result in an overall decrease of $6 million, or 5.9% effective January 1,September 2021.
In September 2020, PacifiCorp notified the CPUC of activation of PacifiCorp's Catastrophic Events Memorandum Account in order to track costs for restoring service to customers and repairing, replacing and restoring damaged utility facilities due to wildfires in Happy Camp, California.
MidAmerican Energy
COVID-19Natural Gas Purchased for Resale
In May 2020,February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB issued an order authorizingordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. While sufficient liquidity is available to MidAmerican Energy, to use a regulatory asset account to record and trackthe increased costs and other financial impacts associated with COVID-19. At such time aslonger recovery period resulted in higher working capital requirements during the six-month period ended June 30, 2021.
Renewable Subscription Program
In December 2020, MidAmerican Energy deems appropriate, it may initiate a proceedingfiled with the IUB a proposed Renewable Subscription Program ("RSP") tariff. As proposed, the program would provide qualified industrial customers with the opportunity to seek recoverymeet their future energy growth above baseline levels with renewable energy from specific MidAmerican Energy wind-powered generation additions and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such costsfacilities. Under the program, MidAmerican Energy would own the facilities, retain PTCs and other financial impacts.tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the project would be specifically assigned to subscribing customers. In June 2021, the IUB rejected the proposed RSP tariff. In a separate docket, the IUB ordered the exclusion from MidAmerican Energy's energy adjustment clause all PTCs and energy benefits associated with projects addressed in the RSP, resulting in MidAmerican Energy cannot predict at this time the amount ofretaining such financial impacts from COVID-19 or when it will seek recovery of such costs with the IUB.benefits.
Iowa Transmission Legislation
In June 2020, Iowa signed into law legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law ensures MidAmerican Energy, as an incumbent electric transmission owner, has the legal right to construct, own and maintain transmission lines that have been approved by the Midcontinent Independent System Operator, Inc. (or another federally registered planning authority) in MidAmerican Energy's service territory. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for construction that it intends to construct, own and maintain the electric transmission line. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner provide the IUB an estimate of the cost to construct the electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the electric transmission line. Legal challenges have been brought against similar laws in other states, but courts that have ruled on such cases have upheld the states' laws. In October 2020, a lawsuit challenging the law was filed in Iowa by national transmission interests. The suit raises issues specific to Iowa law, and the State of Iowa is defending the suit.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Review
In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. In September 2019, Sierra Pacific filed an all-party settlement for the electric regulatory rate review. The settlement resolved all cost of capital and revenue requirement issues and provided for an annual revenue reduction of $5 million and required Sierra Pacific to share 50% of regulatory earnings above 9.7% with its customers. The rate design portion of the regulatory rate review was not part of the settlement and a hearing on rate design was held in November 2019. In December 2019, the PUCN issued an order approving the stipulation but made some adjustments to the methodology for the weather normalization component of historical sales in rates, which resulted in an additional annual revenue reduction of $3 million. The new rates were effective January 1, 2020. In January 2020, Sierra Pacific filed a petition for rehearing challenging the PUCN's adjustments to the weather normalization methodology. In February 2020, the PUCN issued an order granting the petition for rehearing. In April 2020, the PUCN issued a final order approving a weather normalization methodology that changed the additional annual revenue reduction from $3 million to $2 million with an effective date of January 1, 2020. Customers billed under rates utilizing the initial revenue reduction will be issued credits in the fourth quarter of 2020.
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. An order that will delineate the remaining parts of the settlement and conclude on the continuation of the earning sharing mechanism is expected by the end of 2020 and new rates will be effective on January 1, 2021.
In June 2020, Sierra Pacific filed with the PUCN a petition, which was later changed to an application, to adjudicate and establish the cost recovery mechanism for the One Nevada Transmission Line ("ON Line") addressing the reallocated portion of the ON Line revenue requirement. This filing was made concurrent with the Nevada Power regulatory rate review application, which addresses the ON Line reallocated revenue requirement related to Nevada Power. A hearing with the PUCN for the application is scheduled in November 2020.
2017 Tax Reform
In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by the Nevada Utilities. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing the Nevada Utilities to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, the Nevada Utilities filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, the Nevada Utilities filed a petition for judicial review. The judicial review occurred in January 2020 and the district court issued an order in March 2020 denying the petition and affirming the PUCN's order. In May 2020, the Nevada Utilities filed a notice of appeal to the Nevada Supreme Court of the district court's order. The Nevada Utilities have agreed to withdraw the notice of appeal as a part of the Nevada Power electric regulatory rate review settlement. A final order on the settlement is expected by the end of 2020.
Customer Price Stability Tariff
In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST").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 rateBase Tariff Energy Rate and DEAA.Deferred Energy Accounting Adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors. Aintervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST with the PUCN. The enrollment period for the tariff has ended with no customers having enrolled. A final order has not been issued but because no customers have enrolled the order may be dismissed or withdrawn and the tariff will not go into effect. A final order is expected in November 2020.2021.
Natural Disaster Protection Plan
In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires the Nevada Utilities to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 2020, that require the Nevada Utilities to file their natural disaster protection plan for approval on or before March 1 of every third year, with the first filing due on March 1, 2020. The regulations also require annual updates to be filed on or before September 1 of the second and third years of the plan. The plan must include procedures, protocols and other certain information as it relates to the efforts of the Nevada Utilities to prevent or respond to a fire or other natural disaster. The expenditures incurred by the Nevada Utilities in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with the Nevada Utilities filing an application for recovery on or before March 1 of each year. The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration.
COVID-19
Intervenors have filed a petition for judicial review with the District Court in November 2020. In MarchDecember 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an emergency order is expected in 2021. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan. A hearing related to the application for approval of the first amendment to the 2020 natural disaster protection plan was held in June 2021. The Nevada Utilities filed a partial party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial party stipulation and other intervenors filed legal briefs. The partial party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate for cost recovery. A separate docket remains open regarding the regulatory asset account and the cost recovery mechanism. Parties have submitted testimony and a hearing occurred in July 2021.
Senate Bill 448 ("SB 448")
SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage within the state of Nevada and requires the Nevada Utilities to establish regulatory asset accounts relatedsubmit a plan to accelerate transportation electrification in the costs of maintaining service to customers affected by COVID-19 whose services would have been terminated or disconnected under normally-applicable terms of service. Thestate and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities may incur significant costs asto amend its most recently filed resource plan to include a resultplan for certain high-voltage transmission infrastructure construction projects that will be placed into service not later than December 31, 2028 and requires the IRP to include at least one scenario of COVID-19, including, but not limited to, higher credit loss expenses resulting from a higher than average levellow carbon dioxide emissions that uses sources of write-offs of uncollectible accounts associated withsupply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires the suspension of disconnections and late payment fees to assist customers facing unprecedented economic pressures. The Nevada Utilities, on or before September 1, 2021, to file a plan to invest in certain transportation electrification programs during the period beginning January 1, 2022, and ending on December 31, 2024, and establishes requirements for the contents of the transportation electrification investment plan for that period. It also expect to incur additional costs that cannot currently be predicted givenestablishes requirements for the unprecedented naturereview and the acceptance or modification of COVID-19.the transportation electrification investment plan by the PUCN. The PUCN has not yet addressed the regulations in SB 448.
Northern Powergrid Distribution Companies
In JulyDecember 2020, GEMA, through the Ofgem, published its draftfinal determinations for transmission and gas distribution networks in Great Britain. These determinations do not apply directly to Northern Powergrid, as its next price control, ("ED2"), will begin in April 2023 and is subject to a separate process. However, Ofgem's determinations for other Great Britain energy networks are likely to be indicative for ED2. Regarding the allowed return on capital, Ofgem's draft determinations include an expectedOfgem determined a cost of equity of 3.95%4.55% (plus up to 0.25% if a sector does not outperform on incentive schemes and inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs)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, with an outcome expected in October 2021. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023.
In December 2020, GEMA published its decision on the methodology it will use to set the next electricity distribution price control, ED2, and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution, and that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a 40%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 regulatory assumption. Thisand the measure of inflation used, the working assumption for ED2 is approximately 250150 basis points lower than the comparablecurrent cost of equity for Northern Powergrid's current regulatory settlement, after accounting for differences in the inflation index and equity ratio.equity.
In September 2020, the CompetitionJuly 2021, Northern Powergrid submitted and Markets Authority ("CMA") published its provisional findingsdraft business plan for price control redeterminations for four water companies that rejected their settlement. The CMA proposesApril 2023 to overturn the water regulator's proposal for a 4.2% costMarch 2028. If adopted, this plan would involve annual capital and operating expenditures of equity, replacing it with 5.08%. The CMA is the appeal body for energy network price control appeals, although energy networks do not have access£642 million, an increase relative to the same price control redetermination process.
In respect of Northern Powergrid's current price control ("ED1"), GEMA published a decision in October 2019 to make allowance for certain additional costs totaling £12£471 million plus RPI inflation from 2012-13, that it judged to be beyond the control of the licensees, beyond the routine adjustments for such costs that occur annually. The adjustments, which reflect additional costs for the licensees, will flow into allowed revenues through the standard price control mechanismsaverage annual capital and do not affect Northern Powergrid's overall financial position compared to whenoperating expenditures expected over the current price control was set.period (April 2015 to March 2023). A final business plan submission for 2023-2028 will be submitted in December 2021, ahead of GEMA's draft and final determinations which are expected around June and December 2022, respectively. A new price control can be implemented by GEMA without the consent of the licensee but, if a licensee disagrees with the decision, it can appeal the matter to the United Kingdom’s Competition and Markets Authority. In general terms, an appeal may also be sought by another licensee whose interests are materially affected by the decision, a trade association that represents a licensee and Citizens Advice, as the representative of consumers whose interests are materially affected by the decision.
BHE Pipeline Group
Northern Natural GasBHE GT&S
In July 2018, the FERC issued a final rule adopting procedures for determining whether natural gas pipelines were collecting unjust and unreasonable rates in light of the reduction in the federal corporate tax rate from 2017 Tax Reform. PursuantJanuary 2020, pursuant to the final rule, in October 2018, Northern Natural Gas filed an informational filing on FERC Form No. 501-G andterms of a Statement Demonstrating Why No Rate Adjustment is Necessary. In January 2019, the FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gasprevious settlement, Cove Point filed a cost and revenue study in April 2019. In July 2019, Northern Natural Gas filed a Section 4general rate case requesting increases infor its transportation and storage rates.FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In JanuaryFebruary 2020, the FERC approved Northern Natural Gas' filing to implement its interimsuspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund, effective January 1, 2020.
refund. In JuneNovember 2020, a settlementCove Point reached an agreement was filedin principle with the FERC, resolvingactive participants in the Section 5 investigation and Section 4general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and providing for increased service rates anda decrease in annual depreciation rates. Market Area transportation reservation rates increased 28.5% and storage reservation rates increased 67.0% fromexpense of $1 million, compared to the rates that were in effect in 2019. Depreciation rates are 2.3% for onshore transmission plant, 2.95% for LNG storage plant, 13.0% for intangible plant, and 2.75% for general plant.prior to August 1, 2020. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2022, subject to certain exceptions, as well as provides for minimum annual maintenance capital spending. Theinterim settlement rates were implemented MayNovember 1, 2020, and the Company'sCove Point's provision for rate refunds for JanuaryAugust 2020 through AprilOctober 2020 totaled $69$7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the settlement in September 2020,stipulation and agreement and the rate refunds to customers were processed in early October 2020.late April.
BHE Transmission
AltaLink
Tariff Refund Application
In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation.
In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 customer tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 were proposed in AltaLink's 2022-2023 GTA.
In April 2021, the AUC confirmed its approval of AltaLink's customer tariff refund as provided in the decision issued in March 2021 and detailed its reasons for the decision. Specifically, the AUC found that the exceptional circumstances faced by Alberta customers in 2021 have brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances include the current economic downturn due to COVID-19, the collapse in the world price of oil and the resulting significant negative impact to Albertans and businesses. As a result, immediate and temporary relief was warranted.
2019-2021 General Tariff Application
In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposesproposed to provide a further tariff reduction over the three yearsyear period by refunding previously collected accumulated depreciation surplus of an additional C$31 million.
In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral AccountAccounts Reconciliation Application. The application requestsrequested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.
In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions totalingthat resulted in a net decrease of C$38 million net decrease to the three-yearthree year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019. In November 2019, the hearing to examine the excluded matters was completed andwith written arguments were filed in January 2020.
In October 2019, AltaLink filed a letter with the AUC to request the continuation of the monthly interim refundable transmission tariff effective January 1, 2020, until a final tariff is approved. In October 2019, the AUC confirmed the interim refundable transmission tariff at C$74 million per month, until otherwise directed by the AUC.
In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. Reverting the salvage method back to the traditional pre-collection approach increases the amount of salvage collected by approximately C$82 million, resulting in an increase to AltaLink's cash transmission tariffs collected from customers for the 2019-2021 period by approximately C$77 million. The AUC approved, on a placeholder basis, C$13 million of AltaLink's requestedthe additional C$20 million ofAltaLink requested for forecast transmission line clearance capital on placeholder basis and reviewed thecapital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital investmentexpenditures related to fire risk mitigation were approved, to reduce the risk of fires, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.
In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership. The AUC also approved a revised monthly tariff of C$71 million for September 2020 to December 2020 and monthly tariff of C$74 million for 2021. The 2021 revenue requirement is based on 8.5% return on equity and 37% deemed equity set by the AUC as placeholders.
The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there arewere changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. A decision from the AUC is expected in January 2021.
2021 Generic Cost of Capital Proceeding
In December 2018, the AUC initiated the 2021 GCOC proceeding to consider returning to a formula-based approach in determining the return on equity for a given year, starting with 2021. In April 2019, after receiving comments from interested parties, the AUC expanded the scope of the proceeding to include a traditional non-formulaic GCOC inquiry as well as the consideration of returning to a formula-based approach.
In January 2020, AltaLink filed company and expert evidence, recommending a range of 8.75% to 10.5% return on equity, on a recommended equity ratio of 40% for 2021 and 2022. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the City of Calgary filed intervenor evidence recommending a range of 5.0% to 6.9% return on equity, and an AltaLink common equity ratio of 35% to 37% for 2021 and 2022.
In March 2020, as a result of COVID-19, the AUC suspended the proceeding for an indefinite period. This decision will be subject to review and reassessment by the AUC every 30 to 60 days. In May 2020, the AUC proposed a method to determine fair cost of capital parameters for 2021 given the circumstances presented by the COVID-19 pandemic. The AUC outlined four options for utilities and interested parties to consider and subsequently added a fifth option that sets the 2021 return on equity at 8.3% as a balance between certainty and economic conditions.
In July 2020, AltaLink requested that the AUC continue to hold the proceeding in abeyance and revisit the issue in another 30 to 60 days. AltaLink also requested that if the AUC determines the proceeding should resume, the AUC should set a date for the filing of evidence by all parties in the first quarter of 2021 and that the proceeding should address return on equity for 2021 and 2022 only.
In August 2020, the AUC issued a letter indicating that it had decided not to resume the GCOC proceeding at that time and would continue to assess when, and under what conditions, the proceeding could resume.
In OctoberNovember 2020, the AUC issued its decision on AltaLink's review and setvariance application. The AUC decided to vary the finaloriginal decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year over year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.
2022 Generic Cost of Capital Proceeding
In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding considered the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the commission requested participants to submit comments that addressed the following: (i) the continuation of the currently approved return on equity and deemed equity ratioratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.
In January 2021, AltaLink bysubmitted 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 currentcurrently approved 8.5%2021 return on equity and 37%, respectively,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 durationbeginning of 2021.2022 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.
2014-2015 Deferral Account Reconciliation Application
In December 2018 and January 2019,March 2021, the AUC issued decisions approving C$3,833 million outits decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta customers.
In April 2021, the Utilities Consumer Advocate filed an application with the Court of Appeal of Alberta requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleged that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness. The Utilities Consumer Advocate additionally filed an application with the AUC for review and variance of the C$4,017 million capital project additions, included in the application. Project costs of C$155 million were deferred to a future hearing.AUC's decision. The AUC disallowed capital additions of approximately C$29 million including applicable AFUDC, pending receipt of additional supporting documentation for certain items.
AltaLink filed compliance filings in February and September 2019 reflecting the AUC's directives and AUC approval was received in November 2019. However, the AUC had previously ruled that it will put in placeholder amountsbasis for the approved costs ofapplication was the assets insame as the 2014-2015 Deferral Account Reconciliation Application proceeding until the AUC-initiated proceedingpermission to consider the issue of transmission asset utilization.
2016-2018 Deferral Account Reconciliation Application
In July 2019, AltaLinkappeal filed its 2016-2018 Deferral Account Reconciliation Application with the AUC. The application includes 116 projects with total gross capital additions, including AFUDC,Court of C$976 million. In December 2019, the AUC announced a series of technical meetings to address AltaLink's responses to certain information requests.Appeal.
In March 2020, the AUC issued a letter indicating that it would provide further process steps after AltaLink submitted its remaining responses to information requests and the Consumers' Coalition of Alberta files its intervener evidence. In May 2020, AltaLink provided additional responses to information requests as directed by the AUC. In accordance with the AUC's revised process schedule, the Consumers' Coalition of Alberta filed its intervener evidence in June 2020, and AltaLink subsequently filed information requests on the intervener evidence in June 2020 and filed its rebuttal evidence in July 2020.
In August 2020, the AUC determined that a hearing is not required and issued a proceeding schedule to provide for argument, reply argument and the close of record by September 2020. In September 2020, AltaLink and interveners filed written argument and reply argument, and a decision from the AUC is expected by the end of 2020.
2019 Deferral AccountAccounts Reconciliation Application
In October 2020, AltaLink filed its application with the AUC, which includes ten10 projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.
Alberta Electric System Operator Tariff Decision
In September 2019,March 2021, the AUC issued its decision with respect to the 2018 AESO tariff. As part of this decision, theon AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved AltaLink's proposal to refund contributions made by distribution facility owners relative to transmission projects built and owned by transmission facility owners. The proposal will benefit distribution customers by flowing throughC$128 million of the lower costC$128.5 million of gross capital project additions, disallowing C$0.5 million of capital of the transmission facility owner rather than the higher cost of capital of the distribution facility owner. As directed by the AUC, AltaLink would pay FortisAlberta the unamortized contribution balance of approximately C$375 million as of December 2017, and add the amount to AltaLink's rate base if the decision is upheld.costs. The AUC directedalso approved the AESO to consult with AltaLink to provide a joint proposal to implement AltaLink's contribution proposal effective in January 2018. In September 2019, FortisAlberta filed a reviewother deferral accounts for taxes other than income taxes, long-term debt and variance application with the AUC requesting the AUC re-evaluate its findings with respect to AltaLink's customer contribution proposal relative to distribution facility owners. In October 2019, the AUC granted FortisAlberta's request to proceed to a review and variance with the record closed in November 2019, after submissions from FortisAlberta, AltaLink, and other interested parties. FortisAlberta also filed for permission to appeal the decision with the Court of Appeal, which will not be heard until after the AUC's review proceeding.
In December 2019, the AUC reopened the record of the review and variance proceeding and, in January 2020, issued specific information requests to each of FortisAlberta and AltaLink to clarify the evidence previouslyannual structure payments as filed. AltaLink and FortisAlberta filed responses to the AUC information requests in January 2020. In February 2020, FortisAlberta filed a motion with the AUC requesting the appointment of a review panel to convene an oral hearing.
In March 2020, as a result of COVID-19, the AUC advised that it would be immediately deferring all public hearings, consultations or information sessions until further notice and requested FortisAlberta to advise the AUC whether it wishes to amend its motion. In April 2020, FortisAlberta filed its response requesting an oral hearing, to commencecompliance filing in 105 days.
April 2021. In May 2020, the AUC denied FortisAlberta's request for an oral hearing, but requested expert tax evidence on three areas of disagreement between AltaLink and FortisAlberta. AltaLink and FortisAlberta filed expert evidence in July 2020. The AUC set a further process of information requests and responses and written submissions, which were scheduled to be completed in September 2020.
In September 2020, AltaLink and FortisAlberta filed a written argument and a reply argument. In November 2020,2021, the AUC issued its decision with respect to FortisAlberta's review and variance proceeding. In its decision,approving the AUC rescinded its original September 2019 decision that directed (i) FortisAlberta to transfer the unamortized contribution balance of approximately C$375 million to AltaLink and (ii) the new contribution policy proposed by AltaLink be applied. The AUC's decision was based on two main areas: (i) if the original decision was confirmed, FortisAlberta would incur incremental income tax, carrying costs and debt restructuring costs of at least C$117 million that would be required to be recovered from ratepayers and (ii) the AUC determined that a majority of the approximately C$40 million in savings to ratepayers, which the hearing panel relied oncompliance filing application as the basis for their original decision, can be achieved by directing FortisAlberta to adjust the applicable amortization rate for its AESO contributions to match the service lives of the transmission assets. The AUC will initiate a separate proceeding to (i) examine the legal basis of the current AESO customer contribution policy as it pertains to all transmission facility owners and distribution facility owners, (ii) consider whether there is a need for a new policy, including consideration of AltaLink's proposed policy and (iii) if approved, set the date on which any new policy would commence.filed.
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, 2019,2020, and new environmental matters occurring in 2020.2021.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goals of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius and reaching a global peak of greenhouse gas emissions as soon as possible to achieve climate neutrality by mid-century; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:
•On July 27, 2021, the governor of Oregon signed House Bill 2021, which requires utilities to reduce GHG emissions to meet certain clean energy targets. The bill sets a baseline of the average of 2010, 2011, and 2012 emissions and requires utilities to meet the following reductions from that baseline: 80% by 2030, 90% by 2035 and 100% by 2040. No earlier than January 1, 2022, PacifiCorp must file a clean energy plan with the OPUC showing how it will meet the clean energy targets.
•On May 17, 2021, the state of Washington passed the Climate Commitment Act (Senate Bill 5126), which creates an economy-wide cap-and-trade program to reduce GHG emissions. Under the Climate Commitment Act, the Washington Department of Ecology must establish progressively declining annual allowance budgets for emissions of GHG beginning January 1, 2023. PacifiCorp is subject to the Climate Commitment Act as an importer of electricity into Washington.
Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and the EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations are described below.
GHG Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.
New Source Performance Standards for Methane Emissions
In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. On June 30, 2021, President Biden signed into law a resolution that rescinded the August 2020 rule and reinstated a rule promulgated in 2016. The primary effect of the resolution is that the 2020 rule was immediately challenged by environmental and tribal groups,is treated as well as numerous states.never having taken effect. The EPA is developing guidance for stakeholders to comply with the 2016 rule. In September 2020, the D.C. Circuit issued an administrative stay blocking the rule from taking effect while the court considers whetheraddition, reinstating methane rules for new sources imposes a long-term suspension is warranted.requirement for EPA to also issue rules for existing sources. Until such time as additional regulatory action is taken and litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Most air quality standards require measurement over a defined period of time to determine the average concentration of the pollutant present. 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 December 2012,June 2010, the EPA finalized more stringent fine particulate mattera new NAAQS reducingfor SO2. Under the annual2010 rule, areas must meet a one-hour standard from 15 microgramsof 75 parts per cubic meterbillion utilizing a three-year average. The rule utilizes source modeling in addition to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. Theinstallation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not setissue its final designations until July 2013 and determined, at that date, that a separate secondary visibility standard, choosingportion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to relyconclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014,Louisa coal-fueled generating facility. Although the EPA issued finalEPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant. In June 2020, the EPA proposed a determination of attainment for the 2006 24-hour fine particulate matter for Salt Lake City and Provo serious nonattainment areas. The determination is based upon quality-assured, quality controlled and certified ambient air monitoring data showing that the area has attained the 2006 standard based on the 2017-2019 monitoring. The comment period for the proposal ended in August 2020.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective in April 2012, and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to complycontinue with the new standards by April 2015 withdeployment of additional SO2 monitoring networks across the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA, without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.
In December 2018,country. On February 25, 2019, the EPA issued a proposed revised supplemental cost findingdecision to retain the 2010 SO2 NAAQS without revision.
The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the MATS,Northern District of California ("Northern District of California") accepted as wellan enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.
The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required risk and technology review underadditional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act Section 112.interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The EPA proposed to determineD.C. Circuit ruled September 13, 2019, that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not propose to remove coal-fully address interstate ozone transport, and oil-fueled power plants fromremanded the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding. Until litigation over the rule is exhausted, the relevant Registrants cannot fully determine the impacts of the changesCSAPR Update Rule back to the MATS rule.
In March 2020, theEPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power plants in Chesapeake Climate Action Network v. EPA regarding consolidated challenges12 states in the CSAPR trading program in response to the EPA's startup and shutdown provisions contained inD.C. Circuit's decision to vacate the 2012 MATSCSAPR Update rule. The MATS rule's provisions governing startuprule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and shutdown require electric generating units comply with work practice standards as opposedTexas, will not significantly contribute to numerical limits during these periods.downwind states' ability to attain or maintain the ozone standard. The EPA denied petitions for reconsideration of these provisions in 2016 and environmentalists challenged this denial. The D.C. Circuit vacatedaccepted comment on the reconsideration denials, remanding the petition toproposal through December 15, 2020. On March 15, 2021, the EPA for further action. The court didfinalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not makeanticipated as a determination on the meritsresult of the arguments concerning the EPA's legal authority to set work practice standards. The existing work practice standards and the alternate definition for when startup ends continue to be applicable. Until the EPA finalizes action to respond to the court's order, the relevant Registrants cannot fully determine the impacts of the remand.rule.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to best available retrofit technology ("BART")BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective in August 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. In January 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. In June 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval by the end of 2019.
In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements for the Hunter and Huntington plants to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative will take effect 30 days after publication in the Federal Register.
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit Court of Appeals ("Tenth Circuit") in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final inon March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. A stay remains in placeThe EPA, U.S. Department of Justice, state of Wyoming and the case has not yet been set for oral argument with settlement negotiations ongoing. In September 2020, specific parties reachedPacifiCorp executed a settlement agreement in principle, which would resolve the appeal, and are working to finalize a written agreement in the fourth quarter of 2020. In MayDecember 16, 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the four Jim Bridger units. Also in May 2020, the Wyoming Department of Environmental Quality submitted a regional haze SIP revision to the EPA. The revised SIP grants approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu ofremoving the requirement to install SCR systemsin lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Jim BridgerHunter Units 1 and 2, and Huntington Units 1 and 2. PacifiCorp anticipatesIn December 2012, the EPA will initiate a public comment process duringapproved the fourth quarter of 2020 as partSO2 portion of the federal reviewUtah regional haze SIP and approval process.
Waterdisapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the frameworkcompleted an alternative BART analysis for maintainingHunter Units 1 and improving water quality in the United States through a program that regulates, among other things, discharges to2, and withdrawals from waterways.Huntington Units 1 and 2. In April 2014,January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the United States Army Corpsinstallation of Engineers ("Corps of Engineers")SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a joint proposal to address "watersFIP requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementationeffective date of the rule was issued in October 2015. In January 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process,PacifiCorp and other parties filed requests with the first stepEPA to repealreconsider and stay that decision, as well as filed motions for stay and petitions for review with the 2015 rule andTenth Circuit asking the second stepcourt to carry out a notice-and- comment rulemaking in which a substantive re-evaluation ofoverturn the definition of the "waters of the United States" will be undertaken.EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the Corps of Engineers issuedEPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized in September 2019. In January 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extensionstay of the compliance deadline. In December 2018,obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the CorpsUtah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of Engineers proposed a revised definitionPacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of "watersAir Quality submitted the SIP revision to the EPA for approval at the end of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by- case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States.2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the Corps of Engineers signedexisting NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule narrowingapproving the federal government's permitting authority underUtah Regional Haze SIP Alternative on October 28, 2020. With the Clean Water Act.approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The new Navigable Waters Protection Rule, whichUtah Regional Haze SIP Alternative took effect in June 2020, redefines what waters qualify as navigable waters of the United States and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act will be considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. The EPA and the Corps of Engineers originally proposed six categories, but in the final version they collapsed ditches and impoundments into other categories. There are also 12 categories of waters that the agencies highlighted as being excluded from coverage, including groundwater, ephemeral streams and pools, prior converted cropland and waste treatment systems.
In April 2020, the United States Supreme Court establishedDecember 28, 2020. As a new test for Clean Water Act jurisdiction in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding that the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor test to determine whether discharges conveyed through groundwater to surface water are "functionally equivalent" to direct discharges, finding that the time it takes for pollutants to travel through groundwater and the distance traveled are the two most important factors in the test. The United States Supreme Court remanded County of Maui, Hawaii to the Ninth Circuit Court of Appeals for further adjudication, which subsequently remanded the case to the district court to determine whether additional discovery is needed before applying the new seven-factor test. Until the functional equivalent test is applied by the courts, the Registrants cannot determine the impact of this case on their operations.
Coal Combustion Byproduct Disposal
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the Resource Conservation and Recovery Act. The final rule was released by the EPA in December 2014, was published in the Federal Register in April 2015 and was effective in October 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under the Resource Conservation and Recovery Act Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The firstresult of these reports was posted toactions, the respective Registrant's coal combustion rule compliance data and information websites in March 2018. BasedTenth Circuit dismissed the Utah regional haze petitions on the results in those reports, additional action may be required under the rule.
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton generating facility. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed in or before December 2017 and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated ten evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit in November 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. In August 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for the EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to the EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held the EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, in March 2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the agency in June 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of CCR units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The first phase of the CCR rule amendments was finalized by the EPA in July 2018 and made effective in August 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, the EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 2020. Following the March 2019 submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, the D.C. Circuit granted the EPA's request to remand the rule and left the October 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. In August 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and the EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 proposal modifies the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering the need to conduct an environmental demonstration; establishes a definition of "CCR storage pile" to address the temporary storage of CCR on the ground, depending on whether the material is destined for disposal or beneficial use; makes certain changes to the rule's annual groundwater monitoring and corrective action reports to make it easier for the public to see and understand the data contained within the reports; modifies the requirements related to facilities' publicly available CCR rule websites to make the information more readily available; and establishes a risk-based groundwater monitoring protection standard for boron in the event the EPA decides to add boron to Appendix IV in the CCR rule. The EPA accepted comments on the Phase 2 proposal through October 2019.
In September 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule") in response to the D.C. Circuit's revocation of certain provisions of the CCR rule and to clarify certain other provisions of the rule. The Part A rule reclassifies compacted-soil lined surface impoundments from "lined" to "unlined," establishes a deadline of April 11, 2021, by which all unlined surface impoundments must initiate closure, and revises the alternative closure provisions to grant facilities additional time to initiate closure in order to manage CCR and non-CCR wastestreams either due to a lack of alternative capacity or with a commitment to closure the coal-fueled operating unit and complete closure of unlined impoundments by a date certain. The Part A rule also revises certain requirements regarding annual groundwater monitoring and corrective action reports and publicly accessible CCR internet sites. MidAmerican Energy and NV Energy have already initiated closure or will initiate closure of all surface impoundments by AprilJanuary 11, 2021. On October 16, 2020, the EPA released the pre-publication versionJanuary 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the final Holistic Approach to Closure: Part B rule ("Part B rule"). The Part B rule finalizes a two-step process, as set forthUtah Regional Haze SIP Alternative in the March 2020 proposal, allowing facilitiesTenth Circuit. PacifiCorp and the state of Utah moved to request approval to continue operating an existing unlined CCR surface impoundment with an alternate liner system. The other provisions that were containedintervene in the Part B proposal, including (1) options to use CCR during closurelitigation, which has been stayed pending the Biden administration's review of a CCR unit, (2) an additional closure-by-removal option and (3) new requirements for annual closure progress reports, were not finalized with the Part B rule. These options will be addressed by the EPA in a subsequent rulemaking action. In addition to the Part A and Part B rules, the EPA has proposed the Phase II rule, the federal CCR permit program rule, and the advanced notice of proposed rulemaking for legacy impoundments. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
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, 2019.2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2019.2020.
PacifiCorp and its subsidiaries
Consolidated Financial Section
PART I
| |
Item 1. | Financial Statements |
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PacifiCorp
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of SeptemberJune 30, 2020,2021, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019,2020, and of cash flowsfor the nine-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019,2020, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2019,2020, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 21, 2020,26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2019,2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Portland, Oregon
NovemberAugust 6, 20202021
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | |
| | | As of |
| | | June 30, | | December 31, |
| | 2021 | | 2020 |
| ASSETS |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 44 | | | $ | 13 | |
| Trade receivables, net | | 714 | | | 703 | |
| Other receivables, net | | 62 | | | 48 | |
| Inventories | | 474 | | | 482 | |
| Derivative contracts | | 99 | | | 27 | |
| | | | |
| Regulatory assets | | 86 | | | 116 | |
| Prepaid expenses | | 66 | | | 79 | |
| Other current assets | | 18 | | | 55 | |
| Total current assets | | 1,563 | | | 1,523 | |
| | | | | |
| Property, plant and equipment, net | | 22,675 | | | 22,430 | |
| Regulatory assets | | 1,339 | | | 1,279 | |
| Other assets | | 506 | | | 470 | |
| | | | | |
| Total assets | | $ | 26,083 | | | $ | 25,702 | |
|
| | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| | | 2020 | | 2019 |
| ASSETS |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 590 |
| | $ | 30 |
|
| Trade receivables, net | | 730 |
| | 644 |
|
| Other receivables, net | | 38 |
| | 70 |
|
| Inventories | | 491 |
| | 394 |
|
| Other current assets | | 233 |
| | 152 |
|
| Total current assets | | 2,082 |
| | 1,290 |
|
| | | | | |
| Property, plant and equipment, net | | 22,042 |
| | 20,973 |
|
| Regulatory assets | | 952 |
| | 1,060 |
|
| Other assets | | 451 |
| | 374 |
|
| | | | | |
| Total assets | | $ | 25,527 |
| | $ | 23,697 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | | | | | | | | | | |
| | | As of |
| | | June 30, | | December 31, |
| | 2021 | | 2020 |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| Current liabilities: | | | | |
| Accounts payable | | $ | 667 | | | $ | 772 | |
| Accrued interest | | 125 | | | 127 | |
| Accrued property, income and other taxes | | 136 | | | 80 | |
| | | | |
| Accrued employee expenses | | 106 | | | 84 | |
| Short-term debt | | 301 | | | 93 | |
| Current portion of long-term debt | | 479 | | | 420 | |
| Regulatory liabilities | | 124 | | | 115 | |
| Other current liabilities | | 221 | | | 174 | |
| Total current liabilities | | 2,159 | | | 1,865 | |
| | | | | |
| Long-term debt | | 7,735 | | | 8,192 | |
| Regulatory liabilities | | 2,753 | | | 2,727 | |
| Deferred income taxes | | 2,715 | | | 2,627 | |
| Other long-term liabilities | | 1,154 | | | 1,118 | |
| Total liabilities | | 16,516 | | | 16,529 | |
| | | | | |
| Commitments and contingencies (Note 9) | | 0 | | 0 |
| | | | | |
| Shareholders' equity: | | | | |
| Preferred stock | | 2 | | | 2 | |
| Common stock - 750 shares authorized, 0 par value, 357 shares issued and outstanding | | 0 | | | 0 | |
| Additional paid-in capital | | 4,479 | | | 4,479 | |
| Retained earnings | | 5,105 | | | 4,711 | |
| Accumulated other comprehensive loss, net | | (19) | | | (19) | |
| Total shareholders' equity | | 9,567 | | | 9,173 | |
| | | | | |
| Total liabilities and shareholders' equity | | $ | 26,083 | | | $ | 25,702 | |
|
| | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| | | 2020 | | 2019 |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| Current liabilities: | | | | |
| Accounts payable | | $ | 764 |
| | $ | 679 |
|
| Accrued interest | | 114 |
| | 116 |
|
| Accrued property, income and other taxes | | 180 |
| | 96 |
|
| Accrued employee expenses | | 124 |
| | 75 |
|
| Short-term debt | | — |
| | 130 |
|
| Current portion of long-term debt | | 438 |
| | 38 |
|
| Other current liabilities | | 235 |
| | 226 |
|
| Total current liabilities | | 1,855 |
| | 1,360 |
|
| | | | | |
| Long-term debt | | 8,211 |
| | 7,620 |
|
| Regulatory liabilities | | 2,847 |
| | 2,913 |
|
| Deferred income taxes | | 2,583 |
| | 2,563 |
|
| Other long-term liabilities | | 965 |
| | 804 |
|
| Total liabilities | | 16,461 |
| | 15,260 |
|
| | | | | |
| Commitments and contingencies (Note 9) | |
|
| |
|
|
| | | | | |
| Shareholders' equity: | | | | |
| Preferred stock | | 2 |
| | 2 |
|
| Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | | — |
| | — |
|
| Additional paid-in capital | | 4,479 |
| | 4,479 |
|
| Retained earnings | | 4,600 |
| | 3,972 |
|
| Accumulated other comprehensive loss, net | | (15 | ) | | (16 | ) |
| Total shareholders' equity | | 9,066 |
| | 8,437 |
|
| | | | | |
| Total liabilities and shareholders' equity | | $ | 25,527 |
| | $ | 23,697 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three-Month Periods | | Six-Month Periods |
| | Ended June 30, | | Ended June 30, |
| | 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | | |
| Operating revenue | $ | 1,298 | | | $ | 1,144 | | | $ | 2,540 | | | $ | 2,350 | |
| | | | | | | | |
| Operating expenses: | | | | | | | |
| Cost of fuel and energy | 441 | | | 383 | | | 865 | | | 800 | |
| Operations and maintenance | 255 | | | 243 | | | 514 | | | 497 | |
| Depreciation and amortization | 275 | | | 210 | | | 539 | | | 462 | |
| Property and other taxes | 43 | | | 52 | | | 104 | | | 101 | |
| Total operating expenses | 1,014 | | | 888 | | | 2,022 | | | 1,860 | |
| | | | | | | | |
| Operating income | 284 | | | 256 | | | 518 | | | 490 | |
| | | | | | | | |
| Other income (expense): | | | | | | | |
| Interest expense | (105) | | | (110) | | | (212) | | | (212) | |
| Allowance for borrowed funds | 6 | | | 12 | | | 12 | | | 22 | |
| Allowance for equity funds | 12 | | | 23 | | | 25 | | | 44 | |
| Interest and dividend income | 5 | | | 3 | | | 11 | | | 6 | |
| Other, net | 4 | | | 8 | | | 10 | | | 4 | |
| Total other income (expense) | (78) | | | (64) | | | (154) | | | (136) | |
| | | | | | | | |
| Income before income tax (benefit) expense | 206 | | | 192 | | | 364 | | | 354 | |
| Income tax (benefit) expense | (19) | | | 26 | | | (30) | | | 12 | |
| Net income | $ | 225 | | | $ | 166 | | | $ | 394 | | | $ | 342 | |
|
| | | | | | | | | | | | | | | |
| | Three-Month Periods | | Nine-Month Periods |
| | Ended September 30, | | Ended September 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | | |
| Operating revenue | $ | 1,479 |
| | $ | 1,367 |
| | $ | 3,829 |
| | $ | 3,793 |
|
| | |
| | | | | | |
|
| Operating expenses: | | | | | | | |
| Cost of fuel and energy | 499 |
| | 464 |
| | 1,299 |
| | 1,313 |
|
| Operations and maintenance | 332 |
| | 252 |
| | 829 |
| | 763 |
|
| Depreciation and amortization | 234 |
| | 272 |
| | 696 |
| | 686 |
|
| Property and other taxes | 53 |
| | 46 |
| | 154 |
| | 146 |
|
| Total operating expenses | 1,118 |
| | 1,034 |
| | 2,978 |
| | 2,908 |
|
| | |
| | | | | | |
|
| Operating income | 361 |
| | 333 |
| | 851 |
| | 885 |
|
| | |
| | | | | | |
|
| Other income (expense): | |
| | | | | | |
|
| Interest expense | (107 | ) | | (101 | ) | | (319 | ) | | (299 | ) |
| Allowance for borrowed funds | 14 |
| | 11 |
| | 36 |
| | 26 |
|
| Allowance for equity funds | 29 |
| | 21 |
| | 73 |
| | 51 |
|
| Interest and dividend income | 2 |
| | 5 |
| | 8 |
| | 17 |
|
| Other, net | 5 |
| | 6 |
| | 9 |
| | 22 |
|
| Total other income (expense) | (57 | ) | | (58 | ) | | (193 | ) | | (183 | ) |
| | |
| | | | | | |
|
| Income before income tax expense (benefit) | 304 |
| | 275 |
| | 658 |
| | 702 |
|
| Income tax expense (benefit) | 18 |
| | (3 | ) | | 30 |
| | 77 |
|
| Net income | $ | 286 |
| | $ | 278 |
| | $ | 628 |
| | $ | 625 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Accumulated | | |
| | | | | | | Additional | | | | Other | | Total |
| | Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| | | Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | | |
| Balance, March 31, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,148 | | | $ | (15) | | | $ | 8,614 | |
| Net income | | — | | | — | | | — | | | 166 | | | — | | | 166 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Balance, June 30, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,314 | | | $ | (15) | | | $ | 8,780 | |
| | | | | | | | | | | | |
| Balance, December 31, 2019 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 3,972 | | | $ | (16) | | | $ | 8,437 | |
| Net income | | — | | | — | | | — | | | 342 | | | — | | | 342 | |
| Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | | |
| Balance, June 30, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,314 | | | $ | (15) | | | $ | 8,780 | |
| | | | | | | | | | | | | |
| Balance, March 31, 2021 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,880 | | | $ | (19) | | | $ | 9,342 | |
| Net income | | — | | | — | | | — | | | 225 | | | — | | | 225 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Balance, June 30, 2021 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | |
| | | | | | | | | | | | |
| Balance, December 31, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | |
| Net income | | — | | | — | | | — | | | 394 | | | — | | | 394 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Balance, June 30, 2021 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Accumulated | | |
| | | | | | | Additional | | | | Other | | Total |
| | | Preferred | | Common | | Paid-in | | Retained | | Comprehensive | | Shareholders' |
| | | Stock | | Stock | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | | |
| Balance, June 30, 2019 |
| $ | 2 |
|
| $ | — |
|
| $ | 4,479 |
|
| $ | 3,548 |
|
| $ | (12 | ) |
| $ | 8,017 |
|
| Net income | | — |
| | — |
| | — |
| | 278 |
| | — |
| | 278 |
|
| Balance, September 30, 2019 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,826 |
| | $ | (12 | ) | | $ | 8,295 |
|
| | | | | | | | | | | | | |
| Balance, December 31, 2018 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,377 |
| | $ | (13 | ) | | $ | 7,845 |
|
| Net income | | — |
| | — |
| | — |
| | 625 |
| | — |
| | 625 |
|
| Other comprehensive (loss) income | | — |
| | — |
| | — |
| | (1 | ) | | 1 |
| | — |
|
| Common stock dividends declared | | — |
| | — |
| | — |
| | (175 | ) | | — |
| | (175 | ) |
| Balance, September 30, 2019 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,826 |
| | $ | (12 | ) | | $ | 8,295 |
|
| | | |
| | |
| | |
| | |
| | |
| | |
|
| Balance, June 30, 2020 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 4,314 |
| | $ | (15 | ) | | $ | 8,780 |
|
| Net income | | — |
| | — |
| | — |
| | 286 |
| | — |
| | 286 |
|
| Balance, September 30, 2020 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 4,600 |
| | $ | (15 | ) | | $ | 9,066 |
|
| | | | | | | | | | | | | |
| Balance, December 31, 2019 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 3,972 |
| | $ | (16 | ) | | $ | 8,437 |
|
| Net income | | — |
| | — |
| | — |
| | 628 |
| | — |
| | 628 |
|
| Other comprehensive income | | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Balance, September 30, 2020 | | $ | 2 |
| | $ | — |
| | $ | 4,479 |
| | $ | 4,600 |
| | $ | (15 | ) | | $ | 9,066 |
|
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | Nine-Month Periods | | Six-Month Periods |
| | Ended September 30, | | Ended June 30, |
| | 2020 | | 2019 | | 2021 | | 2020 |
| Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
| Net income | $ | 628 |
| | $ | 625 |
| Net income | $ | 394 | | | $ | 342 | |
| Adjustments to reconcile net income to net cash flows from operating activities: | | | | Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| Depreciation and amortization | 696 |
| | 686 |
| Depreciation and amortization | 539 | | | 462 | |
| Allowance for equity funds | (73 | ) | | (51 | ) | Allowance for equity funds | (25) | | | (44) | |
| Changes in regulatory assets and liabilities | (17 | ) | | (31 | ) | Changes in regulatory assets and liabilities | (98) | | | (12) | |
| Deferred income taxes and amortization of investment tax credits | (48 | ) | | (78 | ) | Deferred income taxes and amortization of investment tax credits | 22 | | | (24) | |
| Other, net | 2 |
| | (3 | ) | Other, net | (1) | | | 1 | |
| Changes in other operating assets and liabilities: | | | |
| Changes in other operating assets and liabilities: | | | |
| Trade receivables, other receivables and other assets | (154 | ) | | 21 |
| Trade receivables, other receivables and other assets | (10) | | | 46 | |
| Inventories | (97 | ) | | (4 | ) | Inventories | 8 | | | (80) | |
| Derivative collateral, net | 22 |
| | 5 |
| Derivative collateral, net | 35 | | | 7 | |
| Prepaid expenses | | Prepaid expenses | 12 | | | (1) | |
| Accrued property, income and other taxes, net | 84 |
| | 99 |
| Accrued property, income and other taxes, net | 79 | | | 38 | |
| Accounts payable and other liabilities | 248 |
| | (2 | ) | Accounts payable and other liabilities | 91 | | | 35 | |
| Net cash flows from operating activities | 1,291 |
| | 1,267 |
| Net cash flows from operating activities | 1,046 | | | 770 | |
| | | | |
| | | | |
| Cash flows from investing activities: | | | |
| Cash flows from investing activities: | | | |
| Capital expenditures | (1,618 | ) | | (1,449 | ) | Capital expenditures | (819) | | | (973) | |
| Other, net | 31 |
| | 9 |
| Other, net | 0 | | | 29 | |
| Net cash flows from investing activities | (1,587 | ) | | (1,440 | ) | Net cash flows from investing activities | (819) | | | (944) | |
| | | | |
| | | | |
| Cash flows from financing activities: | | | |
| Cash flows from financing activities: | | | |
| Proceeds from long-term debt | 987 |
| | 990 |
| Proceeds from long-term debt | 0 | | | 987 | |
| Repayments of long-term debt | — |
| | (350 | ) | Repayments of long-term debt | (400) | | | 0 | |
| Net repayments of short-term debt | (130 | ) | | (30 | ) | |
| Dividends paid | — |
| | (175 | ) | |
| Net proceeds from (repayments of) short-term debt | | Net proceeds from (repayments of) short-term debt | 208 | | | (130) | |
| | Other, net | — |
| | (2 | ) | Other, net | (4) | | | 0 | |
| Net cash flows from financing activities | 857 |
| | 433 |
| Net cash flows from financing activities | (196) | | | 857 | |
| | | | |
| | | | |
| Net change in cash and cash equivalents and restricted cash and cash equivalents | 561 |
| | 260 |
| Net change in cash and cash equivalents and restricted cash and cash equivalents | 31 | | | 683 | |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 |
| | 92 |
| Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 19 | | | 36 | |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 597 |
| | $ | 352 |
| Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 50 | | | $ | 719 | |
The accompanying notes are an integral part of these consolidated financial statements.
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of SeptemberJune 30, 20202021 and for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20202021 and 2019.2020. The results of operations for the three- and nine-monthsix-month periods ended SeptemberJune 30, 20202021 and 20192020 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 20192020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the nine-monthsix-month period ended SeptemberJune 30, 2020.2021.
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing escrow accounts for disputes, vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of SeptemberJune 30, 20202021 and December 31, 2019,2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows: