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 $12 million for the third quarter of 2021 compared to 2020, primarily due to higher retail revenue of $8 million and higher wholesale and other revenue of $4 million. Retail revenue increased due to higher customer volumes of $28 million, partially offset by price impacts of $20 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers and higher customer usage. Wholesale and other revenue increased primarily due to higher wheeling revenue and REC sales, partially offset by $27 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.
In November 2019, PacifiCorp completed negotiationsEarnings increased $47 million for the third quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $65 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 higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher deferred net power costs in accordance with established adjustment mechanisms and the higher retail and wheeling revenue, partially offset by higher purchased power and thermal generation costs and higher wheeling expenses. Operations and maintenance expense decreased primarily due to 2020 costs associated with the Multi-State Process Workgroup,Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.
Operating revenue increased $202 million for the first nine months of 2021 compared to 2020, primarily due to higher retail revenue of $152 million and higher wholesale and other revenue of $50 million. Retail revenue increased due to higher customer volumes of $176 million, partially offset by price impacts of $24 million from lower rates primarily due to certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather. Wholesale and other revenue increased primarily due to higher wheeling revenue, wholesale volumes and REC sales, partially offset by $34 million from the Oregon RAC settlement (offset in depreciation expense) recognized in 2020.
Earnings increased $99 million for the first nine months of 2021 compared to 2020, primarily due to higher utility margin of $131 million, favorable income tax expense, from higher PTCs recognized due to new wind-powered generating facilities placed in-service and the impacts of ratemaking, and lower operations and maintenance expense of $48 million, partially offset by higher depreciation and amortization expense of $115 million and lower allowances for equity and borrowed funds used during construction of $53 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 purchased power and thermal generation costs and higher wheeling expenses. Operations and maintenance expense decreased primarily due to 2020 costs associated with the Klamath Hydroelectric Settlement Agreement and wildfires and lower thermal plant maintenance expense, partially offset by higher costs associated with additional wind-powered generating facilities placed in-service as well as higher distribution maintenance costs. The increase in depreciation and amortization expense was primarily due to the impacts of a depreciation study effective January 1, 2021, as well as additional assets placed in-service.
MidAmerican Funding
Operating revenue increased $154 million for the third quarter of 2021 compared to 2020, primarily due to higher electric operating revenue of $126 million and higher natural gas operating revenue of $30 million. Electric operating revenue increased due to higher retail revenue of $67 million and higher wholesale and other revenue of $59 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $43 million (largely offset in cost of sales) and higher customer volumes of $24 million. Electric retail customer volumes increased 5.6% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased mainly due to higher average wholesale per-unit prices of $34 million and higher wholesale volumes of $17 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 $24 million (offset in cost of sales).
Earnings increased $36 million for the third quarter of 2021 compared to 2020, primarily due to higher electric utility margin of $78 million and lower operations and maintenance expense of $12 million, mainly due to 2020 costs associated with storm restoration activities, partially offset by higher depreciation and amortization expense of $39 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms.
Operating revenue increased $612 million for the first nine months of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $344 million and higher electric operating revenue of $268 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 $345 million (offset in cost of sales), primarily due to the February 2021 polar vortex weather event. Electric operating revenue increased due to higher retail revenue of $157 million and higher wholesale and other revenue of $111 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $91 million (largely offset in cost of sales), higher customer volumes of $59 million and price impacts of $7 million from changes in sales mix. Electric retail customer volumes increased 6.5% due to increased usage of certain industrial customers and the favorable impact of weather. Electric wholesale and other revenue increased due to higher wholesale volumes of $64 million and higher average wholesale per-unit prices of $42 million.
Earnings increased $33 million for the first nine months of 2021 compared to 2020, primarily due to higher electric utility margin of $117 million and a favorable income tax benefit, partially offset by higher depreciation and amortization expense of $104 million, higher operations and maintenance expense of $18 million and lower allowances for equity and borrowed funds of $12 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues, partially offset by higher thermal generation and purchased power costs. Operations and maintenance expense increased primarily due to higher costs associated with additional wind-powered generating facilities placed in-service as well as higher natural gas distribution costs, partially offset by 2020 costs associated with storm restoration activities. The increase in depreciation and amortization expense was primarily due to additional assets placed in-service as well as from the impacts of certain regulatory mechanisms. The favorable income tax benefit was from higher PTCs recognized due to new wind-powered generating facilities placed in-service, partially offset by the impacts of ratemaking.
On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by the IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense of $13 million for the third quarter and $39 million for the first nine months of 2021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower in years 2021 through 2023 than would have been recognized absent the order. The annual amount of the deferral for 2021 will be recognized in the fourth quarter.
NV Energy
Operating revenue increased $43 million for the third 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 $80 million and an increase in the average number of customers, partially offset by lower base tariff general rates of $27 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 3.9%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.
Earnings increased $33 million for the third quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $51 million, lower income tax expense from the impacts of ratemaking and lower interest expense of $5 million, partially offset by lower electric utility margin of $39 million and higher depreciation and amortization expense of $9 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower earnings sharing at Nevada Power and lower regulatory deferrals and amortizations. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.
Operating revenue increased $84 million for the first nine months of 2021 compared to 2020, primarily due to higher electric operating revenue of $92 million, partially offset by lower natural gas operating revenue of $8 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (offset in cost of sales) of $153 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 $51 million at Nevada Power and a favorable regulatory decision in 2020. Electric retail customer volumes increased 4.2%, primarily due to higher customer usage 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).
Earnings increased $49 million for the first nine months of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $72 million, lower income tax expense from the impacts of ratemaking, lower interest expense of $17 million, lower pension costs of $10 million, higher interest and dividend income of $8 million and favorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower electric utility margin of $61 million and higher depreciation and amortization expense of $34 million. Electric utility margin decreased primarily due to lower base tariff general rates at Nevada Power and a favorable regulatory decision in 2020, partially offset by higher retail customer volumes, price impacts from changes in sales mix and an increase in the average number of customers. Operations and maintenance expense decreased primarily due to lower regulatory deferrals and amortizations and lower earnings sharing at Nevada Power. The increase in depreciation and amortization expense was mainly due to the regulatory amortization of decommissioning costs and additional assets placed in-service.
Northern Powergrid
Operating revenue increased $31 million for the third quarter of 2021 compared to 2020, primarily due to $17 million from the weaker United States dollar and higher distribution revenue of $17 million, mainly from 4.1% higher units distributed of $10 million and increased tariff rates of $8 million.
Earnings increased $57 million for the third quarter of 2021 compared to 2020, primarily due to a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and the higher distribution revenue.
Operating revenue increased $124 million for the first nine months of 2021 compared to 2020, primarily due to $69 million from the weaker United States dollar and higher distribution revenue of $56 million, mainly from increased tariff rates of $27 million and 4.5% higher units distributed of $26 million.
Earnings decreased $10 million for the first nine months of 2021 compared to 2020, primarily due to a deferred income tax charge of $109 million related to a June 2021 enacted increase in the United Kingdom corporate income tax rate from 19% to 25% effective April 1, 2023, partially offset by the higher distribution revenue, a deferred income tax charge in July 2020 of $35 million related to the United Kingdom corporate income tax rate not decreasing from 19% to 17% effective April 1, 2020, as had previously been announced, and $11 million from the weaker United States dollar.
BHE Pipeline Group
Operating revenue increased $521 million for the third quarter of 2021 compared to 2020, primarily due to $516 million of incremental revenue at BHE GT&S, acquired in November 2020, and higher transportation revenue of $23 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $19 million at Northern Natural Gas primarily due to lower volumes.
Earnings increased $66 million for the third quarter of 2021 compared to 2020, primarily due to $74 million of incremental earnings at BHE GT&S and higher earnings of $16 million at Kern River from the higher transportation revenue, partially offset by lower earnings of $25 million at Northern Natural Gas, primarily due to the lower transportation revenue.
Operating revenue increased $1,694 million for the first nine months of 2021 compared to 2020, primarily due to $1,563 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, higher gas sales at Northern Natural Gas of $33 million (largely offset in cost of sales) and higher transportation revenue of $25 million at Kern River largely due to higher rates, partially offset by lower transportation revenue of $69 million at Northern Natural Gas primarily due to lower volumes.
Earnings increased $306 million for the first nine months of 2021 compared to 2020, primarily due to $247 million of incremental earnings at BHE GT&S, higher earnings of $39 million at Northern Natural Gas and favorable earnings of $18 million at Kern River from the higher transportation revenue. 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 primarily to lower volumes.
BHE Transmission
Operating revenue increased $10 million for the third quarter of 2021 compared to 2020, primarily due to $10 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line of $5 million, partially offset by the impact of a regulatory decision received in November 2020 at AltaLink.
Earnings increased $7 million for the third quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line.
Operating revenue increased $31 million for the first nine months of 2021 compared to 2020, primarily due to $40 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line of $10 million, partially offset by the impacts of regulatory decisions received in April and November 2020 at AltaLink.
Earnings increased $11 million for the first nine months of 2021 compared to 2020, primarily due to $11 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 impact of a regulatory decision received in April 2020 at AltaLink.
BHE Renewables
Operating revenue increased $7 million for the third quarter of 2021 compared to 2020, primarily due to higher hydro, natural gas and solar revenues from higher generation and favorable market conditions, partially offset by an unfavorable change in the valuation of a power purchase agreement of $8 million and lower geothermal revenues from lower generation.
Earnings increased $1 million for the third quarter 2021 compared to 2020, primarily due to higher wind earnings of $6 million, mainly from tax equity investments offset by the unfavorable change in the valuation of a power purchase agreement, and higher hydro earnings of $5 million from higher generation, partially offset by lower geothermal earnings of $12 million, primarily due to lower geothermal generation and natural gas margin.
Operating revenue increased $42 million for the first nine months of 2021 compared to 2020, primarily due to higher natural gas, hydro and solar revenues from favorable market conditions and higher generation, partially offset by an unfavorable change in the valuation of a power purchase agreement of $22 million.
Earnings decreased $35 million for the first nine months of 2021 compared to 2020, primarily due to lower wind earnings of $56 million, largely from lower tax equity investment earnings of $48 million and the unfavorable change in the valuation of a power purchase agreement, partially offset by higher solar earnings of $18 million, mainly due to higher generation and lower depreciation expense, and higher hydro earnings of $5 million from higher generation. Tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $123 million, primarily due to the February 2021 polar vortex weather event, partially offset by $79 million of earnings from projects reaching commercial operation.
HomeServices
Operating revenue increased $1 million for the third quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $117 million, partially offset by lower mortgage revenue of $112 million from a 27% decrease in funded volume. The increase in brokerage revenue was due to $67 million from acquired companies and a 5% increase in closed transaction volume at existing companies, resulting from an increase in average sales price offset by fewer closed units.
Earnings decreased $75 million for the third quarter of 2021 compared to 2020, primarily due to lower earnings from mortgage services of $76 million, largely attributable to the decrease in funded volume.
Operating revenue increased $910 million for the first nine months of 2021 compared to 2020, primarily due to higher brokerage revenue of $933 million from a 34% increase in closed transaction volume, resulting from increases in closed units and average sales price, partially offset by lower mortgage revenue of $71 million from a decrease in refinance activity.
Earnings increased $75 million for the first nine months of 2021 compared to 2020, primarily due to higher earnings from brokerage services of $84 million, largely due to the increase in closed transaction volume, partially offset by lower earnings from mortgage services of $28 million, largely attributable to the decrease in refinance activity offset by an unfavorable 2020 contingent earn-out remeasurement.
BHE and Other
Operating revenue decreased $4 million for the third quarter of 2021 compared to 2020, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from lower volumes offset by favorable pricing.
Earnings decreased $1,118 million for the third quarter of 2021 compared to 2020, primarily due to the $1,046 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $86 million of lower federal income tax credits recognized on a consolidated basis, $26 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 October 2020 and unfavorable changes in the cash surrender value of corporate-owned life insurance policies, partially offset by lower other corporate costs and higher earnings of $18 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts.
Operating revenue increased $82 million for the first nine 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.
Earnings decreased $1,050 million for the first nine months of 2021 compared to 2020, primarily due to the $891 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $101 million of dividends on BHE's 4.00% Perpetual Preferred Stock, $44 million of lower federal income tax credits recognized on a consolidated basis, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by higher earnings of $30 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, and favorable changes in the cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of September 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 | $ | 300 | | | $ | 893 | | | $ | 542 | | | $ | 99 | | | $ | 14 | | | $ | 72 | | | $ | 789 | | | $ | 2,709 | |
| | | | | | | | | | | | | | | |
Credit facilities(1) | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 204 | | | 848 | | | 3,450 | | | 11,361 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | — | | | — | | | (127) | | | (68) | | | (230) | | | (1,543) | | | (1,968) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | (589) | |
Net credit facilities | 3,500 | | | 982 | | | 1,139 | | | 523 | | | 136 | | | 617 | | | 1,907 | | | 8,804 | |
| | | | | | | | | | | | | | | |
Total net liquidity | $ | 3,800 | | | $ | 1,875 | | | $ | 1,681 | | | $ | 622 | | | $ | 150 | | | $ | 689 | | | $ | 2,696 | | | $ | 11,513 | |
Credit facilities: | | | | | | | | | | | | | | | |
Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2023 | | 2022, 2025 | | 2022, 2026 | | |
| | | | | | | | | | | | | | | |
(1) Includes drawn uncommitted credit facilities totaling $1 million at Northern Powergrid Holdings.
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 were $7.0 billion and $4.5 billion, respectively. The increase was primarily due to $886 million of incremental net cash flows from operating activities at BHE GT&S, improved operating results, changes in working capital and favorable income tax cash flows.
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 were $(3.5) billion and $(6.6) billion, respectively. The change was primarily due to lower funding of tax equity investments and the July 2021 receipt of $1.3 billion due to the termination of the Q-Pipe Purchase Agreement. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2021 was $(2.0) billion. Uses of cash totaled $4.0 billion and consisted mainly of preferred stock redemptions totaling $1.5 billion, repayments of subsidiary debt totaling $1.3 billion, repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $366 million and net repayments of short-term debt totaling $316 million. Sources of cash totaled $2.0 billion and consisted of proceeds from subsidiary debt issuances.
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 nine-month period ended September 30, 2020 was $2.9 billion. Sources of cash totaled $5.9 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.6 billion. Uses of cash totaled $2.9 billion and consisted mainly of repayments of subsidiary debt totaling $1.6 billion, net repayments of short-term debt totaling $815 million, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.
Debt Repurchases
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.
Preferred Stock Redemptions
On July 22, 2021, BHE redeemed at par 1,450,003 shares of its 4.00% Perpetual Preferred Stock from certain subsidiaries of Berkshire Hathaway Inc. for $1.45 billion, plus an additional amount equal to the accrued dividends on the pro rata shares redeemed.
Common Stock Transactions
For the nine-month period ended September 30, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. 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):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
Capital expenditures by business: | | | | | |
PacifiCorp | $ | 1,618 | | | $ | 1,157 | | | $ | 1,558 | |
MidAmerican Funding | 1,341 | | | 1,266 | | | 1,943 | |
NV Energy | 509 | | | 519 | | | 829 | |
Northern Powergrid | 492 | | | 564 | | | 748 | |
BHE Pipeline Group | 428 | | | 684 | | | 1,262 | |
BHE Transmission | 276 | | | 234 | | | 268 | |
BHE Renewables | 46 | | | 129 | | | 166 | |
HomeServices | 21 | | | 29 | | | 42 | |
BHE and Other(1) | (124) | | | 12 | | | 27 | |
Total | $ | 4,607 | | | $ | 4,594 | | | $ | 6,843 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
Capital expenditures by type: | | | | | |
Wind generation | $ | 1,388 | | | $ | 872 | | | $ | 1,122 | |
Electric distribution | 1,182 | | | 1,217 | | | 1,745 | |
Electric transmission | 745 | | | 539 | | | 845 | |
Natural gas transmission and storage | 385 | | | 647 | | | 1,097 | |
Solar generation | 2 | | | 104 | | | 218 | |
Other | 905 | | | 1,215 | | | 1,816 | |
Total | $ | 4,607 | | | $ | 4,594 | | | $ | 6,843 | |
(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $275 million and $676 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73 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 $274 million and $25 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the repowering of wind-powered generating facilities totals $101 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 892 MWs of current repowering projects not in-service as of September 30, 2021, 591 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in service in the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
◦Construction of wind-powered generating facilities at BHE Renewables totaling $75 million for the nine-month period ended September 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 $10 million in 2021.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for PacifiCorp's 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 spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including 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 spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.
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 nine-month period ended September 30, 2021, and has commitments as of September 30, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $766 million for the remainder of 2021 and $414 million in 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. 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 September 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 state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new 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 expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. While the FERC included some limited exemptions 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. A number of parties, including Exelon, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. A request for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms was filed on October 5, 2021, and remains pending.
Assuming the continued effectiveness of the Illinois zero emission standard, Exelon Generation no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020 and 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 current 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 Protocol.deferral period. This reflected a $36 million reduction, or 1.7% decrease compared to current rates. In June 2021, PacifiCorp updated the requested recovery to $7 million to correct certain load related data reflected in the initial application. The agreement establishesupdated recovery request reflects a common allocation method$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 would result in a net 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 $4 million in net power cost savings with actual PTCs and net power cost savings to be usedtrued-up in the Energy Balancing Account. A hearing has been scheduled beginning November 2021.
In August 2021, PacifiCorp filed an application with the UPSC for approval of its Electric Vehicle Infrastructure Program, as provided for by Utah Oregon, Wyoming, IdahoHouse Bill 396 ("HB 396"), Electric Vehicle Charging Infrastructure Amendments. The filing details how PacifiCorp proposes to invest the $50 million authorized by HB 396 to support the development of electric vehicle infrastructure in Utah. The application also requests approval of a surcharge to collect $5 million per year for 10 years. The proposed surcharge would replace the existing Sustainable Transportation and California through 2023 and a separate method for Washington during the same time periodEnergy Plan cost adjustment that is basedwill expire on a system approach for cost allocations and provides a path forward for Washington to achieve compliance with Washington's newly-enacted Clean Energy Transformation Act. The agreement establishes a process for the 2020 Protocol signatories to resolve remaining outstanding cost-allocations to be implementedDecember 31, 2021. PacifiCorp's request would result in a new, permanent and long-term allocation method at the enddecrease of the four years. $5 million, or 0.2%, compared to current rates effective January 1, 2022.
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 2019,2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind-powered generating facilities, new wind-powered generating facilities and CPUC approval will be requestedcertain other new investments that had not been placed in service at the time of the filing. Additional compliance filings have been made to include investments in rates concurrent with when they were 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 rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind-powered generating facility and the Pryor 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, a deferral for resources not placed in service by June 30, 2021 was filed for consideration in a future rate proceeding.
In July 2021, in accordance with the OPUC's December 2020 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 requests 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. In January 2020, the OPUC issued an order adopting the 2020 Protocol. The WPSC held a hearing and issued a bench decision approving the 2020 Protocol in March 2020. In April 2020, the UPSC and the IPUC issued orders approving the 2020 Protocol.
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 A hearing for coal-fueled generating facilities and proposes a secondary phase to the proceeding be establishedthis deferral application was held 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, duringJuly 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, duringSeptember 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,depreciation expense incurred from January 1, 2021 through June 30, 2021, subject to a public notice period, and required associated benefits arising from COVID‑19 to be offset againstcertain offsetting cost savings during the deferred costs. During the public notice period, one party to the proceeding filed a petition for a rehearing of the matter.relevant period. The WPSC has scheduled 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 EBA 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 fullwill address 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 approvein 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 communities 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, 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 RRAREC 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 requested an interim basisrate effective July 1, 2021, which was approved by the WPSC in June 15, 2020. This increase will be offset2021. PacifiCorp filed an all-party stipulation in part by continued rate credits associated with 2017 Tax Reform benefits and bonus depreciation for which minor adjustments are proposed to go into effectOctober 2021. A hearing on the stipulation was held 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 updatefor 2022. The proposed $13 million, or 3.7%, rate increase has a requested effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with the power cost adjustment mechanism deferral account balance. The October update resulted in an increase greater than the balance in the deferral account. To maintain the intentmost of the settlement to update net power costs and decrease rates for customers, PacifiCorp and the parties, to the settlement reachedwhich includes an agreement to reflectadjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing in this difference in the deferral accountmatter is scheduled for future ratemaking. In November 2020, PacifiCorp and parties filed joint testimony supporting the amended settlement. The settlementJanuary 2022 with rates becoming effective after an order is subject to approval by the WUTC.issued.
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 investments, the Pryor Mountain wind-powered generating facility, repowered Foote Creek, new investment in transmission, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested recovery of the decommissioning and closure costs associated with the early retirement of Cholla Unit 4. PacifiCorp filed an all-party settlement with the IPUC in October 2021, resolving all issues in the case. The settlement provides an $8 million, or 2.9%, overall increase, which will be offset in part by a refund of deferred income tax savings over two years, resulting in a $6net increase of $4 million, or 5.1%, rate decrease1.4%. A hearing on the settlement has been scheduled for November 2021 for rates to be effective February 6, 2020. The CPUC's final order also resulted in an additional rate decrease of $6 million, or 5.1%, over the next three years due to the amortization of excess deferred income taxes attributed to 2017 Tax Reform.January 1, 2022.
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 2020March 2021 for which it received approval in June 2020.July 2021.
In December 2019, PacifiCorp filed an application notifying the CPUC 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. The memorandum account would be used to track costs associated with the unrecovered plant balance, decommissioning and other closure-related costs until PacifiCorp requests recovery 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") AllowanceGHG 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 thisprogram. In March 2021, the CPUC approved the rate change related to GHG allowances and in November 2021, approved updated rates for energy costs as filed.
In August 2021, PacifiCorp filed an application is approved, thiswith the CPUC to address California energy costs and GHG allowance costs. The application includes a $5 million rate decrease associated with lower energy costs, partially offset by an increase of $3 million to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade program. PacifiCorp's application would result in an overalla rate decrease of $6$2 million, or 5.9%1.9%, effective January 1, 2021.
In September 2020, PacifiCorp notified2022. As of November 2021, the CPUC of activation of PacifiCorp's Catastrophic Events Memorandum Account inhas not set a procedural schedule for this application.
FERC Show Cause Order
On April 15, 2021, the FERC issued an order to track costs for restoring serviceshow cause and notice of proposed penalty related to customersallegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and repairing, replacingremediate certain discrepancies resulting from transmission facility design and restoring damaged utility facilities dueactual field conditions, including transmission line clearances. In July 2021, PacifiCorp filed its answer to wildfiresthe FERC's show cause order denying the alleged violation of certain NERC reliability standards. The FERC Office of Enforcement staff replied in Happy Camp, California.September 2021. A decision by the FERC is pending.
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 nine-month period ended September 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. In July 2021, a hearing was held regarding the recovery of the 2020 costs held in a regulatory asset account and the cost recovery mechanism. In September 2021, the PUCN issued an order, approving the recovery of the 2020 costs with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management costs were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate for operating costs and a service territory specific rate for capital costs. In September 2021, the Nevada Utilities and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. The PUCN will reexamine the record and issue a modified order or reaffirm its original order with the outcome expected in the fourth quarter of 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 establishsubmit a plan to accelerate transportation electrification in the state and file a plan for certain high-voltage transmission infrastructure projects. SB 448 requires the Nevada Utilities to amend its most recently filed resource plan to include a plan 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 low carbon dioxide emissions that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. SB 448 also requires 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 establishes requirements for the review and the acceptance or modification of the transportation electrification investment plan by the PUCN. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. In addition, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of certain high-voltage transmission infrastructure. The PUCN opened rulemakings to address the regulations in SB 448.
ON Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR and corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset accounts related to 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. The Nevada Utilities may incur significant costsbeing accumulated as a result of COVID-19, including, but not limitedthe ON Line cost reallocation and the on-going reallocated revenue requirement. Sierra Pacific's application would, if approved by the PUCN as filed, result in a one-time rate increase of $28 million to higher credit loss expenses resulting frombe collected over a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers facing unprecedented economic pressures. The Nevada Utilities also expect to incur additional costs that cannot currently be predicted given the unprecedented nature of COVID-19.nine-month period starting on April 1, 2022.
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. In August 2021, the Competition and Markets Authority published a 40%provisional determination that proposed to uphold the 4.55% cost of equity, which was confirmed in their final determination 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 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,September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued a final rule adopting proceduresan order that accepted the November 1, 2021 effective date for determining whether natural gas pipelines were collecting unjustcertain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022 subject to refund and unreasonable rates in lightthe outcome of the reduction in the federal corporate tax rate from 2017 Tax Reform. Pursuanthearing procedures. This matter is pending.
In January 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 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 consisted 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 provided Alberta customers with immediate tariff relief in 2021. The approved 2021 tariff refund included 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 brought to bear an unprecedented need for rate relief that has not existed previously. These exceptional circumstances included 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. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs 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.
In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. Oral argument and reply argument were completed in a hearing in October 2021. A decision from the AUC is expected in January 2021.2022.
20212022 Generic Cost of Capital Proceeding
In December 2018,2020, the AUC initiated the 2021 GCOC2022 generic cost of capital proceeding. This proceeding to consider returning to a formula-based approach in determiningconsidered the return on equity and deemed equity ratios for a given year, starting with 2021. In April 2019, after receiving comments from interested parties,2022 and one or more additional test years. Due to 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,uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the AUC suspendedcommission requested participants to submit comments that addressed the proceeding for an indefinite period. This decision will be subject to review and reassessment byfollowing: (i) the AUC every 30 to 60 days. In May 2020,continuation of 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 October 2020, the AUC issued its decision and set the finalcurrently 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 was 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 Alberta Court of Appeal 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 fulfill 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,Alberta 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 2020,2021, the AUC determineddenied the Utilities Consumer Advocate's application for review and variance of its decision that a hearing is not requiredextended the approved 2020 and issued a proceeding schedule2021 return on equity of 8.5% and equity ratio of 37% to provide for argument, reply argument and the close of record by September 2020.2022. In September 2020, AltaLink and interveners filed written argument and reply argument, and a decision from2021, the Alberta Court of Appeal heard the Utilities Consumer Advocate's permission to appeal application. In October 2021, the Alberta Court of Appeal issued its judgement dismissing the Utilities Consumer Advocate's application for leave to appeal the AUC is expected by the end of 2020.decision setting final rates for 2022.
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 and generator of electricity in 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. The 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. 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. The rule was immediately challenged by environmental and tribal groups, as wellwells as numerous states. In September 2020,January 2021, the D.C. Circuit issuedlifted an administrative stay blockingand allowed the rule from takingto take effect, whilefinding that groups challenging the court considers whetherrule had not met the standard for a long-term suspensionstay. On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under the Congressional Review Act, disapproving the August 2020 rule. The resolution has the effect of reinstating the 2012 volatile organic compounds standards and the 2016 volatile organic compounds and methane standards for the oil and natural gas transmission and storage segments, as well as the methane standards for the production and processing segments of the oil and gas sector. On November 2, 2021, the EPA released proposed rules in response to Executive Order 13990. The November 2021 proposed rule would reduce methane emissions from both new and existing sources in the oil and natural gas industry. The proposal would expand and strengthen emissions reduction requirements for new, modified and reconstructed oil and natural gas sources, and would require states to reduce methane emissions from existing sources nationwide. The EPA intends to issue a supplemental proposal in 2022 and to finalize the rule by the end of 2022. Until the rule is warranted. Until such time as litigation is exhausted,finalized, the relevant Registrants cannot determine whether additional action may be required.the full impacts of the proposed rule.
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 or 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, United States 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 federalUtah 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 August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a FIP requiring the installation of SCR 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 asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval process.at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation, which has been stayed pending the Biden administration's review of the rule.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comescame 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 appealwas appealed in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. InOn January 13, 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, with the first step to repeal the 2015 rule and the second step to carry out a notice-and- comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. InOn July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized in September 12, 2019. InOn January 22, 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 extension of the compliance deadline. InOn December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by- casecase-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. InOn January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which 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 beis 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. TheOn June 9, 2021, the EPA and the Corps of Engineers originally proposed six categories, butannounced their intention to again revise the definition of "waters of the United States." After reviewing the Navigable Waters Protection Rule in accordance with Executive Order 13990, the final version they collapsed ditches and impoundments into other categories. There are also 12 categories of watersagencies determined that the rule significantly reduced clean water protections. The agencies highlighted as being excluded from coverage, including groundwater, ephemeral streams and pools,announced their intention to restore the clean water protections that were in place prior converted cropland and waste treatment systems.
In April 2020,to the implementation of the "waters of the United States" rule in 2015. On August 30, 2021, the United States SupremeDistrict Court establishedfor the District of Arizona vacated the Navigable Waters Protection Rule and the agencies quickly announced that they would no longer implement the rule nationwide. As a result, the agencies are relying on the pre-2015 regulatory definition of "waters of the United States" until they promulgate a new test for Clean Water Act jurisdictiondefinition. Projects that are already permitted under the Navigable Waters Protection Rule and those that received an approved jurisdictional determination in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding thatreliance on the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor testrule may continue 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.rely on those authorizations until they expire. 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 ruleagencies take final action 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 first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based 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 modifiesupdate the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering"waters of 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 changesUnited States," impacts 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 April 11, 2021. On October 16, 2020, the EPA released the pre-publication version of the final Holistic Approach to Closure: Part B rule ("Part B rule"). The Part B rule finalizes a two-step process, as set forth in the March 2020 proposal, allowing facilities to request approval to continue operating an existing unlined CCR surface impoundment with an alternate liner system. The other provisions that were contained in the Part B proposal, including (1) options to use CCR during closure 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, therelevant Registrants cannot determine whether additional action may be required.determined.
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 September 30, 2020,2021, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, and of cash flowsfor the nine-month periods ended September 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
November 6, 20205, 2021
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | |
| | As of |
| | September 30, | | December 31, |
| | 2021 | | 2020 |
ASSETS |
Current assets: | | | | |
Cash and cash equivalents | | $ | 893 | | | $ | 13 | |
Trade receivables, net | | 732 | | | 703 | |
Other receivables, net | | 41 | | | 48 | |
Inventories | | 465 | | | 482 | |
Derivative contracts | | 153 | | | 27 | |
| | | | |
Regulatory assets | | 70 | | | 116 | |
Prepaid expenses | | 89 | | | 79 | |
Other current assets | | 24 | | | 55 | |
Total current assets | | 2,467 | | | 1,523 | |
| | | | |
Property, plant and equipment, net | | 22,748 | | | 22,430 | |
Regulatory assets | | 1,326 | | | 1,279 | |
Other assets | | 530 | | | 470 | |
| | | | |
Total assets | | $ | 27,071 | | | $ | 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 |
| | September 30, | | December 31, |
| | 2021 | | 2020 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
Current liabilities: | | | | |
Accounts payable | | $ | 624 | | | $ | 772 | |
Accrued interest | | 115 | | | 127 | |
Accrued property, income and other taxes | | 159 | | | 80 | |
| | | | |
Accrued employee expenses | | 117 | | | 84 | |
Short-term debt | | — | | | 93 | |
Current portion of long-term debt | | 574 | | | 420 | |
Regulatory liabilities | | 112 | | | 115 | |
Other current liabilities | | 241 | | | 174 | |
Total current liabilities | | 1,942 | | | 1,865 | |
| | | | |
Long-term debt | | 8,625 | | | 8,192 | |
Regulatory liabilities | | 2,759 | | | 2,727 | |
Deferred income taxes | | 2,781 | | | 2,627 | |
Other long-term liabilities | | 1,064 | | | 1,118 | |
Total liabilities | | 17,171 | | | 16,529 | |
| | | | |
Commitments and contingencies (Note 9) | | 0 | | 0 |
| | | | |
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 | | 5,437 | | | 4,711 | |
Accumulated other comprehensive loss, net | | (18) | | | (19) | |
Total shareholders' equity | | 9,900 | | | 9,173 | |
| | | | |
Total liabilities and shareholders' equity | | $ | 27,071 | | | $ | 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 | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 4,031 | | | $ | 3,829 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 505 | | | 499 | | | 1,370 | | | 1,299 | |
Operations and maintenance | 267 | | | 332 | | | 781 | | | 829 | |
Depreciation and amortization | 272 | | | 234 | | | 811 | | | 696 | |
Property and other taxes | 54 | | | 53 | | | 158 | | | 154 | |
Total operating expenses | 1,098 | | | 1,118 | | | 3,120 | | | 2,978 | |
| | | | | | | |
Operating income | 393 | | | 361 | | | 911 | | | 851 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (110) | | | (107) | | | (322) | | | (319) | |
Allowance for borrowed funds | 6 | | | 14 | | | 18 | | | 36 | |
Allowance for equity funds | 13 | | | 29 | | | 38 | | | 73 | |
Interest and dividend income | 7 | | | 2 | | | 18 | | | 8 | |
Other, net | (5) | | | 5 | | | 5 | | | 9 | |
Total other income (expense) | (89) | | | (57) | | | (243) | | | (193) | |
| | | | | | | |
Income before income tax (benefit) expense | 304 | | | 304 | | | 668 | | | 658 | |
Income tax (benefit) expense | (28) | | | 18 | | | (58) | | | 30 | |
Net income | $ | 332 | | | $ | 286 | | | $ | 726 | | | $ | 628 | |
|
| | | | | | | | | | | | | | | |
| 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, 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 | |
| | | | | | | | | | | | |
Balance, June 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,105 | | | $ | (19) | | | $ | 9,567 | |
Net income | | — | | | — | | | — | | | 332 | | | — | | | 332 | |
Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,437 | | | $ | (18) | | | $ | 9,900 | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | |
Net income | | — | | | — | | | — | | | 726 | | | — | | | 726 | |
Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,437 | | | $ | (18) | | | $ | 9,900 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | 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 | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2021 | | 2020 |
Cash flows from operating activities: | | | | Cash flows from operating activities: | | | |
Net income | $ | 628 |
| | $ | 625 |
| Net income | $ | 726 | | | $ | 628 | |
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 | 811 | | | 696 | |
Allowance for equity funds | (73 | ) | | (51 | ) | Allowance for equity funds | (38) | | | (73) | |
Changes in regulatory assets and liabilities | (17 | ) | | (31 | ) | Changes in regulatory assets and liabilities | (185) | | | (17) | |
Deferred income taxes and amortization of investment tax credits | (48 | ) | | (78 | ) | Deferred income taxes and amortization of investment tax credits | 33 | | | (48) | |
Other, net | 2 |
| | (3 | ) | Other, net | — | | | 2 | |
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 | (1) | | | (150) | |
Inventories | (97 | ) | | (4 | ) | Inventories | 17 | | | (97) | |
Derivative collateral, net | 22 |
| | 5 |
| Derivative collateral, net | 19 | | | 22 | |
Prepaid expenses | | Prepaid expenses | (11) | | | (4) | |
Accrued property, income and other taxes, net | 84 |
| | 99 |
| Accrued property, income and other taxes, net | 96 | | | 84 | |
Accounts payable and other liabilities | 248 |
| | (2 | ) | Accounts payable and other liabilities | 77 | | | 248 | |
Net cash flows from operating activities | 1,291 |
| | 1,267 |
| Net cash flows from operating activities | 1,544 | | | 1,291 | |
| | | |
| | | | |
Cash flows from investing activities: | | | |
| Cash flows from investing activities: | | | |
Capital expenditures | (1,618 | ) | | (1,449 | ) | Capital expenditures | (1,157) | | | (1,618) | |
Other, net | 31 |
| | 9 |
| Other, net | 7 | | | 31 | |
Net cash flows from investing activities | (1,587 | ) | | (1,440 | ) | Net cash flows from investing activities | (1,150) | | | (1,587) | |
| | | |
| | | | |
Cash flows from financing activities: | | | |
| Cash flows from financing activities: | | | |
Proceeds from long-term debt | 987 |
| | 990 |
| Proceeds from long-term debt | 984 | | | 987 | |
Repayments of long-term debt | — |
| | (350 | ) | Repayments of long-term debt | (400) | | | — | |
Net repayments of short-term debt | (130 | ) | | (30 | ) | |
Dividends paid | — |
| | (175 | ) | |
Repayments of short-term debt | | Repayments of short-term debt | (93) | | | (130) | |
| Other, net | — |
| | (2 | ) | Other, net | (5) | | | — | |
Net cash flows from financing activities | 857 |
| | 433 |
| Net cash flows from financing activities | 486 | | | 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 | 880 | | | 561 | |
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 | $ | 899 | | | $ | 597 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
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 September 30, 20202021 and for the three- and nine-month periods ended September 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-month periods ended September 30, 20202021 and 2019.2020. The results of operations for the three- and nine-month periods ended September 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-month period ended September 30, 2020.2021.
Coronavirus Disease 2019 ("COVID-19")
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
In March 2020, COVID‑19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of PacifiCorp's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID‑19 has impacted PacifiCorp's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial and industrial customer classes, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections across PacifiCorp's service territory and suspension of late payment fees in certain jurisdictions implemented to assist customers. While PacifiCorp does not currently expect a significant increase in employer contributions to its retirement plans, continued market volatility caused by COVID-19 may lead to increased contributions in the future. The duration and extent of COVID‑19 and its future impact on PacifiCorp's business cannot be reasonably estimated at this time and the longer-term impacts of COVID-19 and related customer and governmental responses remain uncertain. Accordingly, significant estimates used in the preparation of PacifiCorp's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to PacifiCorp and potential regulatory deferral or recovery of certain costs may be subject to significant adjustments in future periods.
In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID‑19 with the Utah Public Service Commission ("UPSC"), the Oregon Public Utility Commission ("OPUC"), the Wyoming Public Service Commission ("WPSC"), the Washington Utilities and Transportation Commission and the Idaho Public Utilities Commission ("IPUC"). In April 2020, as ordered by the California Public Utilities Commission, 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. 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.
| |
(2) | Cash and Cash Equivalents and Restricted Cash and Cash Equivalents |
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 September 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):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 893 | | | $ | 13 | |
Restricted cash included in other current assets | 4 | | | 4 | |
Restricted cash included in other assets | 2 | | | 2 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 899 | | | $ | 19 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Cash and cash equivalents | $ | 590 |
| | $ | 30 |
|
Restricted cash included in other current assets | 4 |
| | 4 |
|
Restricted cash included in other assets | 3 |
| | 2 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 597 |
| | $ | 36 |
|
(3) Property, Plant and Equipment, Net
| |
(3) | Property, Plant and Equipment, Net
|
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,635 | | | $ | 12,861 | |
Transmission | 60 - 90 years | | 7,833 | | | 7,632 | |
Distribution | 20 - 75 years | | 7,889 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,083 | | | 1,054 | |
Other | 5 - 60 years | | 1,535 | | | 1,510 | |
Utility plant in service | | | 31,975 | | | 30,717 | |
Accumulated depreciation and amortization | | | (10,370) | | | (9,838) | |
Utility plant in service, net | | | 21,605 | | | 20,879 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 9 | | | 9 | |
Plant, net | | | 21,614 | | | 20,888 | |
Construction work-in-progress | | | 1,134 | | | 1,542 | |
Property, plant and equipment, net | | | $ | 22,748 | | | $ | 22,430 | |
|
| | | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| Depreciable Life | | 2020 | | 2019 |
Utility Plant: | | | | | |
Generation | 14 - 67 years | | $ | 12,475 |
| | $ | 12,509 |
|
Transmission | 58 - 75 years | | 6,687 |
| | 6,482 |
|
Distribution | 20 - 70 years | | 7,522 |
| | 7,307 |
|
Intangible plant(1) | 5 - 75 years | | 1,027 |
| | 1,016 |
|
Other | 5 - 60 years | | 1,483 |
| | 1,449 |
|
Utility plant in service | | | 29,194 |
| | 28,763 |
|
Accumulated depreciation and amortization | | | (9,886 | ) | | (9,803 | ) |
Utility plant in-service, net | | | 19,308 |
| | 18,960 |
|
Other non-regulated, net of accumulated depreciation and amortization | 59 years | | 9 |
| | 10 |
|
Plant, net | | | 19,317 |
| | 18,970 |
|
Construction work-in-progress | | | 2,725 |
| | 2,003 |
|
Property, plant and equipment, net | | | $ | 22,042 |
| | $ | 20,973 |
|
| |
(1) | Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years. |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
DuringEffective January 1, 2021, PacifiCorp revised its depreciation rates based on its recent depreciation study that was approved by its state regulatory commissions, other than in California. The approved depreciation rates resulted in an increase in depreciation expense of approximately $38 million for the three-month period ended September 30, 2021 as compared to the three-month period ended September 30, 2020, and $120 million for the nine-month period endedSeptember 30, 2021 compared to the nine-month period ended September 30, 2020, PacifiCorp acquired wind turbines from BHE Wind, LLC, an indirect wholly owned subsidiary based on historical property, plant and equipment balances and including depreciation of BHE, for $147 million. The wind turbines will be installed as part of newly constructed wind-poweredcertain coal-fueled generating facilities that are planned to be placedunits in service in 2020 and 2021.Washington over accelerated periods.
| |
(4) | Recent Financing Transactions |
Long-Term(4) Recent Financing Transactions
Long-term Debt
In April 2020,November 2021, PacifiCorp issued $400exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.70%2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due 2030 and $600 million of its 3.30% First Mortgage Bonds due 2051.June 2052. PacifiCorp intends to useused the net proceeds to fundfinance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily for renewable resourcesfrom the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and associated transmission projects,the construction and foracquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general corporate purposes.funds.
In June 2021, PacifiCorp terminated, upon lender consent, its existing $600 million unsecured credit facility expiring in June 2022. In June 2021, PacifiCorp amended and restated its other existing $600 million unsecured credit facility expiring in June 2022 with one remaining one-year extension option. The amendment increased the lender commitment to $1.2 billion, extended the expiration date to June 2024 and increased the available maturity extension options to an unlimited number, subject to lender consent.
Common Shareholder's Equity
In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.
(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | 4 | | | 3 | | | 4 | | | 3 | |
Federal income tax credits | (20) | | | (15) | | | (20) | | | (12) | |
Effects of ratemaking | (13) | | | (4) | | | (14) | | | (8) | |
| | | | | | | |
Other | (1) | | | 1 | | | — | | | 1 | |
Effective income tax rate | (9) | % | | 6 | % | | (9) | % | | 5 | % |
|
| | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | 3 |
| | 3 |
| | 3 |
| | 3 |
|
Federal income tax credits | (15 | ) | | (3 | ) | | (12 | ) | | (4 | ) |
Effects of ratemaking | (2 | ) | | (3 | ) | | (2 | ) | | (2 | ) |
Amortization of excess deferred income taxes | (2 | ) | | (18 | ) | | (6 | ) | | (7 | ) |
Other | 1 |
| | (1 | ) | | 1 |
| | — |
|
Effective income tax rate | 6 | % | | (1 | )% | | 5 | % | | 11 | % |
Income tax credits relate primarily to production tax credits ("PTCs"PTC") earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.
AmortizationEffects of excess deferred income taxesratemaking for the three- and nine-month periods ended September 30, 2021, and 2020 and 2019 is primarily attributable to activity associated with excess deferred income taxes. Excess deferred income tax amortization, net of deferrals, was $89 million for the amortizationnine-month period ended September 30, 2021, including the use of $3 million to amortize certain regulatory asset balances in Wyoming, as compared to $41 million for the nine-month period endedSeptember 30, 2020, including the use of $30 million and $49 million, respectively, of Oregon allocated excess deferred income taxes pursuant to the Oregon Renewable Adjustment Clause settlement, whereby a portion of Oregon allocated excess deferred income taxes was used to accelerate depreciation on Oregon's share of certain repowered wind facilities.retired equipment in Oregon. Excess deferred income tax amortization, net of deferrals, was $41 million for the three-month period ended September 30, 2021, as compared to $6 million for the three-month period ended September 30, 2020.
Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the nine-month periodsperiod ended September 30, 20202021 PacifiCorp received net cash payments for federal and 2019,state income tax from BHE totaling $109 million. For the nine-month period ended September 30, 2020 PacifiCorp made net cash payments for federal and state income tax to BHE totaling $79 million and $128 million, respectively.million.
66
| |
(6) | Employee Benefit Plans
|
(6) Employee Benefit Plans
Net periodic benefit creditcost (credit) for the pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | — | | | $ | — | |
Interest cost | 8 | | | 9 | | | 22 | | | 27 | |
Expected return on plan assets | (12) | | | (14) | | | (39) | | | (42) | |
Settlement | 4 | | | — | | | 4 | | | — | |
Net amortization | 5 | | | 4 | | | 15 | | | 13 | |
Net periodic benefit cost (credit) | $ | 5 | | | $ | (1) | | | $ | 2 | | | $ | (2) | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | |
Interest cost | 1 | | | 2 | | | 5 | | | 7 | |
Expected return on plan assets | (2) | | | (3) | | | (6) | | | (10) | |
Net amortization | 1 | | | — | | | 1 | | | — | |
Net periodic benefit (credit) cost | $ | — | | | $ | (1) | | | $ | 1 | | | $ | (2) | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Pension: | | | | | | | |
Service cost | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Interest cost | 9 |
| | 11 |
| | 27 |
| | 33 |
|
Expected return on plan assets | (14 | ) | | (17 | ) | | (42 | ) | | (50 | ) |
Net amortization | 4 |
| | 3 |
| | 13 |
| | 9 |
|
Net periodic benefit credit | $ | (1 | ) | | $ | (3 | ) | | $ | (2 | ) | | $ | (8 | ) |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
|
Interest cost | 2 |
| | 3 |
| | 7 |
| | 9 |
|
Expected return on plan assets | (3 | ) | | (6 | ) | | (10 | ) | | (16 | ) |
Net amortization | — |
| | 1 |
| | — |
| | 1 |
|
Net periodic benefit credit | $ | (1 | ) | | $ | (2 | ) | | $ | (2 | ) | | $ | (5 | ) |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $-$1 million, respectively, during 2020.2021. As of September 30, 2020,2021, $3 million of contributions had been made to the pension plans.
The amount of lump sum pension distributions in 2021 resulted in a July 31, 2021 remeasurement of the pension plan assets and projected benefit obligation. As a result of the remeasurement, PacifiCorp recognized a settlement loss of $4 million, net of regulatory deferrals. Additionally, the pension plan's underfunded status and regulatory asset each decreased by $84 million. | |
(7) | Risk Management and Hedging Activities
|
(7) Risk Management and Hedging Activities
PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, geopolitical factors, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.
PacifiCorp has established a risk management process that is designed to identify, manage and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
As of September 30, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 159 | | | $ | 40 | | | $ | 4 | | | $ | 1 | | | $ | 204 | |
Commodity liabilities | — | | | — | | | (46) | | | (9) | | | (55) | |
Total | 159 | | | 40 | | | (42) | | | (8) | | | 149 | |
| | | | | | | | | |
Total derivatives | 159 | | | 40 | | | (42) | | | (8) | | | 149 | |
Cash collateral (payable) receivable | (6) | | | — | | | 11 | | | — | | | 5 | |
Total derivatives - net basis | $ | 153 | | | $ | 40 | | | $ | (31) | | | $ | (8) | | | $ | 154 | |
| | | | | | | | | |
As of December 31, 2020 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 29 | | | $ | 6 | | | $ | 1 | | | $ | — | | | $ | 36 | |
Commodity liabilities | (2) | | | — | | | (23) | | | (28) | | | (53) | |
Total | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
| | | | | | | | | |
Total derivatives | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
Cash collateral receivable | — | | | — | | | 15 | | | 9 | | | 24 | |
Total derivatives - net basis | $ | 27 | | | $ | 6 | | | $ | (7) | | | $ | (19) | | | $ | 7 | |
|
| | | | | | | | | | | | | | | | | | | |
| Other | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of September 30, 2020 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 44 |
| | $ | 11 |
| | $ | 2 |
| | $ | — |
| | $ | 57 |
|
Commodity liabilities | (2 | ) | �� | — |
| | (31 | ) | | (33 | ) | | (66 | ) |
Total | 42 |
| | 11 |
| | (29 | ) | | (33 | ) | | (9 | ) |
| |
| | |
| | |
| | |
| | |
|
Total derivatives | 42 |
| | 11 |
| | (29 | ) | | (33 | ) | | (9 | ) |
Cash collateral receivable | — |
| | — |
| | 14 |
| | 11 |
| | 25 |
|
Total derivatives - net basis | $ | 42 |
| | $ | 11 |
| | $ | (15 | ) | | $ | (22 | ) | | $ | 16 |
|
| | | | | | | | | |
As of December 31, 2019 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 15 |
| | $ | 2 |
| | $ | 4 |
| | $ | — |
| | $ | 21 |
|
Commodity liabilities | (3 | ) | | — |
| | (31 | ) | | (50 | ) | | (84 | ) |
Total | 12 |
| | 2 |
| | (27 | ) | | (50 | ) | | (63 | ) |
| | | | | | | | | |
Total derivatives | 12 |
| | 2 |
| | (27 | ) | | (50 | ) | | (63 | ) |
Cash collateral receivable | — |
| | — |
| | 20 |
| | 27 |
| | 47 |
|
Total derivatives - net basis | $ | 12 |
| | $ | 2 |
| | $ | (7 | ) | | $ | (23 | ) | | $ | (16 | ) |
(1)PacifiCorp's commodity derivatives are generally included in rates. As of September 30, 2021 a regulatory liability of $149 million was recorded related to the net derivative asset of $149 million. As of December 31, 2020 a regulatory asset of $17 million was recorded related to the net derivative liability of $17 million.
| |
(1) | PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2020 and December 31, 2019, a regulatory asset of $9 million and $62 million, respectively, was recorded related to the net derivative liability of $9 million and $63 million, respectively. |
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Beginning balance | $ | (102) | | | $ | 68 | | | $ | 17 | | | $ | 62 | |
Changes in fair value | (128) | | | (49) | | | (247) | | | (21) | |
Net gains (losses) reclassified to operating revenue | — | | | 1 | | | (5) | | | 14 | |
Net gains (losses) reclassified to cost of fuel and energy | 81 | | | (11) | | | 86 | | | (46) | |
Ending balance | $ | (149) | | | $ | 9 | | | $ | (149) | | | $ | 9 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Beginning balance | $ | 68 |
| | $ | 101 |
| | $ | 62 |
| | $ | 96 |
|
Changes in fair value | (49 | ) | | 16 |
| | (21 | ) | | (12 | ) |
Net gains (losses) reclassified to operating revenue | 1 |
| | (11 | ) | | 14 |
| | (27 | ) |
Net (losses) gains reclassified to cost of fuel and energy | (11 | ) | | (25 | ) | | (46 | ) | | 24 |
|
Ending balance | $ | 9 |
| | $ | 81 |
| | $ | 9 |
| | $ | 81 |
|
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
| | | | | | | | | | | | | | | | | |
| Unit of | | September 30, | | December 31, |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity sales, net | Megawatt hours | | — | | | (1) | |
Natural gas purchases | Decatherms | | 101 | | | 100 | |
| | | | | |
|
| | | | | | | |
| Unit of | | September 30, | | December 31, |
| Measure | | 2020 | | 2019 |
| | | | | |
Electricity sales, net | Megawatt hours | | (2 | ) | | (2 | ) |
Natural gas purchases | Decatherms | | 102 |
| | 129 |
|
Credit Risk
PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third‑party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contractsagreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," or in some cases terminate the contract, in the event ofassurance" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2020,2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Servicesfrom the recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $62$54 million and $80$51 million as of September 30, 20202021 and December 31, 2019,2020, respectively, for which PacifiCorp had posted collateral of $25$11 million and $47$24 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 20202021 and December 31, 2019,2020, PacifiCorp would have been required to post $33$36 million and $27$25 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
69
| |
(8) | Fair Value Measurements
|
(8) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
The following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | | | |
| Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of September 30, 2021 | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 204 | | | $ | — | | | $ | (11) | | | $ | 193 | |
Money market mutual funds | 876 | | | — | | | — | | | — | | | 876 | |
Investment funds | 31 | | | — | | | — | | | — | | | 31 | |
| $ | 907 | | | $ | 204 | | | $ | — | | | $ | (11) | | | $ | 1,100 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (55) | | | $ | — | | | $ | 16 | | | $ | (39) | |
| | | | | | | | | |
As of December 31, 2020 | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 36 | | | $ | — | | | $ | (3) | | | $ | 33 | |
Money market mutual funds | 6 | | | — | | | — | | | — | | | 6 | |
Investment funds | 25 | | | — | | | — | | | — | | | 25 | |
| $ | 31 | | | $ | 36 | | | $ | — | | | $ | (3) | | | $ | 64 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (53) | | | $ | — | | | $ | 27 | | | $ | (26) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $5 million and $24 million as of September 30, 2021 and December 31, 2020, respectively.
|
| | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of September 30, 2020 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | 57 |
| | $ | — |
| | $ | (4 | ) | | $ | 53 |
|
Money market mutual funds(2) | | 587 |
| | — |
| | — |
| | — |
| | 587 |
|
Investment funds | | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
| | $ | 612 |
| | $ | 57 |
| | $ | — |
| | $ | (4 | ) | | $ | 665 |
|
| | | | | | | | | | |
Liabilities - Commodity derivatives | | $ | — |
| | $ | (66 | ) | | $ | — |
| | $ | 29 |
| | $ | (37 | ) |
| | | | | | | | | | |
As of December 31, 2019 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | 21 |
| | $ | — |
| | $ | (7 | ) | | $ | 14 |
|
Money market mutual funds(2) | | 23 |
| | — |
| | — |
| | — |
| | 23 |
|
Investment funds | | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
| | $ | 48 |
| | $ | 21 |
| | $ | — |
| | $ | (7 | ) | | $ | 62 |
|
| | | | | | | | | | |
Liabilities - Commodity derivatives | | $ | — |
| | $ | (84 | ) | | $ | — |
| | $ | 54 |
| | $ | (30 | ) |
| |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $25 million and $47 million as of September 30, 2020 and December 31, 2019, respectively. |
| |
(2) | Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 7 for further discussion regarding PacifiCorp's risk management and hedging activities.
PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2021 | | As of December 31, 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 9,199 | | | $ | 11,005 | | | $ | 8,612 | | | $ | 10,995 | |
(9) Commitments and Contingencies
|
| | | | | | | | | | | | | | | | |
| | As of September 30, 2020 | | As of December 31, 2019 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 8,649 |
| | $ | 10,860 |
| | $ | 7,658 |
| | $ | 9,280 |
|
| |
(9) | Commitments and Contingencies
|
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
California and Oregon 2020 Wildfires
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). The wildfires have spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California. Certain of theCalifornia, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires are still burningindicate over 2,000 structures destroyed, including residences; several structures damaged; multiple individuals injured; and are atseveral fatalities. Fire suppression costs estimated by various levels of containment.agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing. Although those investigations are not complete, several civil actions (includingongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.
Several lawsuits have been filed in Oregon and California, including a putative class action complaint) have been filedcomplaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.
In California, under the doctrine of inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages along with associated interest and attorneys' fees where its facilities are a substantial cause of a wildfire that caused the property damage, even ifwithout the utility is not atbeing found negligent and regardless of fault. To date, no lawsuits arising from the 2020 Wildfires have been filed in California.California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment.equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property damage,and natural resource damage; fire suppression costs,costs; personal injury damagesand loss of life damages; and interest.
As of September 30, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. Given the early stagesThese accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of the investigations into the cause and origin of the 2020 Wildfires and the uncertainty surrounding potential damages, itlife damages. It is reasonably possible that PacifiCorp maywill incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred. PacifiCorp has some levelincurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage that may applyis expected to damages caused by wildfires, but it may be insufficientavailable to cover all such damages. PacifiCorp has accrued its best estimateat least a portion of the expected probable insurance recovery associated with the estimated losses accrued.losses.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.
In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four main-stemmainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. The order does not immediately take effectIn November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and PacifiCorp is working with its settlement partners to implement the agreement.
The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions oncontinue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021, to remove PacifiCorp from the license for the Klamath Hydroelectric Project and relicensed projects. Environmental interests, supported byadd the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. The transfer will be effective after PacifiCorp secures property transfer approvals from its state public utility commissions and 30 days following the issuance of a license surrender order from the FERC for the project. In July 2021, the Oregon, Wyoming, Idaho and California Oregon and other states, askedstate public utility commissions approved the court to rehearproperty transfer. In August 2021, PacifiCorp notified the case, which was denied. Subsequently, environmental groups, supported by numerous states, filed a petition for certiorari beforePublic Service Commission of Utah of the United States Supreme Court, which was denied on December 9, 2019, thereby allowing the circuit court opinion to stand as a final and unappealable decision.property transfer, however no formal approval is required in Utah.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.
| |
(10) | Revenue from Contracts with Customers |
(10) Revenue from Contracts with Customers
The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 530 | | | $ | 519 | | | $ | 1,442 | | | $ | 1,363 | |
Commercial | 428 | | | 418 | | | 1,180 | | | 1,122 | |
Industrial | 296 | | | 293 | | | 849 | | | 838 | |
Other retail | 98 | | | 114 | | | 214 | | | 209 | |
Total retail | 1,352 | | | 1,344 | | | 3,685 | | | 3,532 | |
Wholesale | 58 | | | 59 | | | 124 | | | 76 | |
Transmission | 55 | | | 33 | | | 117 | | | 79 | |
Other Customer Revenue | 26 | | | 42 | | | 80 | | | 88 | |
Total Customer Revenue | 1,491 | | | 1,478 | | | 4,006 | | | 3,775 | |
Other revenue | — | | | 1 | | | 25 | | | 54 | |
Total operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 4,031 | | | $ | 3,829 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 519 |
| | $ | 478 |
| | $ | 1,363 |
| | $ | 1,316 |
|
Commercial | 418 |
| | 419 |
| | 1,122 |
| | 1,152 |
|
Industrial | 293 |
| | 306 |
| | 838 |
| | 887 |
|
Other retail | 114 |
| | 100 |
| | 209 |
| | 203 |
|
Total retail | 1,344 |
| | 1,303 |
| | 3,532 |
| | 3,558 |
|
Wholesale | 59 |
| | 8 |
| | 76 |
| | 47 |
|
Transmission | 33 |
| | 26 |
| | 79 |
| | 76 |
|
Other Customer Revenue | 42 |
| | 17 |
| | 88 |
| | 55 |
|
Total Customer Revenue | 1,478 |
| | 1,354 |
| | 3,775 |
| | 3,736 |
|
Other revenue | 1 |
| | 13 |
| | 54 |
| | 57 |
|
Total operating revenue | $ | 1,479 |
| | $ | 1,367 |
| | $ | 3,829 |
| | $ | 3,793 |
|
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
| |
Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Months of 20202021 and 20192020
Overview
Net income for the third quarter of 20202021 was $286$332 million, an increase of $8$46 million, or 3%16%, compared to 2019.2020. Net income increased primarily due to lower operations and maintenance expense of $65 million, primarily due to prior year costs associated with the Klamath Hydroelectric Projectand estimated losses in the prior year associated with wildfires, lower income tax expense of $46 million primarily due to the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service, and higher utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $24 million. Utility margin increased primarily due to higher retail and wheeling revenue, higher deferred net power costs in accordance with established adjustment mechanisms, lower purchased electricity volumes and higher REC revenue, partially offset by higher purchased electricity prices, thermal generation costs, and wheeling expenses. Retail customer volumes increased 2.1%, primarily due to an increase in the average number of customers and higher customer usage. Energy generated increased 9% for the third quarter of 2021 compared to 2020 primarily due to higher wind-powered, coal-fueled, and natural gas-fueled generation, partially offset by lower hydroelectric generation. Wholesale electricity sales volumes increased 4% and purchased electricity volumes decreased 16%.
Net income for the first nine months of 2021 was $726 million, an increase of $98 million, or 16%, compared to 2020. Net income increased primarily due to higher utility margin of $50$131 million, lower income tax expense of $118 million (excluding theprior year impacts of the Oregon RAC settlement of $27 million offset in depreciation expense), primarily from the impacts of ratemaking and higher PTCs recognized of $35 million due to repowerednew wind-powered generating facilities placed in-service, lower operations and maintenance expense of $48 million, primarily due to prior year costs associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires, partially offset by higher depreciation and amortization expense of $115 million, including the impacts of the depreciation study for which rates became effective January 2021, and lower allowances for equity and borrowed funds used during construction of $11 million, partially offset by higher operations and maintenance expenses of $80 million primarily due to costs associated with the KHSA and wildfires, higher property taxes of $7 million and higher interest expense of $6$53 million. Utility margin increased primarily due to the higher retail, wholesale, and retail revenues, lower coal-fueled generation volumes and lower purchased electricity prices, partially offset by lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms andwheeling revenue, higher purchased electricity volumes. Retail customer volumes remained relatively unchanged primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather and an increase in the average number of customers. Energy generated decreased 4% for the third quarter of 2020 compared to 2019 primarily due to lower coal-fueled and hydroelectric generation, partially offset by higher wind-powered and natural gas-fueled generation. Wholesale electricity sales volumes increased 9% and purchased electricity volumes increased 18%.
Net income for the first nine months of 2020 was $628 million, an increase of $3 million compared to 2019. Net income increased primarily due to higher PTCs recognized of $52 million due to repowered wind-powered generating facilities, higher allowances for equity and borrowed funds used during construction of $32 million and higher utility margin of $16 million (excluding the impacts of the Oregon RAC settlement of $34 million offset in depreciation expense), partially offset by higher operations and maintenance expenses of $66 million primarily due to costs associated with the KHSA and wildfires, higher interest expense of $20 million, higher pension and other postretirement costs of $10 million and increased property taxes of $8 million. Utility margin increased primarily due to lower coal-fueled generation volumes, higher wholesale and retail sales prices, lower purchased electricity prices and lower natural gas-fueled generation costs, partially offset by lower net deferrals of incurreddeferred net power costs in accordance with established adjustment mechanisms, lower retail and wholesale customer sales volumes, higher purchased electricity volumes and higher coal-fueledREC revenue, partially offset by higher purchased electricity prices, thermal generation prices.costs and wheeling expenses. Retail customer volumes decreased 1.8%increased 4.4%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercialhigher customer usage, and higher residential customer usage, partially offset by an increase in the average number of customers, and the favorable impactimpacts of weather. Energy generated decreased 5%increased 14% for the first nine months of 20202021 compared to 20192020 primarily due to lowerhigher coal-fueled, wind-powered, and natural gas-fueled generation, partially offset by higher wind-powered andlower hydroelectric generation. Wholesale electricity sales volumes decreased 14%increased 20% and purchased electricity volumes increased 9%decreased 16%.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
PacifiCorp's cost of fuel and energy is directlygenerally recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin: | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 12 | | | 1 | % | | $ | 4,031 | | | $ | 3,829 | | | $ | 202 | | | 5 | % |
Cost of fuel and energy | 505 | | | 499 | | | 6 | | | 1 | | | 1,370 | | | 1,299 | | | 71 | | | 5 | |
Utility margin | 986 | | | 980 | | | 6 | | | 1 | | | 2,661 | | | 2,530 | | | 131 | | | 5 | |
Operations and maintenance | 267 | | | 332 | | | (65) | | | (20) | | | 781 | | | 829 | | | (48) | | | (6) | |
Depreciation and amortization | 272 | | | 234 | | | 38 | | | 16 | | | 811 | | | 696 | | | 115 | | | 17 | |
Property and other taxes | 54 | | | 53 | | | 1 | | | 2 | | | 158 | | | 154 | | | 4 | | | 3 | |
Operating income | $ | 393 | | | $ | 361 | | | $ | 32 | | | 9 | % | | $ | 911 | | | $ | 851 | | | $ | 60 | | | 7 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,479 |
| | $ | 1,367 |
| | $ | 112 |
| | 8 | % | | $ | 3,829 |
| | $ | 3,793 |
| | $ | 36 |
| | 1 | % |
Cost of fuel and energy | 499 |
| | 464 |
| | 35 |
| | 8 |
| | 1,299 |
| | 1,313 |
| | (14 | ) | | (1 | ) |
Utility margin | 980 |
| | 903 |
| | 77 |
| | 9 |
| | 2,530 |
| | 2,480 |
| | 50 |
| | 2 |
|
Operations and maintenance | 332 |
| | 252 |
| | 80 |
| | 32 |
| | 829 |
| | 763 |
| | 66 |
| | 9 |
|
Depreciation and amortization | 234 |
| | 272 |
| | (38 | ) | | (14 | ) | | 696 |
| | 686 |
| | 10 |
| | 1 |
|
Property and other taxes | 53 |
| | 46 |
| | 7 |
| | 15 |
| | 154 |
| | 146 |
| | 8 |
| | 5 |
|
Operating income | $ | 361 |
| | $ | 333 |
| | $ | 28 |
| | 8 | % | | $ | 851 |
| | $ | 885 |
| | $ | (34 | ) | | (4 | )% |
Utility Margin
A comparison of PacifiCorp's key operating results related to utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,491 | | | $ | 1,479 | | | $ | 12 | | | 1 | % | | $ | 4,031 | | | $ | 3,829 | | | $ | 202 | | | 5 | % |
Cost of fuel and energy | 505 | | | 499 | | | 6 | | | 1 | | | 1,370 | | | 1,299 | | | 71 | | | 5 | |
Utility margin | $ | 986 | | | $ | 980 | | | $ | 6 | | | 1 | % | | $ | 2,661 | | | $ | 2,530 | | | $ | 131 | | | 5 | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 4,732 | | | 4,622 | | | 110 | | | 2 | % | | 13,396 | | | 12,699 | | | 697 | | | 5 | % |
Commercial | 5,078 | | | 4,799 | | | 279 | | | 6 | | | 14,181 | | | 13,157 | | | 1,024 | | | 8 | |
Industrial, irrigation and other | 5,375 | | | 5,446 | | | (71) | | | (1) | | | 14,976 | | | 14,907 | | | 69 | | | — | |
Total retail | 15,185 | | | 14,867 | | | 318 | | | 2 | | | 42,553 | | | 40,763 | | | 1,790 | | | 4 | |
Wholesale | 1,093 | | | 1,053 | | | 40 | | | 4 | | | 3,928 | | | 3,266 | | | 662 | | | 20 | |
Total sales | 16,278 | | | 15,920 | | | 358 | | | 2 | % | | 46,481 | | | 44,029 | | | 2,452 | | | 6 | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 2,006 | | | 1,971 | | | 35 | | | 2 | % | | 1,998 | | | 1,963 | | | 35 | | | 2 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 88.91 | | | $ | 90.25 | | | $ | (1.34) | | | (1) | % | | $ | 86.53 | | | $ | 86.60 | | | $ | (0.07) | | | — | % |
Wholesale | $ | 53.45 | | | $ | 57.54 | | | $ | (4.09) | | | (7) | % | | $ | 37.23 | | | $ | 38.58 | | | $ | (1.35) | | | (3) | % |
| | | | | | | | | | | | | | | |
Heating degree days | 196 | | | 194 | | | 2 | | | 1 | % | | 6,111 | | | 6,132 | | | (21) | | | — | % |
| | | | | | | | | | | | | | | |
Cooling degree days | 1,681 | | | 1,658 | | | 23 | | | 1 | % | | 2,427 | | | 2,097 | | | 330 | | | 16 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 9,011 | | | 8,576 | | | 435 | | | 5 | % | | 24,157 | | | 22,001 | | | 2,156 | | | 10 | % |
Natural gas | 3,886 | | | 3,638 | | | 248 | | | 7 | | | 10,174 | | | 8,881 | | | 1,293 | | | 15 | |
Hydroelectric(2) | 380 | | | 414 | | | (34) | | | (8) | | | 1,981 | | | 2,351 | | | (370) | | | (16) | |
Wind and other(2) | 1,323 | | | 720 | | | 603 | | | 84 | | | 4,534 | | | 2,696 | | | 1,838 | | | 68 | |
Total energy generated | 14,600 | | | 13,348 | | | 1,252 | | | 9 | | | 40,846 | | | 35,929 | | | 4,917 | | | 14 | |
Energy purchased | 3,058 | | | 3,621 | | | (563) | | | (16) | | | 9,407 | | | 11,245 | | | (1,838) | | | (16) | |
Total | 17,658 | | | 16,969 | | | 689 | | | 4 | % | | 50,253 | | | 47,174 | | | 3,079 | | | 7 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 18.39 | | | $ | 18.65 | | | $ | (0.26) | | | (1) | % | | $ | 17.98 | | | $ | 17.95 | | | $ | 0.03 | | | — | % |
Energy purchased | $ | 88.48 | | | $ | 53.28 | | | $ | 35.20 | | | 66 | % | | $ | 67.10 | | | $ | 45.85 | | | $ | 21.25 | | | 46 | % |
(1)GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,479 |
| | $ | 1,367 |
| | $ | 112 |
| | 8 | % | | $ | 3,829 |
| | $ | 3,793 |
| | $ | 36 |
| | 1 | % |
Cost of fuel and energy | 499 |
| | 464 |
| | 35 |
| | 8 |
| | 1,299 |
| | 1,313 |
| | (14 | ) | | (1 | ) |
Utility margin | $ | 980 |
| | $ | 903 |
| | $ | 77 |
| | 9 | % | | $ | 2,530 |
| | $ | 2,480 |
| | $ | 50 |
| | 2 | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 4,622 |
| | 4,298 |
| | 324 |
| | 8 | % | | 12,699 |
| | 12,213 |
| | 486 |
| | 4 | % |
Commercial | 4,799 |
| | 4,877 |
| | (78 | ) | | (2 | ) | | 13,157 |
| | 13,622 |
| | (465 | ) | | (3 | ) |
Industrial, irrigation and other | 5,446 |
| | 5,686 |
| | (240 | ) | | (4 | ) | | 14,907 |
| | 15,693 |
| | (786 | ) | | (5 | ) |
Total retail | 14,867 |
| | 14,861 |
| | 6 |
| | — |
| | 40,763 |
| | 41,528 |
| | (765 | ) | | (2 | ) |
Wholesale | 1,053 |
| | 962 |
| | 91 |
| | 9 |
| | 3,266 |
| | 3,778 |
| | (512 | ) | | (14 | ) |
Total sales | 15,920 |
| | 15,823 |
| | 97 |
| | 1 | % | | 44,029 |
| | 45,306 |
| | (1,277 | ) | | (3 | )% |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 1,971 |
| | 1,935 |
| | 36 |
| | 2 | % | | 1,963 |
| | 1,928 |
| | 35 |
| | 2 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 90.25 |
| | $ | 87.64 |
| | $ | 2.61 |
| | 3 | % | | $ | 86.60 |
| | $ | 85.65 |
| | $ | 0.95 |
| | 1 | % |
Wholesale | $ | 57.54 |
| | $ | 21.08 |
| | $ | 36.46 |
| | 173 | % | | $ | 38.58 |
| | $ | 26.58 |
| | $ | 12.00 |
| | 45 | % |
| | | | | | | | | | | | | | | |
Heating degree days | 194 |
| | 271 |
| | (77 | ) | | (28 | )% | | 6,132 |
| | 6,739 |
| | (607 | ) | | (9 | )% |
Cooling degree days | 1,658 |
| | 1,462 |
| | 196 |
| | 13 | % | | 2,097 |
| | 1,773 |
| | 324 |
| | 18 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 8,576 |
| | 9,391 |
| | (815 | ) | | (9 | )% | | 22,001 |
| | 25,059 |
| | (3,058 | ) | | (12 | )% |
Natural gas | 3,638 |
| | 3,619 |
| | 19 |
| | 1 |
| | 8,881 |
| | 8,995 |
| | (114 | ) | | (1 | ) |
Hydroelectric(2) | 414 |
| | 480 |
| | (66 | ) | | (14 | ) | | 2,351 |
| | 2,211 |
| | 140 |
| | 6 |
|
Wind and other(2) | 720 |
| | 353 |
| | 367 |
| | 104 |
| | 2,696 |
| | 1,710 |
| | 986 |
| | 58 |
|
Total energy generated | 13,348 |
| �� | 13,843 |
| | (495 | ) | | (4 | ) | | 35,929 |
| | 37,975 |
| | (2,046 | ) | | (5 | ) |
Energy purchased | 3,621 |
| | 3,071 |
| | 550 |
| | 18 |
| | 11,245 |
| | 10,357 |
| | 888 |
| | 9 |
|
Total | 16,969 |
| | 16,914 |
| | 55 |
| | — | % | | 47,174 |
| | 48,332 |
| | (1,158 | ) | | (2 | )% |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 18.65 |
| | $ | 19.17 |
| | $ | (0.52 | ) | | (3 | )% | | $ | 17.95 |
| | $ | 19.41 |
| | $ | (1.46 | ) | | (8 | )% |
Energy purchased | $ | 53.28 |
| | $ | 62.25 |
| | $ | (8.97 | ) | | (14 | )% | | $ | 45.85 |
| | $ | 49.88 |
| | $ | (4.03 | ) | | (8 | )% |
Quarter Ended September 30, 2021 compared to Quarter Ended September 30, 2020
| |
(1) | GWh amounts are net of energy used by the related generating facilities. |
| |
(2) | All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities. |
| |
(3) | The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities. |
Utility margin increased $77$6 million, or 1%, for the third quarter of 20202021 compared to 20192020 primarily due to:
•$40103 million of higher wholesaledeferred net power costs in accordance with established adjustment mechanisms;
•$12 million of favorable wheeling activities;
•$8 million increase in retail revenue primarily due to higher average market prices and higher volumes;
$39 million of higher retail revenuecustomer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 2.1%, primarily due to price impacts from changes in sales mix and higher retail customer volumes. While retail volume changes contributed to thean increase in retail revenue due to favorable weather impacts, higherthe average number of customers, and changes in sales mix, overall retail volumes were relatively flat due to the offsetting net impacts of decreases in commercial and industrialhigher customer usage, partially offset by the unfavorable impact of weather; and
•$6 million of higher REC, fly ash and increased residential customer usage drivenby-product revenues.
The increases above were partially offset by:
•$80 million of higher purchased electricity costs from higher average market prices, partially offset by COVID-19;lower volumes;
•$27 million of higherlower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense); and in the prior year;
•$15 million of lower coal-fueled generation costs primarily due to lower volumes.
The increases above were partially offset by:
$52 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and
$213 million of higher purchased electricitynatural gas-fueled generation costs due to higher average prices and higher volumes; and
•$7 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average market prices.
Operations and maintenance increased $80 decreased $65 million, or 32%20%, for the third quarter of 20202021 compared to 2019 primarily due to costs associated with the KHSA, increased wildfire and storm related costs, and increased bad debt expense.
Depreciation and amortization decreased $38 million, or 14%, for the third quarter of 2020 compared to 2019 primarily due to prior year accelerated depreciationcosts associated with the Klamath Hydroelectric Project and estimated losses in the prior year associated with wildfires and lower thermal plant maintenance expense, including overhauls, partially offset by higher wind plant and distribution maintenance.
Depreciation and amortization increased $38 million, or 16%, for the third quarter of $65 million (offset in income tax expense) for Oregon's share of certain retired wind equipment2021 compared to 2020 primarily due to repowering, compared to currentthe impacts of a depreciation study effective January 1, 2021 of approximately $38 million and higher plant in-service balances, partially offset by prior year accelerated depreciation of $27 million (offset in other revenue), due to the prior year Oregon RAC settlement.
PropertyAllowance for borrowed and other taxes increased$7equity funds decreased $24 million, or 15%56%, for the third quarter of 20202021 compared to 2019 primarily due to higher property taxes in Oregon and Utah.
Interest expense increased$6 million, or 6% for the third quarter of 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds increased $11 million, or 34%, for the third quarter of 2020 compared to 2019 primarily due to higher qualified construction work-in-progress balances.
Interest and dividend income decreased $3 million, or 60%, for the third quarter of 2020 compared to 2019 primarily due to lower interest rates in the current year.qualified construction work-in-progress balances.
Income tax expense increased $21Other, net decreased $10 million for the third quarter of 20202021 compared to 2020 primarily due to the July 2021 pension settlement loss and market movements related to corporate-owned life insurance policies.
Income tax (benefit) expense decreased $46 million to a benefit of $28 million for the third quarter of 2019.2021 compared to expense of $18 million for the third quarter of 2020. The effective tax rate was (9)% for 2021 and 6% for 2020 and (1)% for 2019.2020. The effective tax rate increaseddecreased primarily due to lower amortizationas a result of Oregon's allocatedhigher effects of ratemaking associated with excess deferred income taxes pursuant totax amortization in the Oregon RAC settlement, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering, partially offset bycurrent year and increased PTCs from PacifiCorp's repowerednew wind-powered generating facilities.
First Nine Months of 2021 compared to First Nine Months of 2020
Utility margin increased $50$131 million, or 5%, for the first nine months of 20202021 compared to 20192020 primarily due to:
•$74152 million of lower coal-fueled generation costsincrease in retail revenue primarily due to lowerhigher customer volumes, partially offset by lower rates driven by certain general rate case orders. Retail customer volumes increased 4.4%, primarily due to higher prices;customer usage, an increase in the average number of customers, and the favorable impact of weather;
•$151 million of higher deferred net power costs in accordance with established adjustment mechanisms;
•$21 million of favorable wheeling activities;
•$20 million of higher wholesale revenue due to higher wholesale volumes, partially offset by lower average wholesale market prices; and
•$18 million of higher REC, fly ash and by-product revenues.
The increases above were partially offset by:
•$117 million of higher purchased electricity costs due to higher average prices, partially offset by lower volumes;
•$58 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes;
•$34 million of higherlower other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense); in the prior year; and
•$2633 million of higher wholesale revenuecoal-fueled generation costs primarily due to higher average market prices,volumes, partially offset by lower volumes;average prices.
$20 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes;
$8 million from favorable wheeling activities; and
$1 million of lower purchased electricity costs primarily due to lower average market prices, partially offset by higher volumes.
The increases above were partially offset by:
$87 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and
$27 million of lower retail revenue from lower volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 1.8% primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by an increase in the average number of customers and the favorable impact of weather.
Operations and maintenance increased $66 decreased $48 million, or 9%6%, for the first nine months of 20202021 compared to 20192020 primarily due to prior year costs associated with the KHSA, increased wildfireKlamath Hydroelectric Project and storm related costs,estimated losses in the prior year associated with wildfires, lower thermal plant maintenance expense, including overhauls, and lower employee expenses, partially offset by higher wind plant and distribution maintenance and higher vegetation management costs and increased bad debt expense.costs.
Depreciation and amortizationincreased $10$115 million, or 1%17%, for the first nine months of 20202021 compared to 2019,2020 primarily due to currentthe impacts of a depreciation study effective January 1, 2021 of approximately $120 million, and higher plant in-service balances, partially offset by a $71 million decrease due to the prior year accelerated depreciationOregon RAC settlement ($3 million in the first quarter of 2021 (fully offset in other revenue) compared to $74 million in 2020 ($34 million offset in other revenue and $40 million offset in income tax expense) as a result of the Oregon RAC settlement, partially offset by prior year accelerated depreciation of $65 million (offset in income tax expense) on Oregon's share of certain retired wind equipment due to repowering.).
Property and other taxes increased $8 million, or 5% for the first nine months of 2020 compared to 2019, primarily due to higher property taxes in Oregon and Utah.
Interest expense increased $20 million, or 7% for the first nine months of 2020 compared to 2019 primarily due to higher average long-term debt balances, partially offset by a lower weighted average long-term debt interest rate.
Allowance for borrowed and equity funds increased $32decreased $53 million, or 42%49%, for the first nine months of 20202021 compared to 20192020 primarily due to higherlower qualified construction work-in-progress balances.balances and allowance for borrowed and equity funds rates.
Interest and dividend income Income tax (benefit) expensedecreased $9$88 million or 53%,to a benefit of $58 million for the first nine months of 20202021 compared to 2019 primarily due to lower interest rates in the current year.
Other, net decreased $13expense of $30 million or 59% for the first nine months of 2020 compared to 2019 primarily due to higher pension and other postretirement costs of $10 million.
Income tax expense decreased $47 million, or 61%, for the first nine months of 2020 compared to 2019.2020. The effective tax rate was (9)% for 2021 and 5% for 2020 and 11% for 2019.2020. The effective tax rate decreased primarily due toas a result of increased PTCs from PacifiCorp's repowerednew wind-powered generating facilities partially offset by lower amortizationand as a result of Oregon's allocatedhigher effects of ratemaking associated with excess deferred income taxes pursuant totax amortization in the Oregon RAC settlement whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering.current year.
Liquidity and Capital Resources
As of September 30, 2020,2021, PacifiCorp's total net liquidity was as follows (in millions):
|
| | | | |
Cash and cash equivalents | | $ | 590 |
|
| | |
Credit facilities | | 1,200 |
|
Less: | | |
Tax-exempt bond support | | (256 | ) |
Net credit facilities | | 944 |
|
| | |
Total net liquidity | | $ | 1,534 |
|
| | |
Credit facilities: | | |
Maturity dates | | 2022 |
|
| | | | | | | | |
Cash and cash equivalents | | $ | 893 | |
| | |
Credit facilities | | 1,200 | |
Less: | | |
| | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | 982 | |
| | |
Total net liquidity | | $ | 1,875 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 | |
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $1,291$1,544 million and $1,267$1,291 million, respectively. The change was primarily due to lowerhigher collections from retail customers and higher cash paidreceived for income taxes, and lower operating expense payments due to timing, partially offset by lower collections from retail customers.higher wholesale purchases.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $(1,587)$(1,150) million and $(1,440)$(1,587) million, respectively. The change is primarily due to an increasea decrease in capital expenditures of $169$461 million, partially offset by prior year proceeds from the settlement of notes receivable of $25 million associated with the sale of certain Utah mining assets in 2015. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2021 were $486 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $984 million. Uses of cash consisted substantially of $400 million for the repayment of long-term debt and $93 million for the repayment of short-term debt.
Net cash flows from financing activities for the nine-month period ended September 30, 2020 waswere $857 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $987 million. Uses of cash consisted of $130 million for the repayment of short-term debt.
Net cash flows from financing activities for the nine-month period ended September 30, 2019 was $433 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $990 million. Uses of cash consisted substantially of $350 million for the repayment of long-term debt, $175 million for common stock dividends paid to PPW Holdings LLC and $30 million for the repayment of short-term debt.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2020,2021, PacifiCorp had no short-term debt outstanding. As of December 31, 2019,2020, PacifiCorp had $130$93 million of short-term debt outstanding at a weighted average interest rate of 2.05%0.16%.
Long-term Debt
In April 2020,November 2021, PacifiCorp issued $400exercised its par call redemption option, available in the final three months prior to scheduled maturity, and redeemed $450 million of its 2.70%2.95% Series First Mortgage Bonds that was originally due February 2022.
In July 2021, PacifiCorp issued $1 billion of its 2.90% First Mortgage Bonds due 2030 and $600 million of its 3.30% First Mortgage Bonds due 2051.June 2052. PacifiCorp intends to useused the net proceeds to fundfinance a portion of the capital expenditures disbursed during the period from July 1, 2019 to May 31, 2021 with respect to investments, primarily for renewable resourcefrom the Energy Vision 2020 initiative, in the repowering of certain of its existing wind-powered generating facilities and associated transmission projects,the construction and foracquisition of new wind-powered generating facilities, which were previously financed with PacifiCorp's general corporate purposes.funds.
Debt Authorizations
Following the July 2021 long-term debt issuance, PacifiCorp has regulatory authority from the OPUC and the IPUC to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.
Common Shareholder's Equity
In October 2021, PacifiCorp declared a common stock dividend of $150 million, payable in November 2021, to PPW Holdings LLC.
Future Uses of Cash
PacifiCorp 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, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including regulatory approvals, PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp 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.
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):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Wind generation | $ | 807 | | | $ | 110 | | | $ | 138 | |
Electric distribution | 360 | | | 461 | | | 637 | |
Electric transmission | 300 | | | 212 | | | 316 | |
Other | 151 | | | 374 | | | 467 | |
Total | $ | 1,618 | | | $ | 1,157 | | | $ | 1,558 | |
|
| | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2019 | | 2020 | | 2020 |
| | | | | |
Transmission system investment | $ | 370 |
| | $ | 184 |
| | $ | 268 |
|
Wind investment | 687 |
| | 804 |
| | 1,329 |
|
Operating and other | 392 |
| | 630 |
| | 1,055 |
|
Total | $ | 1,449 |
| | $ | 1,618 |
| | $ | 2,652 |
|
PacifiCorp's 2019 and 2021 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate for these new resources and associated transmission in its forecast capital expenditures for 2021 through 2023. These estimates may change as a result of the RFP process. PacifiCorp's historical and forecast capital expenditures include the following:
•Wind generation includes both growth projects and operating expenditures. Growth projects include:
◦Construction of wind-powered generating facilities at PacifiCorp totaling $99 million and $705 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs that were placed in service in the first nine months of 2021. The energy production for these new facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. Similar to PacifiCorp's 2019 IRP, the 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to come online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. Planned spending for the construction of additional wind-powered generating facilities totals $17 million for the remainder of 2021.
◦Repowering of wind-powered generating facilities at PacifiCorp totaling $9 million and $99 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Certain repowering projects for existing facilities were placed in service in 2019, 2020 and in the first nine months of 2021. The energy production from these existing repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. Planned spending for the repowering of wind-powered generating facilities totals $7 million for the remainder of 2021.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $144 million and $21 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned electric distribution spending totals $51 million for the remainder of 2021 and relates to expenditures for new connections and distribution.
•Electric transmission includes both growth projects and operating expenditures. Transmission system investment through 2020 primarily reflects initial costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, expected to be placed in-service in 2020 and investment inNovember 2020. Planned spending for additional Energy Gateway Transmission segments expected to be placed in service consistent with generation resources sought in PacifiCorp's 2020 All Source RFP ("2020AS RFP"). Forecast spending2024-2026 totals $46 million in 2021.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $69 million and $53 million for the Aeolus-Bridger/Anticline linenine-month periods ended September 30, 2021 and 2020, respectively. Planned information technology spending totals $131$47 million in 2020.
Wind investment includesfor the following:
| |
◦ | Construction of wind-powered generating facilities at PacifiCorp totaling $705 million and $245 million for the nine-month periods ended September 30, 2020 and 2019, respectively. Construction includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and 2021 and the energy production is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $522 million for 2020. |
| |
◦ | Repowering existing wind-powered generating facilities at PacifiCorp totaling $99 million and $442 million for the nine-month periods ended September 30, 2020 and 2019, respectively. Certain repowering projects were placed in service in 2019 and the remaining repowering projects are expected to be placed in-service at various dates in 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for ten years following each facility's return to service. PacifiCorp anticipates costs for these activities will total an additional $3 million for 2020. |
Remaining investments relateremainder of 2021 and relates to operating projects that consist of advanced meter infrastructure costs, routine expenditures for generation transmission and distribution, planned spend for wildfire mitigation and other infrastructure needed to serve existing and expected demand.
Energy Supply Planning
As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations.
In October 2019,September 2021, PacifiCorp filed its 20192021 IRP with its state commissions. In November 2019, the WUTC temporarily suspended its practice of acknowledging utility IRPs, including PacifiCorp's 2019The IRP due to ongoing implementation activities associated with Washington state's Senate Bill 5116, the Clean Energy Transformation Act. In May 2020, the OPUC acknowledged the 2019 IRP with conditions. The UPSC also acknowledged the 2019 IRPincludes investments in May 2020. In September 2020, the IPUC acknowledged the 2019 IRP. The WPSC review of the 2019 IRP is ongoing. In October 2020, the WPSC concluded its docket investigating the 2019 IRP. A decision from the WPSCnew renewable energy resources, new battery storage resources and expanded transmission investments. New renewable energy resources in the 2019 IRP filing docket is yetinclude more than 1,800 MW of new wind-powered generation, over 2,100 MW of new solar-powered generation and nearly 700 MW of new battery storage capacity by 2025. The IRP also outlines PacifiCorp's plan to be issued.retire or convert to natural gas all coal-fueled resources by 2042.
Requests for Proposals
PacifiCorp issues individual requests for proposals ("RFP")RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.
A draft of the 2020AS RFP was filed for approval with the UPSC and the OPUC in April 2020. In July 2020, the UPSC and the OPUC approved the 2020AS RFP, and PacifiCorp issued the 2020AS2020 All Source RFP to market.the market in July 2020. The 2020AS2020 All Source RFP is seekingsought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. Bids were submittedAn initial shortlist was identified in August 2020, and aOctober 2020. The final shortlist of winning bids will be identified bywas submitted to OPUC in June 2021. The initial shortlist includes a total of 6,982 MWs of new generation and storage capacity. Of the total, 5,652 MWs are new generation resources (represented by 3,173 MWs of solar generation and 2,479 MWs of wind generation) and an additional 1,330 MWs of new battery storage assets, which includes 1,130 MWs of solar collocated battery storage and 200 MWs of stand-alone battery storage. The 2019 IRP preferred portfolio includes 1,823 MWs of solar resources collocatedPacifiCorp will initiate negotiations with 595 MWs of battery energy storage systems and 1,920shortlisted bids that include approximately 1,792 MWs of new wind resources coming onlinecapacity, 1,306 MWs of solar capacity and 697 MWs of battery storage to its portfolio by 2024. PacifiCorp expects that 590 MWs of the end1,792 MWs of 2024. The resources included innew wind capacity will be owned with the IRP are enabled by new transmission investments, including Energy Gateway South, a 400-mile, 500-kV transmission line connecting southeastern Wyoming to northern Utah.remainder of the wind, solar and battery storage capacity being contracted resources.
Contractual Obligations
As of September 30, 2020,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2019.2020.
COVID-19
In March 2020, COVID‑19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by PacifiCorp. While COVID-19 has impacted PacifiCorp's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, all states in which PacifiCorp operates instituted varying levels of "stay-at-home" orders and other measures, requiring non-essential businesses to remain closed, which impacted PacifiCorp's customers and, therefore, their needs and usage patterns for electricity as evidenced by a reduction in consumption due to COVID-19 through September 2020 compared to the same period in 2019. These states have since moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by PacifiCorp related to customer collection activity and suspension of disconnections for non-payment, PacifiCorp has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. Regulatory jurisdictions may allow for deferral or recovery of certain costs incurred in responding to COVID‑19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion. While PacifiCorp does not currently expect a significant increase in employer contributions to its retirement plans, continued market volatility caused by COVID-19 may lead to increased contributions in the future.
PacifiCorp's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system. In response to the effects of COVID‑19, PacifiCorp has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID‑19.
Regulatory Matters
PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, wildfire prevention and mitigation, 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 PacifiCorp'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 the EPA and various federal, state and local agencies. All suchPacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to a range of interpretation whichthat may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws.laws and regulations.
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, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2019.2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2019.
2020.
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
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 Shareholder of
MidAmerican Energy Company
Results of Review of Interim Financial Information
We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2020,2021, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, and of cash flows for the nine-month periods ended September 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 balance sheet of MidAmerican Energy as of December 31, 2019,2020, and the related statements of operations, changes in shareholder's 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 financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2019,2020, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Energy 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
Des Moines, Iowa
November 6, 20205, 2021
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 541 | | | $ | 38 | |
Trade receivables, net | 555 | | | 234 | |
| | | |
Inventories | 244 | | | 278 | |
Other current assets | 142 | | | 73 | |
Total current assets | 1,482 | | | 623 | |
| | | |
Property, plant and equipment, net | 19,773 | | | 19,279 | |
Regulatory assets | 479 | | | 392 | |
Investments and restricted investments | 975 | | | 911 | |
Other assets | 235 | | | 232 | |
| | | |
Total assets | $ | 22,944 | | | $ | 21,437 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 188 |
| | $ | 287 |
|
Trade receivables, net | 303 |
| | 291 |
|
Inventories | 266 |
| | 226 |
|
Other current assets | 70 |
| | 90 |
|
Total current assets | 827 |
| | 894 |
|
| | | |
Property, plant and equipment, net | 19,049 |
| | 18,375 |
|
Regulatory assets | 333 |
| | 289 |
|
Investments and restricted investments | 849 |
| | 818 |
|
Other assets | 210 |
| | 188 |
|
| | | |
Total assets | $ | 21,268 |
| | $ | 20,564 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 347 | | | $ | 408 | |
Accrued interest | 89 | | | 78 | |
Accrued property, income and other taxes | 242 | | | 161 | |
| | | |
| | | |
Other current liabilities | 226 | | | 183 | |
Total current liabilities | 904 | | | 830 | |
| | | |
Long-term debt | 7,716 | | | 7,210 | |
Regulatory liabilities | 943 | | | 1,111 | |
Deferred income taxes | 3,407 | | | 3,054 | |
Asset retirement obligations | 677 | | | 709 | |
Other long-term liabilities | 495 | | | 458 | |
Total liabilities | 14,142 | | | 13,372 | |
| | | |
Commitments and contingencies (Note 9) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 561 | | | 561 | |
Retained earnings | 8,241 | | | 7,504 | |
| | | |
Total shareholder's equity | 8,802 | | | 8,065 | |
| | | |
Total liabilities and shareholder's equity | $ | 22,944 | | | $ | 21,437 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 463 |
| | $ | 519 |
|
Accrued interest | 86 |
| | 78 |
|
Accrued property, income and other taxes | 215 |
| | 225 |
|
Other current liabilities | 170 |
| | 219 |
|
Total current liabilities | 934 |
| | 1,041 |
|
| | | |
Long-term debt | 7,210 |
| | 7,208 |
|
Regulatory liabilities | 1,083 |
| | 1,406 |
|
Deferred income taxes | 2,997 |
| | 2,626 |
|
Asset retirement obligations | 768 |
| | 704 |
|
Other long-term liabilities | 336 |
| | 339 |
|
Total liabilities | 13,328 |
| | 13,324 |
|
| | | |
Commitments and contingencies (Note 8) |
| |
|
| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — |
| | — |
|
Additional paid-in capital | 561 |
| | 561 |
|
Retained earnings | 7,379 |
| | 6,679 |
|
Total shareholder's equity | 7,940 |
| | 7,240 |
|
| | | |
Total liabilities and shareholder's equity | $ | 21,268 |
| | $ | 20,564 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | |
Regulated natural gas and other | 112 | | | 84 | | | 741 | | | 389 | |
Total operating revenue | 966 | | | 812 | | | 2,726 | | | 2,106 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 163 | | | 115 | | | 417 | | | 266 | |
Cost of natural gas purchased for resale and other | 64 | | | 40 | | | 553 | | | 210 | |
Operations and maintenance | 200 | | | 212 | | | 577 | | | 559 | |
Depreciation and amortization | 218 | | | 180 | | | 634 | | | 531 | |
Property and other taxes | 34 | | | 33 | | | 107 | | | 102 | |
Total operating expenses | 679 | | | 580 | | | 2,288 | | | 1,668 | |
| | | | | | | |
Operating income | 287 | | | 232 | | | 438 | | | 438 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (76) | | | (74) | | | (224) | | | (224) | |
Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | |
Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | |
Other, net | 8 | | | 14 | | | 34 | | | 30 | |
Total other income (expense) | (53) | | | (39) | | | (157) | | | (149) | |
| | | | | | | |
Income before income tax benefit | 234 | | | 193 | | | 281 | | | 289 | |
Income tax benefit | (143) | | | (147) | | | (456) | | | (411) | |
| | | | | | | |
Net income | $ | 377 | | | $ | 340 | | | $ | 737 | | | $ | 700 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 728 |
| | $ | 712 |
| | $ | 1,717 |
| | $ | 1,792 |
|
Regulated natural gas and other | 84 |
| | 84 |
| | 389 |
| | 505 |
|
Total operating revenue | 812 |
| | 796 |
| | 2,106 |
| | 2,297 |
|
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 115 |
| | 113 |
| | 266 |
| | 318 |
|
Cost of natural gas purchased for resale and other | 40 |
| | 45 |
| | 210 |
| | 302 |
|
Operations and maintenance | 212 |
| | 189 |
| | 559 |
| | 600 |
|
Depreciation and amortization | 180 |
| | 184 |
| | 531 |
| | 540 |
|
Property and other taxes | 33 |
| | 31 |
| | 102 |
| | 94 |
|
Total operating expenses | 580 |
| | 562 |
| | 1,668 |
| | 1,854 |
|
| | | | | | | |
Operating income | 232 |
| | 234 |
| | 438 |
| | 443 |
|
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (74 | ) | | (68 | ) | | (224 | ) | | (207 | ) |
Allowance for borrowed funds | 5 |
| | 7 |
| | 12 |
| | 20 |
|
Allowance for equity funds | 16 |
| | 27 |
| | 33 |
| | 59 |
|
Other, net | 14 |
| | 4 |
| | 30 |
| | 34 |
|
Total other income (expense) | (39 | ) | | (30 | ) | | (149 | ) | | (94 | ) |
| | | | | | | |
Income before income tax benefit | 193 |
| | 204 |
| | 289 |
| | 349 |
|
Income tax benefit | (147 | ) | | (78 | ) | | (411 | ) | | (282 | ) |
| | | | | | | |
Net income | $ | 340 |
| | $ | 282 |
| | $ | 700 |
| | $ | 631 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid-in Capital | | Retained Earnings | | Total Shareholder's Equity |
| | | | | | | |
Balance, June 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,039 | | | $ | 7,600 | |
Net income | — | | | — | | | 340 | | | 340 | |
| | | | | | | |
Balance, September 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,379 | | | $ | 7,940 | |
| | | | | | | |
Balance, December 31, 2019 | $ | — | | | $ | 561 | | | $ | 6,679 | | | $ | 7,240 | |
Net income | — | | | — | | | 700 | | | 700 | |
| | | | | | | |
Balance, September 30, 2020 | $ | — | | | $ | 561 | | | $ | 7,379 | | | $ | 7,940 | |
| | | | | | | |
Balance, June 30, 2021 | $ | — | | | $ | 561 | | | $ | 7,865 | | | $ | 8,426 | |
Net income | — | | | — | | | 377 | | | 377 | |
Other equity transactions | — | | | — | | | (1) | | | (1) | |
Balance, September 30, 2021 | $ | — | | | $ | 561 | | | $ | 8,241 | | | $ | 8,802 | |
| | | | | | | |
Balance, December 31, 2020 | $ | — | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | |
Net income | — | | | — | | | 737 | | | 737 | |
| | | | | | | |
Balance, September 30, 2021 | $ | — | | | $ | 561 | | | $ | 8,241 | | | $ | 8,802 | |
|
| | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid-in Capital | | Retained Earnings | | Total Shareholder's Equity |
| | | | | | | |
Balance, June 30, 2019 | $ | — |
| | $ | 561 |
| | $ | 6,234 |
| | $ | 6,795 |
|
Net income | — |
| | — |
| | 282 |
| | 282 |
|
Balance, September 30, 2019 | $ | — |
| | $ | 561 |
| | $ | 6,516 |
| | $ | 7,077 |
|
| | | | | | | |
Balance, December 31, 2018 | $ | — |
| | $ | 561 |
| | $ | 5,885 |
| | $ | 6,446 |
|
Net income | — |
| | — |
| | 631 |
| | 631 |
|
Balance, September 30, 2019 | $ | — |
| | $ | 561 |
| | $ | 6,516 |
| | $ | 7,077 |
|
| | | | | | | |
Balance, June 30, 2020 | $ | — |
| | $ | 561 |
| | $ | 7,039 |
| | $ | 7,600 |
|
Net income | — |
| | — |
| | 340 |
| | 340 |
|
Balance, September 30, 2020 | $ | — |
| | $ | 561 |
| | $ | 7,379 |
| | $ | 7,940 |
|
| | | | | | | |
Balance, December 31, 2019 | $ | — |
| | $ | 561 |
| | $ | 6,679 |
| | $ | 7,240 |
|
Net income | — |
| | — |
| | 700 |
| | 700 |
|
Balance, September 30, 2020 | $ | — |
| | $ | 561 |
| | $ | 7,379 |
| | $ | 7,940 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 737 | | | $ | 700 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 634 | | | 531 | |
Amortization of utility plant to other operating expenses | 26 | | | 25 | |
Allowance for equity funds | (25) | | | (33) | |
Deferred income taxes and investment tax credits, net | 121 | | | 76 | |
Settlements of asset retirement obligations | (51) | | | (55) | |
Other, net | 42 | | | (1) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (331) | | | (15) | |
Inventories | 34 | | | (40) | |
| | | |
Pension and other postretirement benefit plans | 2 | | | (17) | |
Accrued property, income and other taxes, net | 80 | | | (10) | |
Accounts payable and other liabilities | 21 | | | 48 | |
Net cash flows from operating activities | 1,290 | | | 1,209 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (1,266) | | | (1,341) | |
Purchases of marketable securities | (166) | | | (251) | |
Proceeds from sales of marketable securities | 163 | | | 244 | |
Other, net | (7) | | | 9 | |
Net cash flows from investing activities | (1,276) | | | (1,339) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Proceeds from long-term debt | 492 | | | — | |
Repayments of long-term debt | (1) | | | — | |
| | | |
Other, net | (2) | | | (1) | |
Net cash flows from financing activities | 489 | | | (1) | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 503 | | | (131) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 45 | | | 330 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 548 | | | $ | 199 | |
|
| | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2020 | | 2019 |
Cash flows from operating activities: | | | |
Net income | $ | 700 |
| | $ | 631 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 531 |
| | 540 |
|
Amortization of utility plant to other operating expenses | 25 |
| | 25 |
|
Allowance for equity funds | (33 | ) | | (59 | ) |
Deferred income taxes and amortization of investment tax credits | 76 |
| | 31 |
|
Other, net | (56 | ) | | 16 |
|
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (15 | ) | | (1 | ) |
Inventories | (40 | ) | | 3 |
|
Pension and other postretirement benefit plans | (17 | ) | | (9 | ) |
Accrued property, income and other taxes, net | (10 | ) | | (28 | ) |
Accounts payable and other liabilities | 48 |
| | 62 |
|
Net cash flows from operating activities | 1,209 |
| | 1,211 |
|
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (1,341 | ) | | (1,909 | ) |
Purchases of marketable securities | (251 | ) | | (139 | ) |
Proceeds from sales of marketable securities | 244 |
| | 126 |
|
Other, net | 9 |
| | 19 |
|
Net cash flows from investing activities | (1,339 | ) | | (1,903 | ) |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | — |
| | 1,460 |
|
Repayments of long-term debt | — |
| | (500 | ) |
Net repayments of short-term debt | — |
| | (240 | ) |
Other, net | (1 | ) | | — |
|
Net cash flows from financing activities | (1 | ) | | 720 |
|
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (131 | ) | | 28 |
|
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 330 |
| | 56 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 199 |
| | $ | 84 |
|
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
(1) General
MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is 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 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 Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2020,2021, and for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The results of operations for the three- and nine-month periods ended September 30, 2020,2021, are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited 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 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 Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2019,2020, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.2021.
Coronavirus Disease 2019 ("COVID-19")
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of MidAmerican Energy's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted MidAmerican Energy's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue and higher bad debt expense. The duration and extent of COVID-19 and its future impact on MidAmerican Energy's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of MidAmerican Energy's unaudited Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to MidAmerican Energy and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.
In May 2020, the Iowa Utilities Board ("IUB") issued an order authorizing MidAmerican Energy to use a regulatory asset account to track increased costs and other financial impacts, including changes in revenue, associated with COVID-19. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when, or if, it will seek recovery of such costs with the IUB.
| |
(2) | Cash and Cash Equivalents and Restricted Cash and Cash Equivalents |
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 as of September 30, 20202021 and December 31, 2019,2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2019, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements.preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 20202021 and December 31, 2019,2020, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 541 | | | $ | 38 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 548 | | | $ | 45 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
| | | |
Cash and cash equivalents | $ | 188 |
| | $ | 287 |
|
Restricted cash and cash equivalents in other current assets | 11 |
| | 43 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 199 |
| | $ | 330 |
|
(3) Property, Plant and Equipment, Net
| |
(3) | Property, Plant and Equipment, Net |
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility plant in service, net: | | | | | |
Generation | 20-70 years | | $ | 17,162 | | | $ | 16,980 | |
Transmission | 52-75 years | | 2,415 | | | 2,365 | |
Electric distribution | 20-75 years | | 4,522 | | | 4,369 | |
Natural gas distribution | 29-75 years | | 2,011 | | | 1,955 | |
Utility plant in service | | | 26,110 | | | 25,669 | |
Accumulated depreciation and amortization | | | (7,444) | | | (6,902) | |
Utility plant in service, net | | | 18,666 | | | 18,767 | |
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 | | | 7 | |
Accumulated depreciation and amortization | | | (1) | | | (1) | |
Nonregulated property, net | | | 6 | | | 6 | |
| | | 18,672 | | | 18,773 | |
Construction work-in-progress | | | 1,101 | | | 506 | |
Property, plant and equipment, net | | | $ | 19,773 | | | $ | 19,279 | |
(4) Regulatory Matters
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.
To mitigate the impact to MidAmerican Energy's customers, the Iowa Utilities Board ordered 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, the increased costs and longer recovery period resulted in higher working capital requirements during the nine-month period ended September 30, 2021.
|
| | | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| Depreciable Life | | 2020 | | 2019 |
Utility plant in service, net: | | | | | |
Generation | 20-70 years | | $ | 15,917 |
| | $ | 15,687 |
|
Transmission | 52-75 years | | 2,303 |
| | 2,124 |
|
Electric distribution | 20-75 years | | 4,281 |
| | 4,095 |
|
Natural gas distribution | 29-75 years | | 1,873 |
| | 1,820 |
|
Utility plant in service | | | 24,374 |
| | 23,726 |
|
Accumulated depreciation and amortization | | | (6,584 | ) | | (6,139 | ) |
Utility plant in service, net | | | 17,790 |
| | 17,587 |
|
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 |
| | 7 |
|
Accumulated depreciation and amortization | | | (1 | ) | | (1 | ) |
Nonregulated property, net | | | 6 |
| | 6 |
|
| | | 17,796 |
| | 17,593 |
|
Construction work-in-progress | | | 1,253 |
| | 782 |
|
Property, plant and equipment, net | | | $ | 19,049 |
| | $ | 18,375 |
|
(5) Recent Financing Transactions
Long-Term Debt
| |
(4) | Recent Financing Transactions |
In July 2021, MidAmerican Energy issued $500 million of its 2.70% First Mortgage Bonds due August 2052. MidAmerican Energy used the net proceeds to finance a portion of the capital expenditures, disbursed during the period from July 22, 2019 to September 27, 2019, with respect to investments in its 2,000-megawatt Wind XI project, its 592-megawatt Wind XII project, its 207-megawatt Wind XII Expansion project and the repowering of certain of its existing wind-powered generating facilities, which were previously financed with MidAmerican Energy's general funds.
Credit Facilities
In May 2020,June 2021, MidAmerican Energy terminatedamended and restated its $400existing $900 million unsecured credit facility expiring August 2020in June 2022. The amendment increased the commitment of the lenders to $1.5 billion, extended the expiration date to June 2024 and entered into aincreased the available maturity extension options to an unlimited number, subject to consent of the lenders. Additionally, in June 2021, MidAmerican Energy terminated its existing $600 million unsecured credit facility which expires May 2021, with an option to extend for up to three months, and has a variable rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. The facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.expiring in August 2021.
(6) Income Taxes
A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (44) | | | (55) | | | (143) | | | (122) | |
State income tax, net of federal income tax impacts | (26) | | | (27) | | | (27) | | | (29) | |
Effects of ratemaking | (12) | | | (15) | | | (13) | | | (13) | |
Other, net | — | | | — | | | — | | | 1 | |
Effective income tax rate | (61) | % | | (76) | % | | (162) | % | | (142) | % |
|
| | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (55 | ) | | (35 | ) | | (122 | ) | | (75 | ) |
State income tax, net of federal income tax benefit | (27 | ) | | (18 | ) | | (29 | ) | | (19 | ) |
Effects of ratemaking | (15 | ) | | (7 | ) | | (13 | ) | | (7 | ) |
Other, net | — |
| | 1 |
| | 1 |
| | (1 | ) |
Effective income tax rate | (76 | )% | | (38 | )% | | (142 | )% | | (81 | )% |
Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended September 30, 2021 and 2020 totaled $103 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. BHE madeMidAmerican Energy received net cash payments for income tax to MidAmerican Energyfrom BHE totaling $500$677 million and $309$500 million for the nine-month periods ended September 30, 20202021 and 2019,2020, respectively.
| |
(6) | Employee Benefit Plans |
(7) Employee Benefit Plans
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.
Net periodic benefit creditcost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | $ | 5 | | | $ | 2 | | | $ | 15 | | | $ | 4 | |
Interest cost | 6 | | | 7 | | | 17 | | | 19 | |
Expected return on plan assets | (9) | | | (10) | | | (28) | | | (30) | |
Net amortization | — | | | — | | | 1 | | | 1 | |
Net periodic benefit cost (credit) | $ | 2 | | | $ | (1) | | | $ | 5 | | | $ | (6) | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | $ | 2 | | | $ | 1 | | | $ | 6 | | | $ | 3 | |
Interest cost | 2 | | | 2 | | | 6 | | | 5 | |
Expected return on plan assets | (2) | | | (4) | | | (7) | | | (10) | |
Net amortization | (1) | | | (1) | | | (3) | | | (4) | |
Net periodic benefit cost (credit) | $ | 1 | | | $ | (2) | | | $ | 2 | | | $ | (6) | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Pension: | | | | | | | |
Service cost | $ | 2 |
| | $ | 2 |
| | $ | 4 |
| | $ | 5 |
|
Interest cost | 7 |
| | 7 |
| | 19 |
| | 22 |
|
Expected return on plan assets | (10 | ) | | (10 | ) | | (30 | ) | | (31 | ) |
Net amortization | — |
| | — |
| | 1 |
| | — |
|
Net periodic benefit credit | $ | (1 | ) | | $ | (1 | ) | | $ | (6 | ) | | $ | (4 | ) |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | $ | 1 |
| | $ | 1 |
| | $ | 3 |
| | $ | 4 |
|
Interest cost | 2 |
| | 2 |
| | 5 |
| | 7 |
|
Expected return on plan assets | (4 | ) | | (3 | ) | | (10 | ) | | (9 | ) |
Net amortization | (1 | ) | | (1 | ) | | (4 | ) | | (3 | ) |
Net periodic benefit credit | $ | (2 | ) | | $ | (1 | ) | | $ | (6 | ) | | $ | (1 | ) |
Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $1$12 million, respectively, during 2020.2021. As of September 30, 2020,2021, $5 million and $1$9 million of contributions had been made to the pension and other postretirement benefit plans, respectively.
| |
(7) | Fair Value Measurements |
(8) Fair Value Measurements
The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.
The following table presents MidAmerican Energy's financial assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of September 30, 2021: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | 1 | | | $ | 70 | | | $ | 4 | | | $ | (7) | | | $ | 68 | |
Money market mutual funds | | 543 | | | — | | | — | | | — | | | 543 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 228 | | | — | | | — | | | — | | | 228 | |
International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Corporate obligations | | — | | | 86 | | | — | | | — | | | 86 | |
Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
Equity securities: | | | | | | | | | | |
United States companies | | 398 | | | — | | | — | | | — | | | 398 | |
International companies | | 8 | | | — | | | — | | | — | | | 8 | |
Investment funds | | 23 | | | — | | | — | | | — | | | 23 | |
| | $ | 1,201 | | | $ | 162 | | | $ | 4 | | | $ | (7) | | | $ | 1,360 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | (2) | | | $ | (5) | | | $ | (4) | | | $ | 7 | | | $ | (4) | |
| | | | | | | | | | | | | | Input Levels for Fair Value Measurements | |
| | Input Levels for Fair Value Measurements | | | | | | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total | |
As of September 30, 2020: | | | | | | | | | | | |
As of December 31, 2020: | | As of December 31, 2020: | | | | | | | | | | |
Assets: | | | | | | | | | | | Assets: | |
Commodity derivatives | | $ | — |
| | $ | 11 |
| | $ | 3 |
| | $ | (2 | ) | | $ | 12 |
| Commodity derivatives | | $ | — | | | $ | 4 | | | $ | 5 | | | $ | (5) | | | $ | 4 | |
Money market mutual funds(2) | | 194 |
| | — |
| | — |
| | — |
| | 194 |
| |
Money market mutual funds | | Money market mutual funds | | 41 | | | — | | | — | | | — | | | 41 | |
Debt securities: | | | | | | | | | | | Debt securities: | |
United States government obligations | | 186 |
| | — |
| | — |
| | — |
| | 186 |
| United States government obligations | | 200 | | | — | | | — | | | — | | | 200 | |
International government obligations | | — |
| | 5 |
| | — |
| | — |
| | 5 |
| International government obligations | | — | | | 5 | | | — | | | — | | | 5 | |
Corporate obligations | | — |
| | 75 |
| | — |
| | — |
| | 75 |
| Corporate obligations | | — | | | 73 | | | — | | | — | | | 73 | |
Municipal obligations | | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Municipal obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | — |
| | 5 |
| | — |
| | — |
| | 5 |
| Agency, asset and mortgage-backed obligations | | — | | | 6 | | | — | | | — | | | 6 | |
Equity securities: | | | | | | | | | | | Equity securities: | |
United States companies | | 347 |
| | — |
| | — |
| | — |
| | 347 |
| United States companies | | 381 | | | — | | | — | | | — | | | 381 | |
International companies | | 8 |
| | — |
| | — |
| | — |
| | 8 |
| International companies | | 9 | | | — | | | — | | | — | | | 9 | |
Investment funds | | 21 |
| | — |
| | — |
| | — |
| | 21 |
| Investment funds | | 17 | | | — | | | — | | | — | | | 17 | |
| | $ | 756 |
| | $ | 100 |
| | $ | 3 |
| | $ | (2 | ) | | $ | 857 |
| | $ | 648 | | | $ | 90 | | | $ | 5 | | | $ | (5) | | | $ | 738 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — |
| | $ | (3 | ) | | $ | (1 | ) | | $ | 3 |
| | $ | (1 | ) | Liabilities - commodity derivatives | | $ | — | | | $ | (4) | | | $ | (3) | | | $ | 5 | | | $ | (2) | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2019: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — |
| | $ | 2 |
| | $ | 1 |
| | $ | (1 | ) | | $ | 2 |
|
Money market mutual funds(2) | | 274 |
| | — |
| | — |
| | — |
| | 274 |
|
Debt securities: | | | | | | | | | | |
United States government obligations | | 189 |
| | — |
| | — |
| | — |
| | 189 |
|
International government obligations | | — |
| | 4 |
| | — |
| | — |
| | 4 |
|
Corporate obligations | | — |
| | 58 |
| | — |
| | — |
| | 58 |
|
Municipal obligations | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Agency, asset and mortgage-backed obligations | | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Equity securities: | | | | | | | | | | |
United States companies | | 336 |
| | — |
| | — |
| | — |
| | 336 |
|
International companies | | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
Investment funds | | 15 |
| | — |
| | — |
| | — |
| | 15 |
|
| | $ | 823 |
| | $ | 66 |
| | $ | 1 |
| | $ | (1 | ) | | $ | 889 |
|
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — |
| | $ | (9 | ) | | $ | — |
| | $ | 2 |
| | $ | (7 | ) |
| |
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $1 million as of September 30, 2020 and December 31, 2019, respectively. |
| |
(2) | Amounts are included in cash and cash equivalents and investments and restricted investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost. |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million as of September 30, 2021 and December 31, 2020, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,716 | | | $ | 9,101 | | | $ | 7,210 | | | $ | 9,130 | |
|
| | | | | | | | | | | | | | | |
| As of September 30, 2020 | | As of December 31, 2019 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,210 |
| | $ | 8,975 |
| | $ | 7,208 |
| | $ | 8,283 |
|
(9) Commitments and Contingencies
| |
(8) | Commitments and Contingencies |
Construction Commitments
During the nine-month period ended September 30, 2020,2021, MidAmerican Energy entered into firm construction commitments totaling $274$405 million forthrough the remainder of 2020 through 2021 substantiallyand 2022 related to the repowering and construction of wind-powered generating facilities in Iowa.and the construction of solar-powered generating facilities.
Easements
During the nine-month period ended September 30, 2020,2021, MidAmerican Energy entered into non-cancelable easements with minimum payment commitments totaling $102$87 million through 20602061 for land in Iowa on which some of its wind-poweredwind- and solar-powered generating facilities will be located.
Maintenance and Service Contracts
During the nine-month period ended September 30, 2020, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $75 million through 2031.
Legal Matters
MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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 its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Transmission Rates
MidAmerican Energy's wholesale transmission rates are set annually using FERC-approvedFederal Energy Regulatory Commission ("FERC")-approved formula rates subject to true-up for actual cost of service. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the approved base return on equity ("ROE") effective January 2015. Prior to September 2016, the rates in effect were based on a 12.38% ROE. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. In November 2019, the FERC issued an order addressing the second complaint and issues on appeal in the first complaint. The order established a ROE of 9.88% (10.38% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 forward. In May 2020, the FERC issued an order on rehearing of the November 2019 order. The May 2020 order affirmed the FERC's prior decision to dismiss the second complaint and established an ROE of 10.02% (10.52% including the 0.50% adder) for the 15-month refund period of the first complaint and prospectively from September 2016 to the date of the May 2020 order. These orders continue to be subject to judicial appeal. MidAmerican Energy cannot predict the ultimate outcome of these matters and, as of September 30, 2020,2021, has accrued an $11a $9 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.
96
| |
(9) | Revenue from Contracts with Customers |
(10) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, andwith further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10,11 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Three-Month Period Ended September 30, 2021 | | For the Nine-Month Period Ended September 30, 2021 |
| Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | $ | 255 | | | $ | 52 | | | $ | — | | | $ | 307 | | | $ | 586 | | | $ | 419 | | | $ | — | | | $ | 1,005 | |
Commercial | 107 | | | 17 | | | — | | | 124 | | | 258 | | | 164 | | | — | | | 422 | |
Industrial | 321 | | | 5 | | | — | | | 326 | | | 741 | | | 20 | | | — | | | 761 | |
Natural gas transportation services | — | | | 9 | | | — | | | 9 | | | — | | | 28 | | | — | | | 28 | |
Other retail(1) | 53 | | | 1 | | | — | | | 54 | | | 119 | | | 2 | | | — | | | 121 | |
Total retail | 736 | | | 84 | | | — | | | 820 | | | 1,704 | | | 633 | | | — | | | 2,337 | |
Wholesale | 88 | | | 25 | | | — | | | 113 | | | 214 | | | 93 | | | — | | | 307 | |
Multi-value transmission projects | 15 | | | — | | | — | | | 15 | | | 45 | | | — | | | — | | | 45 | |
Other Customer Revenue | — | | | — | | | 2 | | | 2 | | | — | | | — | | | 13 | | | 13 | |
Total Customer Revenue | 839 | | | 109 | | | 2 | | | 950 | | | 1,963 | | | 726 | | | 13 | | | 2,702 | |
Other revenue | 15 | | | 1 | | | — | | | 16 | | | 22 | | | 2 | | | — | | | 24 | |
Total operating revenue | $ | 854 | | | $ | 110 | | | $ | 2 | | | $ | 966 | | | $ | 1,985 | | | $ | 728 | | | $ | 13 | | | $ | 2,726 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Three-Month Period Ended September 30, 2020 | | For the Nine-Month Period Ended September 30, 2020 |
| Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | $ | 241 | | | $ | 46 | | | $ | — | | | $ | 287 | | | $ | 555 | | | $ | 233 | | | $ | — | | | $ | 788 | |
Commercial | 99 | | | 13 | | | — | | | 112 | | | 242 | | | 71 | | | — | | | 313 | |
Industrial | 280 | | | 2 | | | — | | | 282 | | | 640 | | | 9 | | | — | | | 649 | |
Natural gas transportation services | — | | | 8 | | | — | | | 8 | | | — | | | 26 | | | — | | | 26 | |
Other retail(1) | 42 | | | 1 | | | — | | | 43 | | | 103 | | | 2 | | | — | | | 105 | |
Total retail | 662 | | | 70 | | | — | | | 732 | | | 1,540 | | | 341 | | | — | | | 1,881 | |
Wholesale | 46 | | | 10 | | | — | | | 56 | | | 116 | | | 41 | | | — | | | 157 | |
Multi-value transmission projects | 14 | | | — | | | — | | | 14 | | | 47 | | | — | | | — | | | 47 | |
Other Customer Revenue | — | | | — | | | 4 | | | 4 | | | — | | | — | | | 5 | | | 5 | |
Total Customer Revenue | 722 | | | 80 | | | 4 | | | 806 | | | 1,703 | | | 382 | | | 5 | | | 2,090 | |
Other revenue | 6 | | | — | | | — | | | 6 | | | 14 | | | 2 | | | — | | | 16 | |
Total operating revenue | $ | 728 | | | $ | 80 | | | $ | 4 | | | $ | 812 | | | $ | 1,717 | | | $ | 384 | | | $ | 5 | | | $ | 2,106 | |
(1) Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Three-Month Period Ended September 30, 2019 | | For the Nine-Month Period Ended September 30, 2019 |
| Electric | | Natural Gas | | Other | | Total | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | $ | 228 |
| | $ | 41 |
| | $ | — |
| | $ | 269 |
| | $ | 547 |
| | $ | 282 |
| | $ | — |
| | $ | 829 |
|
Commercial | 101 |
| | 10 |
| | — |
| | 111 |
| | 255 |
| | 95 |
| | — |
| | 350 |
|
Industrial | 274 |
| | 3 |
| | — |
| | 277 |
| | 641 |
| | 12 |
| | — |
| | 653 |
|
Natural gas transportation services | — |
| | 7 |
| | — |
| | 7 |
| | — |
| | 27 |
| | — |
| | 27 |
|
Other retail(1) | 48 |
| | — |
| | — |
| | 48 |
| | 118 |
| | — |
| | — |
| | 118 |
|
Total retail | 651 |
| | 61 |
| | — |
| | 712 |
| | 1,561 |
| | 416 |
| | — |
| | 1,977 |
|
Wholesale | 41 |
| | 15 |
| | — |
| | 56 |
| | 168 |
| | 64 |
| | — |
| | 232 |
|
Multi-value transmission projects | 17 |
| | — |
| | — |
| | 17 |
| | 47 |
| | — |
| | — |
| | 47 |
|
Other Customer Revenue | — |
| | — |
| | 8 |
| | 8 |
| | — |
| | — |
| | 23 |
| | 23 |
|
Total Customer Revenue | 709 |
| | 76 |
| | 8 |
| | 793 |
| | 1,776 |
| | 480 |
| | 23 |
| | 2,279 |
|
Other revenue | 3 |
| | — |
| | — |
| | 3 |
| | 16 |
| | 2 |
| | — |
| | 18 |
|
Total operating revenue | $ | 712 |
| | $ | 76 |
| | $ | 8 |
| | $ | 796 |
| | $ | 1,792 |
| | $ | 482 |
| | $ | 23 |
| | $ | 2,297 |
|
| |
(1) | Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding. |
(11) Segment Information
MidAmerican Energy has identified two2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | |
Regulated natural gas | 110 | | | 80 | | | 728 | | | 384 | |
Other | 2 | | | 4 | | | 13 | | | 5 | |
Total operating revenue | $ | 966 | | | $ | 812 | | | $ | 2,726 | | | $ | 2,106 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 289 | | | $ | 238 | | | $ | 401 | | | $ | 398 | |
Regulated natural gas | (2) | | | (6) | | | 37 | | | 40 | |
| | | | | | | |
Total operating income | 287 | | | 232 | | | 438 | | | 438 | |
Interest expense | (76) | | | (74) | | | (224) | | | (224) | |
Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | |
Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | |
Other, net | 8 | | | 14 | | | 34 | | | 30 | |
Income before income tax benefit | $ | 234 | | | $ | 193 | | | $ | 281 | | | $ | 289 | |
| | | | | | | | | | | |
| As of |
| September 30, 2021 | | December 31, 2020 |
Assets: | | | |
Regulated electric | $ | 21,063 | | | $ | 19,892 | |
Regulated natural gas | 1,874 | | | 1,544 | |
Other | 7 | | | 1 | |
Total assets | $ | 22,944 | | | $ | 21,437 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 728 |
| | $ | 712 |
| | $ | 1,717 |
| | $ | 1,792 |
|
Regulated natural gas | 80 |
| | 76 |
| | 384 |
| | 482 |
|
Other | 4 |
| | 8 |
| | 5 |
| | 23 |
|
Total operating revenue | $ | 812 |
| | $ | 796 |
| | $ | 2,106 |
| | $ | 2,297 |
|
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 238 |
| | $ | 243 |
| | $ | 398 |
| | $ | 396 |
|
Regulated natural gas | (6 | ) | | (8 | ) | | 40 |
| | 45 |
|
Other | — |
| | (1 | ) | | — |
| | 2 |
|
Total operating income | 232 |
| | 234 |
| | 438 |
| | 443 |
|
Interest expense | (74 | ) | | (68 | ) | | (224 | ) | | (207 | ) |
Allowance for borrowed funds | 5 |
| | 7 |
| | 12 |
| | 20 |
|
Allowance for equity funds | 16 |
| | 27 |
| | 33 |
| | 59 |
|
Other, net | 14 |
| | 4 |
| | 30 |
| | 34 |
|
Income before income tax benefit | $ | 193 |
| | $ | 204 |
| | $ | 289 |
| | $ | 349 |
|
|
| | | | | | | |
| As of |
| September 30, 2020 | | December 31, 2019 |
Assets: | | | |
Regulated electric | $ | 19,782 |
| | $ | 19,093 |
|
Regulated natural gas | 1,479 |
| | 1,468 |
|
Other | 7 |
| | 3 |
|
Total assets | $ | 21,268 |
| | $ | 20,564 |
|
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2020,2021, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, and of cash flows for the nine-month periods ended September 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) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2019,2020, and the related consolidated statements of operations, changes in member's 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 MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding 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 and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. 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 and with auditing standards generally accepted in the United States of America, 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
Des Moines, Iowa
November 6, 20205, 2021
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 542 | | | $ | 39 | |
Trade receivables, net | 555 | | | 234 | |
| | | |
Inventories | 244 | | | 278 | |
Other current assets | 143 | | | 74 | |
Total current assets | 1,484 | | | 625 | |
| | | |
Property, plant and equipment, net | 19,774 | | | 19,279 | |
Goodwill | 1,270 | | | 1,270 | |
Regulatory assets | 479 | | | 392 | |
Investments and restricted investments | 977 | | | 913 | |
Other assets | 234 | | | 232 | |
| | | |
Total assets | $ | 24,218 | | | $ | 22,711 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 193 |
| | $ | 288 |
|
Trade receivables, net | 303 |
| | 291 |
|
Inventories | 266 |
| | 226 |
|
Other current assets | 73 |
| | 91 |
|
Total current assets | 835 |
| | 896 |
|
| | | |
Property, plant and equipment, net | 19,049 |
| | 18,377 |
|
Goodwill | 1,270 |
| | 1,270 |
|
Regulatory assets | 333 |
| | 289 |
|
Investments and restricted investments | 851 |
| | 820 |
|
Other assets | 210 |
| | 188 |
|
| | | |
Total assets | $ | 22,548 |
| | $ | 21,840 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 347 | | | $ | 408 | |
Accrued interest | 90 | | | 83 | |
Accrued property, income and other taxes | 242 | | | 161 | |
Note payable to affiliate | 190 | | | 177 | |
| | | |
| | | |
Other current liabilities | 226 | | | 183 | |
Total current liabilities | 1,095 | | | 1,012 | |
| | | |
Long-term debt | 7,956 | | | 7,450 | |
Regulatory liabilities | 943 | | | 1,111 | |
Deferred income taxes | 3,405 | | | 3,052 | |
Asset retirement obligations | 677 | | | 709 | |
Other long-term liabilities | 495 | | | 458 | |
Total liabilities | 14,571 | | | 13,792 | |
| | | |
Commitments and contingencies (Note 9) | 0 | | 0 |
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 | | | 1,679 | |
Retained earnings | 7,968 | | | 7,240 | |
| | | |
Total member's equity | 9,647 | | | 8,919 | |
| | | |
Total liabilities and member's equity | $ | 24,218 | | | $ | 22,711 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 463 |
| | $ | 520 |
|
Accrued interest | 87 |
| | 84 |
|
Accrued property, income and other taxes | 215 |
| | 226 |
|
Note payable to affiliate | 184 |
| | 171 |
|
Other current liabilities | 171 |
| | 219 |
|
Total current liabilities | 1,120 |
| | 1,220 |
|
| | | |
Long-term debt | 7,450 |
| | 7,448 |
|
Regulatory liabilities | 1,083 |
| | 1,406 |
|
Deferred income taxes | 2,995 |
| | 2,621 |
|
Asset retirement obligations | 768 |
| | 704 |
|
Other long-term liabilities | 336 |
| | 340 |
|
Total liabilities | 13,752 |
| | 13,739 |
|
| | | |
Commitments and contingencies (Note 8) |
| |
|
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 |
| | 1,679 |
|
Retained earnings | 7,117 |
| | 6,422 |
|
Total member's equity | 8,796 |
| | 8,101 |
|
| | | |
Total liabilities and member's equity | $ | 22,548 |
| | $ | 21,840 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | |
Regulated natural gas and other | 112 | | | 84 | | | 741 | | | 397 | |
Total operating revenue | 966 | | | 812 | | | 2,726 | | | 2,114 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 163 | | | 115 | | | 417 | | | 266 | |
Cost of natural gas purchased for resale and other | 64 | | | 40 | | | 553 | | | 211 | |
Operations and maintenance | 200 | | | 212 | | | 577 | | | 560 | |
Depreciation and amortization | 218 | | | 180 | | | 634 | | | 531 | |
Property and other taxes | 34 | | | 33 | | | 107 | | | 102 | |
Total operating expenses | 679 | | | 580 | | | 2,288 | | | 1,670 | |
| | | | | | | |
Operating income | 287 | | | 232 | | | 438 | | | 444 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (81) | | | (79) | | | (237) | | | (238) | |
Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | |
Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | |
Other, net | 8 | | | 15 | | | 34 | | | 30 | |
Total other income (expense) | (58) | | | (43) | | | (170) | | | (163) | |
| | | | | | | |
Income before income tax benefit | 229 | | | 189 | | | 268 | | | 281 | |
Income tax benefit | (144) | | | (148) | | | (460) | | | (414) | |
| | | | | | | |
Net income | $ | 373 | | | $ | 337 | | | $ | 728 | | | $ | 695 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 728 |
| | $ | 712 |
| | $ | 1,717 |
| | $ | 1,792 |
|
Regulated natural gas and other | 84 |
| | 85 |
| | 397 |
| | 507 |
|
Total operating revenue | 812 |
| | 797 |
| | 2,114 |
| | 2,299 |
|
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 115 |
| | 113 |
| | 266 |
| | 318 |
|
Cost of natural gas purchased for resale and other | 40 |
| | 45 |
| | 211 |
| | 301 |
|
Operations and maintenance | 212 |
| | 190 |
| | 560 |
| | 602 |
|
Depreciation and amortization | 180 |
| | 184 |
| | 531 |
| | 540 |
|
Property and other taxes | 33 |
| | 31 |
| | 102 |
| | 94 |
|
Total operating expenses | 580 |
| | 563 |
| | 1,670 |
| | 1,855 |
|
| | | | | | | |
Operating income | 232 |
| | 234 |
| | 444 |
| | 444 |
|
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (79 | ) | | (74 | ) | | (238 | ) | | (223 | ) |
Allowance for borrowed funds | 5 |
| | 7 |
| | 12 |
| | 20 |
|
Allowance for equity funds | 16 |
| | 27 |
| | 33 |
| | 59 |
|
Other, net | 15 |
| | 5 |
| | 30 |
| | 36 |
|
Total other income (expense) | (43 | ) | | (35 | ) | | (163 | ) | | (108 | ) |
| | | | | | | |
Income before income tax benefit | 189 |
| | 199 |
| | 281 |
| | 336 |
|
Income tax benefit | (148 | ) | | (80 | ) | | (414 | ) | | (286 | ) |
| | | | | | | |
Net income | $ | 337 |
| | $ | 279 |
| | $ | 695 |
| | $ | 622 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | |
| Paid-in Capital | | Retained Earnings | | Total Member's Equity |
| | | | | |
Balance, June 30, 2020 | $ | 1,679 | | | $ | 6,780 | | | $ | 8,459 | |
Net income | — | | | 337 | | | 337 | |
| | | | | |
Balance, September 30, 2020 | $ | 1,679 | | | $ | 7,117 | | | $ | 8,796 | |
| | | | | |
Balance, December 31, 2019 | $ | 1,679 | | | $ | 6,422 | | | $ | 8,101 | |
Net income | — | | | 695 | | | 695 | |
| | | | | |
Balance, September 30, 2020 | $ | 1,679 | | | $ | 7,117 | | | $ | 8,796 | |
| | | | | |
Balance, June 30, 2021 | $ | 1,679 | | | $ | 7,594 | | | $ | 9,273 | |
Net income | — | | | 373 | | | 373 | |
Other equity transactions | — | | | 1 | | | 1 | |
Balance, September 30, 2021 | $ | 1,679 | | | $ | 7,968 | | | $ | 9,647 | |
| | | | | |
Balance, December 31, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | |
Net income | — | | | 728 | | | 728 | |
| | | | | |
Balance, September 30, 2021 | $ | 1,679 | | | $ | 7,968 | | | $ | 9,647 | |
|
| | | | | | | | | | | |
| Paid-in Capital | | Retained Earnings | | Total Member's Equity |
| | | | | |
Balance, June 30, 2019 | $ | 1,679 |
| | $ | 5,993 |
| | $ | 7,672 |
|
Net income | — |
| | 279 |
| | 279 |
|
Balance, September 30, 2019 | $ | 1,679 |
| | $ | 6,272 |
| | $ | 7,951 |
|
| | | | | |
Balance, December 31, 2018 | $ | 1,679 |
| | $ | 5,650 |
| | $ | 7,329 |
|
Net income | — |
| | 622 |
| | 622 |
|
Balance, September 30, 2019 | $ | 1,679 |
| | $ | 6,272 |
| | $ | 7,951 |
|
| | | | | |
Balance, June 30, 2020 | $ | 1,679 |
| | $ | 6,780 |
| | $ | 8,459 |
|
Net income | — |
| | 337 |
| | 337 |
|
Balance, September 30, 2020 | $ | 1,679 |
| | $ | 7,117 |
| | $ | 8,796 |
|
| | | | | |
Balance, December 31, 2019 | $ | 1,679 |
| | $ | 6,422 |
| | $ | 8,101 |
|
Net income | — |
| | 695 |
| | 695 |
|
Balance, September 30, 2020 | $ | 1,679 |
| | $ | 7,117 |
| | $ | 8,796 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 728 | | | $ | 695 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 634 | | | 531 | |
Amortization of utility plant to other operating expenses | 26 | | | 25 | |
Allowance for equity funds | (25) | | | (33) | |
Deferred income taxes and investment tax credits, net | 121 | | | 79 | |
| | | |
Settlements of asset retirement obligations | (51) | | | (55) | |
Other, net | 42 | | | (1) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (331) | | | (16) | |
Inventories | 34 | | | (40) | |
| | | |
Pension and other postretirement benefit plans | 2 | | | (17) | |
Accrued property, income and other taxes, net | 80 | | | (13) | |
Accounts payable and other liabilities | 16 | | | 44 | |
Net cash flows from operating activities | 1,276 | | | 1,199 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (1,266) | | | (1,341) | |
Purchases of marketable securities | (166) | | | (251) | |
Proceeds from sales of marketable securities | 163 | | | 244 | |
| | | |
Other, net | (7) | | | 10 | |
Net cash flows from investing activities | (1,276) | | | (1,338) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Proceeds from long-term debt | 492 | | | — | |
Repayments of long-term debt | (1) | | | — | |
Net change in note payable to affiliate | 13 | | | 13 | |
| | | |
Other, net | (1) | | | (1) | |
Net cash flows from financing activities | 503 | | | 12 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 503 | | | (127) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 46 | | | 331 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 549 | | | $ | 204 | |
|
| | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2020 | | 2019 |
Cash flows from operating activities: | | | |
Net income | $ | 695 |
| | $ | 622 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 531 |
| | 540 |
|
Amortization of utility plant to other operating expenses | 25 |
| | 25 |
|
Allowance for equity funds | (33 | ) | | (59 | ) |
Deferred income taxes and amortization of investment tax credits | 79 |
| | 30 |
|
Other, net | (56 | ) | | 18 |
|
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (16 | ) | | (6 | ) |
Inventories | (40 | ) | | 3 |
|
Pension and other postretirement benefit plans | (17 | ) | | (9 | ) |
Accrued property, income and other taxes, net | (13 | ) | | (28 | ) |
Accounts payable and other liabilities | 44 |
| | 58 |
|
Net cash flows from operating activities | 1,199 |
| | 1,194 |
|
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (1,341 | ) | | (1,909 | ) |
Purchases of marketable securities | (251 | ) | | (139 | ) |
Proceeds from sales of marketable securities | 244 |
| | 126 |
|
Other, net | 10 |
| | 19 |
|
Net cash flows from investing activities | (1,338 | ) | | (1,903 | ) |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | — |
| | 1,460 |
|
Repayments of long-term debt | — |
| | (500 | ) |
Net change in note payable to affiliate | 13 |
| | 17 |
|
Net repayments of short-term debt | — |
| | (240 | ) |
Other, net | (1 | ) | | — |
|
Net cash flows from financing activities | 12 |
| | 737 |
|
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (127 | ) | | 28 |
|
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 331 |
| | 57 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 204 |
| | $ | 85 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is 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"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct, wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.
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 September 30, 2020,2021, and for the three- and nine-month periods ended September 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-month periods ended September 30, 20202021 and 2019.2020. The results of operations for the three- and nine-month periods ended September 30, 2020,2021, 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 MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2019,2020, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.2021.
Coronavirus Disease 2019 ("COVID-19")
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of MidAmerican Energy's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted MidAmerican Funding's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue and higher bad debt expense. The duration and extent of COVID-19 and its future impact on MidAmerican Funding's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of MidAmerican Funding's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets and goodwill for impairment, expected credit losses on amounts owed to MidAmerican Funding and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.
In May 2020, the Iowa Utilities Board ("IUB") issued an order authorizing MidAmerican Energy to use a regulatory asset account to track increased costs and other financial impacts, including changes in revenue, associated with COVID-19. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when, or if, it will seek recovery of such costs with the IUB.
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(2) | Cash and Cash Equivalents and Restricted Cash and Cash Equivalents |
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 as of September 30, 20202021 and December 31, 2019,2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2019, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements.preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 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):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 542 | | | $ | 39 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 549 | | | $ | 46 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
| | | |
Cash and cash equivalents | $ | 193 |
| | $ | 288 |
|
Restricted cash and cash equivalents in other current assets | 11 |
| | 43 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 204 |
| | $ | 331 |
|
(3) Property, Plant and Equipment, Net
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(3) | Property, Plant and Equipment, Net |
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had as of September 30, 2020 and December 31, 2019, nonregulated property gross of $‑million and $3 million, respectively, and related accumulated depreciation and amortization of $- million and $1 million, respectively.
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(4) | Recent Financing Transactions |
(4) Regulatory Matters
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5) Recent Financing Transactions
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(6) Income Taxes
A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (45) | | | (56) | | | (150) | | | (126) | |
State income tax, net of federal income tax impacts | (27) | | | (27) | | | (29) | | | (30) | |
Effects of ratemaking | (12) | | | (16) | | | (14) | | | (13) | |
Other, net | — | | | — | | | — | | | 1 | |
Effective income tax rate | (63) | % | | (78) | % | | (172) | % | | (147) | % |
|
| | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Income tax credits | (56 | ) | | (36 | ) | | (126 | ) | | (78 | ) |
State income tax, net of federal income tax benefit | (27 | ) | | (18 | ) | | (30 | ) | | (20 | ) |
Effects of ratemaking | (16 | ) | | (7 | ) | | (13 | ) | | (7 | ) |
Other, net | — |
| | — |
| | 1 |
| | (1 | ) |
Effective income tax rate | (78 | )% | | (40 | )% | | (147 | )% | | (85 | )% |
Income tax credits relate primarily to production tax credits ("PTCs") from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican EnergyFunding recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended September 30, 2021 and 2020 totaled $103 million and $105 million, respectively, and for the nine-month periods ended September 30, 2021 and 2020 totaled $400 million and $352 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. The timing of MidAmerican Funding's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date. BHE madeMidAmerican Funding received net cash payments for income tax to MidAmerican Fundingfrom BHE totaling $504$681 million and $313$504 million for the nine-month periodperiods ended September 30, 20202021 and 2019,2020, respectively.
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(6) | Employee Benefit Plans |
(7) Employee Benefit Plans
Refer to Note 67 of MidAmerican Energy's Notes to Financial Statements.
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(7) | Fair Value Measurements |
(8) Fair Value Measurements
Refer to Note 78 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,956 | | | $ | 9,417 | | | $ | 7,450 | | | $ | 9,466 | |
(9) Commitments and Contingencies
|
| | | | | | | | | | | | | | | |
| As of September 30, 2020 | | As of December 31, 2019 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,450 |
| | $ | 9,313 |
| | $ | 7,448 |
| | $ | 8,599 |
|
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(8) | Commitments and Contingencies |
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 89 of MidAmerican Energy's Notes to Financial Statements.
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(9) | Revenue from Contracts with Customers |
(10) Revenue from Contracts with Customers
Refer to Note 910 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $- million and $1$— million for the three-month periods ended September 30, 20202021 and 2019,2020, respectively, and $8$— million and $2$8 million for the nine-month periods ended September 30, 20202021 and 2019,2020, respectively.
(11) Segment Information
MidAmerican Funding has identified two2 reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 854 | | | $ | 728 | | | $ | 1,985 | | | $ | 1,717 | |
Regulated natural gas | 110 | | | 80 | | | 728 | | | 384 | |
Other | 2 | | | 4 | | | 13 | | | 13 | |
Total operating revenue | $ | 966 | | | $ | 812 | | | $ | 2,726 | | | $ | 2,114 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 289 | | | $ | 238 | | | $ | 401 | | | $ | 398 | |
Regulated natural gas | (2) | | | (6) | | | 37 | | | 40 | |
Other | — | | | — | | | — | | | 6 | |
Total operating income | 287 | | | 232 | | | 438 | | | 444 | |
Interest expense | (81) | | | (79) | | | (237) | | | (238) | |
Allowance for borrowed funds | 4 | | | 5 | | | 8 | | | 12 | |
Allowance for equity funds | 11 | | | 16 | | | 25 | | | 33 | |
Other, net | 8 | | | 15 | | | 34 | | | 30 | |
Income before income tax benefit | $ | 229 | | | $ | 189 | | | $ | 268 | | | $ | 281 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 728 |
| | $ | 712 |
| | $ | 1,717 |
| | $ | 1,792 |
|
Regulated natural gas | 80 |
| | 76 |
| | 384 |
| | 482 |
|
Other | 4 |
| | 9 |
| | 13 |
| | 25 |
|
Total operating revenue | $ | 812 |
| | $ | 797 |
| | $ | 2,114 |
| | $ | 2,299 |
|
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 238 |
| | $ | 243 |
| | $ | 398 |
| | $ | 396 |
|
Regulated natural gas | (6 | ) | | (8 | ) | | 40 |
| | 45 |
|
Other | — |
| | (1 | ) | | 6 |
| | 3 |
|
Total operating income | 232 |
| | 234 |
| | 444 |
| | 444 |
|
Interest expense | (79 | ) | | (74 | ) | | (238 | ) | | (223 | ) |
Allowance for borrowed funds | 5 |
| | 7 |
| | 12 |
| | 20 |
|
Allowance for equity funds | 16 |
| | 27 |
| | 33 |
| | 59 |
|
Other, net | 15 |
| | 5 |
| | 30 |
| | 36 |
|
Income before income tax benefit | $ | 189 |
| | $ | 199 |
| | $ | 281 |
| | $ | 336 |
|
|
| | | | | | | |
| As of |
| September 30, 2020 | | December 31, 2019 |
Assets(1): | | | |
Regulated electric | $ | 20,973 |
| | $ | 20,284 |
|
Regulated natural gas | 1,558 |
| | 1,547 |
|
Other | 17 |
| | 9 |
|
Total assets | $ | 22,548 |
| | $ | 21,840 |
|
| | | | | | | | | | | |
| As of |
| September 30, 2021 | | December 31, 2020 |
Assets(1): | | | |
Regulated electric | $ | 22,254 | | | $ | 21,083 | |
Regulated natural gas | 1,953 | | | 1,623 | |
Other | 11 | | | 5 | |
Total assets | $ | 24,218 | | | $ | 22,711 | |
|
| | | | |
(1) | Assets by reportable segment reflect the assignment of goodwill to applicable reporting units. |
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Item 2. | Management's Discussion and Analysis of Financial Condition and Results of Operations |
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Months of 20202021 and 20192020
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the third quarter of 20202021 was $340$377 million, an increase of $58$37 million, or 21%11%, compared to 20192020 primarily due to higher electric utility margin of $78 million, lower operations and maintenance expenses of $12 million due to storm restoration costs in 2020 and higher natural gas utility margin of $6 million, partially offset by higher depreciation and amortization expense of $38 million, lower allowance for equity funds used during construction of $5 million due to lower construction work-in-progress balances, unfavorable changes in the cash surrender value of corporate-owned life insurance policies and lower income tax benefit due to higher pretax income. Electric utility margin increased due to higher wholesale utility margin primarily reflecting higher market prices and higher retail utility margin mainly from higher volumes. Depreciation and amortization expense increased due to additional assets placed in-service and the impact of regulatory mechanisms.
MidAmerican Energy's net income for the first nine months of 2021 was $737 million, an increase of $37 million, or 5%, compared to 2020, primarily due to higher electric utility margin of $117 million, a favorable income tax benefit of $69$45 million from higher PTCs recognized of $36 million, which was due to higher wind generation driven by repowering and new wind projects placedfavorable changes in service in 2019, and the effects of ratemaking, higher electric utility margin, and higher cash surrender value of corporate-owned life insurance policies, partially offset by higher depreciation and amortization expense of $103 million, higher operations and maintenance expenses, fromincluding increased costs associated with additional wind-powered generating facilities placed in-service and higher natural gas distribution costs, partially offset by lower electric distribution costs due to storm restoration and the addition of wind turbinescosts in 20192020 and lower allowances for equity and borrowed funds used during construction of $13$12 million. Electric utility margin increased primarily due to higher retail customerutility margin, primarily from higher volumes higher wholesale revenue and higher recoveries through bill riders partially offset by higher generation(offset in operations and purchased power costs. Electric retail customer volumes increased 2.3%, primarily due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercialmaintenance and industrial customer usageincome tax benefit), and higher residential customer usage.
MidAmerican Energy's net income for the first nine months of 2020 was $700 million, an increase of $69 million, or 11%, compared to 2019 primarily due towholesale utility margin from higher wholesale volumes. The favorable income tax benefit of $129 million, largelywas due to higher PTCs recognized of $93 million from higher windwind-powered generation, which was driven primarily by repowering and new wind projects placed in-service in 2019, and the effects of ratemaking, lower operations and maintenance expenses and lower depreciationin-service. Depreciation and amortization expense increased due to additional assets placed in-service and the impact of $9 million, partially offsetregulatory mechanisms.
On October 29, 2021, the IUB issued an order extending for three years the depreciation deferral regulatory mechanism approved by lower allowancesthe IUB in MidAmerican Energy's 2013 electric rate case. In December 2020, the cumulative deferral reached the limit previously set by the IUB, resulting in higher depreciation expense for equitythe third quarter and borrowed funds used during constructionfirst nine months of $342021. With the extension of the deferral, annual depreciation expense will be approximately $50 million lower electric and natural gas utility margins, higher interest expensein years 2021 through 2023 than would have been recognized absent the order. The annual amount of $17 million and higher property and other taxes of $8 million. Electric utility margin decreased due to lower wholesale revenue, the price impacts from changesdeferral for 2021 will be recognized in sales mix and lower recoveries through bill riders, partially offset by higher retail customer volumes and lower generation and purchased power costs. Electric retail customer volumes increased 1.1% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased due to lower energy efficiency program revenue and 10.4% lower retail customer volumes primarily due to the unfavorable impact of weather.fourth quarter.
MidAmerican Funding -
MidAmerican Funding's net income for the third quarter of 20202021 was $337$373 million, an increase of $58$36 million, or 21%11%, compared to 2019.2020. MidAmerican Funding's net income for the first nine months of 20202021 was $695$728 million, an increase of $73$33 million, or 12%5%, compared to 2019.2020. The increasesvariances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 854 | | | $ | 728 | | | $ | 126 | | 17 | % | | $ | 1,985 | | | $ | 1,717 | | | $ | 268 | | 16 | % |
Cost of fuel and energy | | 163 | | | 115 | | | 48 | | 42 | | | 417 | | | 266 | | | 151 | | 57 | |
Electric utility margin | | 691 | | | 613 | | | 78 | | 13 | % | | 1,568 | | | 1,451 | | | 117 | | 8 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 110 | | | 80 | | | 30 | | 38 | % | | 728 | | | 384 | | | 344 | | * |
Natural gas purchased for resale | | 63 | | | 39 | | | 24 | | 62 | | | 552 | | | 209 | | | 343 | | * |
Natural gas utility margin | | 47 | | | 41 | | | 6 | | 15 | % | | 176 | | | 175 | | | 1 | | 1 | % |
| | | | | | | | | | | | | | |
Utility margin | | 738 | | | 654 | | | 84 | | 13 | % | | 1,744 | | | 1,626 | | | 118 | | 7 | % |
| | | | | | | | | | | | | | |
Other operating revenue | | 2 | | | 4 | | | (2) | | (50) | % | | 13 | | | 5 | | | 8 | | * |
Other cost of sales | | 1 | | | 1 | | | — | | — | | | 1 | | | 1 | | | — | | * |
Operations and maintenance | | 200 | | | 212 | | | (12) | | (6) | | | 577 | | | 559 | | | 18 | | 3 | |
Depreciation and amortization | | 218 | | | 180 | | | 38 | | 21 | | | 634 | | | 531 | | | 103 | | 19 | |
Property and other taxes | | 34 | | | 33 | | | 1 | | 3 | | | 107 | | | 102 | | | 5 | | 5 | |
| | | | | | | | | | | | | | |
Operating income | | $ | 287 | | | $ | 232 | | | $ | 55 | | 24 | % | | $ | 438 | | | $ | 438 | | | $ | — | | — | % |
* Not meaningful.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 728 |
| | $ | 712 |
| | $ | 16 |
| 2 | % | | $ | 1,717 |
| | $ | 1,792 |
| | $ | (75 | ) | (4 | )% |
Cost of fuel and energy | | 115 |
| | 113 |
| | 2 |
| 2 |
| | 266 |
| | 318 |
| | (52 | ) | (16 | ) |
Electric utility margin | | 613 |
| | 599 |
| | 14 |
| 2 | % | | 1,451 |
| | 1,474 |
| | (23 | ) | (2 | )% |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 80 |
| | 76 |
| | 4 |
| 5 | % | | 384 |
| | 482 |
| | (98 | ) | (20 | )% |
Natural gas purchased for resale | | 39 |
| | 39 |
| | — |
| — |
| | 209 |
| | 287 |
| | (78 | ) | (27 | ) |
Natural gas utility margin | | 41 |
| | 37 |
| | 4 |
| 11 | % | | 175 |
| | 195 |
| | (20 | ) | (10 | )% |
| | | | | | | | | | | | | | |
Utility margin | | 654 |
| | 636 |
| | 18 |
| 3 | % | | 1,626 |
| | 1,669 |
| | (43 | ) | (3 | )% |
| | | | | | | | | | | | | | |
Other operating revenue | | 4 |
| | 8 |
| | (4 | ) | (50 | ) | | 5 |
| | 23 |
| | (18 | ) | (78 | )% |
Other cost of sales | | 1 |
| | 6 |
| | (5 | ) | (83 | ) | | 1 |
| | 15 |
| | (14 | ) | (93 | ) |
Operations and maintenance | | 212 |
| | 189 |
| | 23 |
| 12 |
| | 559 |
| | 600 |
| | (41 | ) | (7 | ) |
Depreciation and amortization | | 180 |
| | 184 |
| | (4 | ) | (2 | ) | | 531 |
| | 540 |
| | (9 | ) | (2 | ) |
Property and other taxes | | 33 |
| | 31 |
| | 2 |
| 6 |
| | 102 |
| | 94 |
| | 8 |
| 9 |
|
Operating income | | $ | 232 |
| | $ | 234 |
| | $ | (2 | ) | (1 | )% | | $ | 438 |
| | $ | 443 |
| | $ | (5 | ) | (1 | )% |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 854 | | | $ | 728 | | | $ | 126 | | | 17 | % | | $ | 1,985 | | | $ | 1,717 | | | $ | 268 | | | 16 | % |
Cost of fuel and energy | 163 | | | 115 | | | 48 | | | 42 | | | 417 | | | 266 | | | 151 | | | 57 | |
Utility margin | $ | 691 | | | $ | 613 | | | $ | 78 | | | 13 | % | | $ | 1,568 | | | $ | 1,451 | | | $ | 117 | | | 8 | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 2,060 | | | 2,053 | | | 7 | | | — | % | | 5,284 | | | 5,226 | | | 58 | | | 1 | % |
Commercial | 1,039 | | | 1,013 | | | 26 | | | 3 | | | 2,871 | | | 2,800 | | | 71 | | | 3 | |
Industrial | 4,106 | | | 3,758 | | | 348 | | | 9 | | | 11,981 | | | 10,884 | | | 1,097 | | | 10 | |
Other | 423 | | | 398 | | | 25 | | | 6 | | | 1,194 | | | 1,117 | | | 77 | | | 7 | |
Total retail | 7,628 | | | 7,222 | | | 406 | | | 6 | | | 21,330 | | | 20,027 | | | 1,303 | | | 7 | |
Wholesale | 3,420 | | | 2,541 | | | 879 | | | 35 | | | 11,343 | | | 7,535 | | | 3,808 | | | 51 | |
Total sales | 11,048 | | | 9,763 | | | 1,285 | | | 13 | % | | 32,673 | | | 27,562 | | | 5,111 | | | 19 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 805 | | 796 | | 9 | | | 1 | % | | 803 | | 794 | | 9 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 96.42 | | | $ | 91.62 | | | $ | 4.80 | | | 5 | % | | $ | 79.90 | | | $ | 76.92 | | | $ | 2.98 | | | 4 | % |
Wholesale | $ | 27.07 | | | $ | 17.34 | | | $ | 9.73 | | | 56 | % | | $ | 18.22 | | | $ | 14.54 | | | $ | 3.68 | | | 25 | % |
| | | | | | | | | | | | | | | |
Heating degree days | 21 | | | 96 | | | (75) | | | (78) | % | | 3,820 | | | 3,698 | | | 122 | | | 3 | % |
Cooling degree days | 870 | | | 795 | | | 75 | | | 9 | % | | 1,296 | | | 1,155 | | | 141 | | | 12 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | 4,164 | | | 4,274 | | | (110) | | | (3) | % | | 16,163 | | | 14,268 | | | 1,895 | | | 13 | % |
Coal | 4,609 | | | 3,169 | | | 1,440 | | | 45 | | | 10,302 | | | 5,771 | | | 4,531 | | | 79 | |
Nuclear | 1,007 | | | 1,000 | | | 7 | | | 1 | | | 2,911 | | | 2,902 | | | 9 | | | — | |
Natural gas | 503 | | | 324 | | | 179 | | | 55 | | | 982 | | | 517 | | | 465 | | | 90 | |
Total energy generated | 10,283 | | | 8,767 | | | 1,516 | | | 17 | | | 30,358 | | | 23,458 | | | 6,900 | | | 29 | |
Energy purchased | 1,038 | | | 1,166 | | | (128) | | | (11) | | | 2,898 | | | 4,592 | | | (1,694) | | | (37) | |
Total | 11,321 | | | 9,933 | | | 1,388 | | | 14 | % | | 33,256 | | | 28,050 | | | 5,206 | | | 19 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 9.81 | | | $ | 7.34 | | | $ | 2.47 | | | 34 | % | | $ | 7.48 | | | $ | 5.53 | | | $ | 1.95 | | | 35 | % |
Energy purchased | $ | 60.32 | | | $ | 43.32 | | | $ | 17.00 | | | 39 | % | | $ | 65.60 | | | $ | 29.67 | | | $ | 35.93 | | | * |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 728 |
| | $ | 712 |
| | $ | 16 |
| | 2 | % | | $ | 1,717 |
| | $ | 1,792 |
| | $ | (75 | ) | | (4 | )% |
Cost of fuel and energy | 115 |
| | 113 |
| | 2 |
| | 2 |
| | 266 |
| | 318 |
| | (52 | ) | | (16 | ) |
Utility margin | $ | 613 |
| | $ | 599 |
| | $ | 14 |
| | 2 | % | | $ | 1,451 |
| | $ | 1,474 |
| | $ | (23 | ) | | (2 | )% |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 2,053 |
| | 1,950 |
| | 103 |
| | 5 | % | | 5,226 |
| | 5,105 |
| | 121 |
| | 2 | % |
Commercial | 1,013 |
| | 1,037 |
| | (24 | ) | | (2 | ) | | 2,800 |
| | 2,930 |
| | (130 | ) | | (4 | ) |
Industrial | 3,758 |
| | 3,652 |
| | 106 |
| | 3 |
| | 10,884 |
| | 10,567 |
| | 317 |
| | 3 |
|
Other | 398 |
| | 420 |
| | (22 | ) | | (5 | ) | | 1,117 |
| | 1,200 |
| | (83 | ) | | (7 | ) |
Total retail | 7,222 |
| | 7,059 |
| | 163 |
| | 2 |
| | 20,027 |
| | 19,802 |
| | 225 |
| | 1 |
|
Wholesale | 2,541 |
| | 1,708 |
| | 833 |
| | 49 |
| | 7,535 |
| | 7,312 |
| | 223 |
| | 3 |
|
Total sales | 9,763 |
| | 8,767 |
| | 996 |
| | 11 | % | | 27,562 |
| | 27,114 |
| | 448 |
| | 2 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 796 |
| | 786 |
| | 10 |
| | 1 | % | | 794 |
| | 785 |
| | 9 |
| | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 91.62 |
| | $ | 92.13 |
| | $ | (0.51 | ) | | (1 | )% | | $ | 86.92 |
| | $ | 78.83 |
| | $ | 8.09 |
| | 10 | % |
Wholesale | $ | 17.34 |
| | $ | 23.00 |
| | $ | (5.66 | ) | | (25 | )% | | $ | 14.54 |
| | $ | 22.81 |
| | $ | (8.27 | ) | | (36 | )% |
| | | | | | | | | | | | | | | |
Heating degree days | 96 |
| | 12 |
| | 84 |
| | * | | 3,698 |
| | 4,218 |
| | (520 | ) | | (12 | )% |
Cooling degree days | 795 |
| | 862 |
| | (67 | ) | | (8 | )% | | 1,155 |
| | 1,142 |
| | 13 |
| | 1 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 3,169 |
| | 3,764 |
| | (595 | ) | | (16 | )% | | 5,771 |
| | 10,101 |
| | (4,330 | ) | | (43 | )% |
Nuclear | 1,000 |
| | 962 |
| | 38 |
| | 4 |
| | 2,902 |
| | 2,846 |
| | 56 |
| | 2 |
|
Natural gas | 324 |
| | 297 |
| | 27 |
| | 9 |
| | 517 |
| | 361 |
| | 156 |
| | 43 |
|
Wind and other(2) | 4,274 |
| | 2,954 |
| | 1,320 |
| | 45 |
| | 14,268 |
| | 11,252 |
| | 3,016 |
| | 27 |
|
Total energy generated | 8,767 |
| | 7,977 |
| | 790 |
| | 10 |
| | 23,458 |
| | 24,560 |
| | (1,102 | ) | | (4 | ) |
Energy purchased | 1,166 |
| | 1,026 |
| | 140 |
| | 14 |
| | 4,592 |
| | 3,072 |
| | 1,520 |
| | 49 |
|
Total | 9,933 |
| | 9,003 |
| | 930 |
| | 10 | % | | 28,050 |
| | 27,632 |
| | 418 |
| | 2 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 7.34 |
| | $ | 9.35 |
| | $ | (2.01 | ) | | (21 | )% | | $ | 5.53 |
| | $ | 8.27 |
| | $ | (2.74 | ) | | (33 | )% |
Energy purchased | $ | 43.32 |
| | $ | 37.29 |
| | $ | 6.03 |
| | 16 | % | | $ | 29.67 |
| | $ | 37.37 |
| | $ | (7.70 | ) | | (21 | )% |
* Not meaningful.
| |
(1) | (1) GWh amounts are net of energy used by the related generating facilities. |
| |
(2) | All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities. |
| |
(3) | The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities. |
Electric utility margin increased $14 million for the third quarter of 2020 compared to 2019, due to:
| |
(1) | Higher retail utility margin of $20 million primarily due to - |
an increase of $13 million from higher recoveries through bill riders, net of energy costs, dueused by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to lower refunds relatedcomply with RPS or other regulatory requirements or (b) sold to third parties in the ratemaking treatmentform of 2017 Tax Reform (offset in income tax benefit) and an increase of $3 million in electric energy efficiency program revenue (offset in operations and maintenance expense);RECs or other environmental commodities.
an increase of $12 million from non-weather-related factors, net of price impacts from changes in sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage;
a decrease of $3 million from lower other retail revenue, including steam sales; and
a decrease of $2 million from the unfavorable impact of weather.
| |
(2) | Lower wholesale utility margin of $5 million due to lower margins per unit, reflecting lower market prices and higher energy costs, partially offset by higher sales volumes of 48.8%. |
Electric utility margin decreased $23 million for the first nine months of 2020 compared to 2019 primarily due to:
| |
(1) | Lower wholesale utility margin of $28 million due to lower market prices, partially offset by lower energy costs and higher sales volumes of 3.0%; |
| |
(2) | Higher retail utility margin of $4 million primarily due to - |
an increase of $14 million from non-weather-related factors, net of price impacts from changes in sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage;
a decrease of $6 million from lower recoveries through bill riders, net(3) The average cost per MWh of energy costs, primarily due to a decreasegenerated includes only the cost of $30 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by lower refunds related tofuel associated with the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and higher recoveries for transmission costs (offset in operations and maintenance expense); andgenerating facilities.
a decrease of $4 million from lower other retail revenue, including steam sales.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 110 | | | $ | 80 | | | $ | 30 | | | 38 | % | | $ | 728 | | | $ | 384 | | | $ | 344 | | | 90 | % |
Natural gas purchased for resale | 63 | | | 39 | | | 24 | | | 62 | | | 552 | | | 209 | | | 343 | | | * |
Utility margin | $ | 47 | | | $ | 41 | | | $ | 6 | | | 15 | % | | $ | 176 | | | $ | 175 | | | $ | 1 | | | 1 | % |
| | | | | | | | | | | | | | | |
Throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | 2,689 | | | 3,190 | | | (501) | | | (16) | % | | 34,243 | | | 34,146 | | | 97 | | | — | % |
Commercial | 1,511 | | | 1,671 | | | (160) | | | (10) | | | 16,255 | | | 15,634 | | | 621 | | | 4 | |
Industrial | 1,110 | | | 1,105 | | | 5 | | | — | | | 3,616 | | | 3,687 | | | (71) | | | (2) | |
Other | 4 | | | 6 | | | (2) | | | (33) | | | 52 | | | 54 | | | (2) | | | (4) | |
Total retail sales | 5,314 | | | 5,972 | | | (658) | | | (11) | | | 54,166 | | | 53,521 | | | 645 | | | 1 | |
Wholesale sales | 6,365 | | | 5,622 | | | 743 | | | 13 | | | 22,955 | | | 24,391 | | | (1,436) | | | (6) | |
Total sales | 11,679 | | | 11,594 | | | 85 | | | 1 | | | 77,121 | | | 77,912 | | | (791) | | | (1) | |
Natural gas transportation service | 26,789 | | | 24,973 | | | 1,816 | | | 7 | | | 83,282 | | | 82,092 | | | 1,190 | | | 1 | |
Total throughput | 38,468 | | | 36,567 | | | 1,901 | | | 5 | % | | 160,403 | | | 160,004 | | | 399 | | | — | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 776 | | | 769 | | | 7 | | | 1 | % | | 776 | | | 770 | | | 6 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per retail Dth sold | $ | 14.21 | | | $ | 10.43 | | | $ | 3.78 | | | 36 | % | | $ | 11.20 | | | $ | 5.91 | | | $ | 5.29 | | | 90 | % |
| | | | | | | | | | | | | | | |
Heating degree days | 28 | | | 122 | | | (94) | | | (77) | % | | 3,954 | | | 3,899 | | | 55 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | $ | 7.09 | | | $ | 4.74 | | | $ | 2.35 | | | 50 | % | | $ | 8.47 | | | $ | 3.12 | | | $ | 5.35 | | | * |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | $ | 5.42 | | | $ | 3.32 | | | $ | 2.10 | | | 63 | % | | $ | 7.16 | | | $ | 2.68 | | | $ | 4.48 | | | * |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Third Quarter | | First Nine Months |
| 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 80 |
| | $ | 76 |
| | $ | 4 |
| | 5 | % | | $ | 384 |
| | $ | 482 |
| | $ | (98 | ) | | (20) | % |
Natural gas purchased for resale | 39 |
| | 39 |
| | — |
| | — |
| | 209 |
| | 287 |
| | (78 | ) | | (27 | ) |
Utility margin | $ | 41 |
| | $ | 37 |
| | $ | 4 |
| | 11 | % | | $ | 175 |
| | $ | 195 |
| | $ | (20 | ) | | (10) | % |
| | | | | | | | | | | | | | | |
Throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | 3,190 |
| | 2,633 |
| | 557 |
| | 21 | % | | 34,146 |
| | 38,130 |
| | (3,984 | ) | | (10) | % |
Commercial | 1,671 |
| | 1,522 |
| | 149 |
| | 10 |
| | 15,634 |
| | 18,103 |
| | (2,469 | ) | | (14 | ) |
Industrial | 1,105 |
| | 929 |
| | 176 |
| | 19 |
| | 3,687 |
| | 3,424 |
| | 263 |
| | 8 |
|
Other | 6 |
| | 10 |
| | (4 | ) | | (40 | ) | | 54 |
| | 58 |
| | (4 | ) | | (7 | ) |
Total retail sales | 5,972 |
| | 5,094 |
| | 878 |
| | 17 |
| | 53,521 |
| | 59,715 |
| | (6,194 | ) | | (10 | ) |
Wholesale sales | 5,622 |
| | 7,251 |
| | (1,629 | ) | | (22 | ) | | 24,391 |
| | 25,856 |
| | (1,465 | ) | | (6 | ) |
Total sales | 11,594 |
| | 12,345 |
| | (751 | ) | | (6 | ) | | 77,912 |
| | 85,571 |
| | (7,659 | ) | | (9 | ) |
Natural gas transportation service | 24,973 |
| | 27,011 |
| | (2,038 | ) | | (8 | ) | | 82,092 |
| | 81,378 |
| | 714 |
| | 1 |
|
Total throughput | 36,567 |
| | 39,356 |
| | (2,789 | ) | | (7) | % | | 160,004 |
| | 166,949 |
| | (6,945 | ) | | (4) | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 769 |
| | 760 |
| | 9 |
| | 1 | % | | 770 |
| | 761 |
| | 9 |
| | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per retail Dth sold | $ | 10.43 |
| | $ | 10.65 |
| | $ | (0.22 | ) | | (2) | % | | $ | 5.91 |
| | $ | 6.55 |
| | $ | (0.64 | ) | | (10) | % |
| | | | | | | | | | | | | | | |
Heating degree days | 122 |
| | 19 |
| | 103 |
| | * | | 3,899 |
| | 4,408 |
| | (509 | ) | | (12) | % |
| | | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | $ | 4.74 |
| | $ | 4.83 |
| | $ | (0.09 | ) | | (2) | % | | $ | 3.12 |
| | $ | 3.74 |
| | $ | (0.62 | ) | | (17) | % |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | $ | 3.32 |
| | $ | 3.17 |
| | $ | 0.15 |
| | 5 | % | | $ | 2.68 |
| | $ | 3.35 |
| | $ | (0.67 | ) | | (20) | % |
* Not meaningful.
Natural gasQuarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020
MidAmerican Energy -
Electric utility margin increased $4$78 million, or 13%, for the third quarter of 20202021 compared to 20192020, primarily due to:
| |
(1) | An increase of $3 million from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense); and |
| |
(2) | An increase of $1 million from the favorable impact of weather and other usage factors. |
•a $41 million increase in wholesale utility margin due to higher margin per unit of $35 million, reflecting higher market prices, and higher volumes of 34.6%; and
•a $36 million increase in retail utility margin primarily due to $20 million from higher usage for certain industrial customers; $6 million from liquidated damages related to a wind-powered generation project; $5 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $4 million from the favorable impact of weather. Retail customer volumes increased 5.6%.
Natural gas utility margin decreased $20 increased $6 million, for the first nine months of 2020 compared to 2019 primarily due to:
| |
(1) | A decrease of $13 million from lower natural gas energy efficiency program revenue (offset in operations and maintenance expense); |
| |
(2) | A decrease of $7 million from the unfavorable impact of weather in the first quarter; |
| |
(3) | A decrease of $1 million from non-weather rate and usage variances, in part due to sales mix; and |
| |
(4) | An increase of $2 million from rider refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit). |
Operating Expenses
MidAmerican Energy -
Operations and maintenance increased $23 millionor 15%, for the third quarter of 20202021 compared to 20192020 primarily due to:
•an $8 million increase from higher average prices primarily due to higher electric distribution expensesthe timing of $17recoveries through a capital tracker mechanism; partially offset by
•a $3 million driven by storm restoration related to significant wind damagedecrease from the derecho storm in August 2020, higher wind-powered generation operations and maintenance expensesunfavorable impact of $7 million due to additional and repowered wind turbines and easements, higher energy efficiency program expense of $4 million (offset in operating revenue) and higher customer accounts costs of $2 million driven by greater bad debt expense, partially offset by lower deferred compensation costs of $4 million and lower natural gas distribution costs of $3 million.weather.
Operations and maintenance decreased $41$12 million, or 6%, for the first nine monthsthird quarter of 20202021 compared to 20192020 primarily due to lower energy efficiency program expense of $43 million (offset in operating revenue), lower fossil-fueled generating facilityelectric distribution maintenance of $13 million, lower natural gas distribution expenses of $8 million, a nuclear property insurance premium refund of $5 million, lower deferred compensation costs of $5$21 million and lower nonregulateddue to storm restoration costs in 2020, partially offset by higher other generation operations expenses of $4 million, partially offset by higher wind-powered generation operations and maintenance expenses of $23 million due to additional wind turbines and easements higher electric distribution costs of $8 million largely driven by storm restoration related to the derecho storm in August 2020 and higher transmission operations costs from the Midcontinent Independent System Operator, Inc.MISO of $4 million (offset in operating revenue).$3 million.
Depreciation and amortization for the third quarter and first nine months of 2020 decreased $42021 increased $38 million, and $9 million, respectively,or 21%, compared to 20192020 primarily due to lower Iowa revenue sharing accruals of $30 million and $84 million, respectively, substantially offset by an increase related to new and repowered wind-powered generating facilities and other plant placed in-service.in-service, $13 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $9 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.
Property and other taxes increased $8 million for the first nine months of 2020 compared to 2019 due to higher retail sales and wind-powered generating facility increases.
Other Income (Expense)
MidAmerican Energy -
Interest expense increased $6 million and $17 million for the third quarter and first nine months, respectively, of 2020 compared to 2019 due to higher average long-term debt balances.
Allowance for borrowed and equity funds decreased $13$6 million, and $34 millionor 29%, for the third quarter and first nine months, respectively, of 20202021 compared to 20192020 primarily due to lower construction work-in-progress balances related to wind-powered generation.
Other, net increased $10 decreased $6 million, or 43%, for the third quarter of 20202021 compared to 2019 primarily due to higher cash surrender values of corporate-owned life insurance policies of $4 million and lower non-service costs of postretirement employee benefit plans.
Other, net decreased $4 million for the first nine months of 2020 compared to 2019 primarily due to lower cash surrender values of corporate-owned life insurance policies of $9policies.
Income tax benefit decreased $4 million, and lower interest income of $6 million from unfavorable cash positions, partially offset by lower non-service costs of postretirement employee benefit plans.
Income Tax Benefit
MidAmerican Energy -
MidAmerican Energy's income tax benefit increased $69 millionor 3%, for the third quarter of 20202021 compared to 2019,2020, and the effective tax rate was (61)% for 2021 and (76)% for 2020 and (38)% for 2019. For the first nine months of 2020 compared to 2019, MidAmerican Energy's income tax benefit increased $129 million, and the effective tax rate was (142)% for 2020 and (81)% for 2019.2020. The change in the effective tax rates for 20202021 compared to 20192020 was primarily due to thea higher PTCs, state income tax impacts, the effects of ratemaking and a lower pretax income in 2020.income.
Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the nine-month periods ended September 30,third quarter of 2021 and 2020 and 2019 totaled $352$103 million and $259$105 million, respectively.
MidAmerican Funding -
MidAmerican Funding's incomeIncome tax benefit increased $68 decreased $4 million, or 3%, for the third quarter of 20202021 compared to 2019,2020, and the effective tax rate was (63)% for 2021 and (78)% for 2020 and (40)%2020. The changes in the effective tax rates were due to the factors discussed for 2019. ForMidAmerican Energy.
First Nine Months of 2021 compared to First Nine Months of 2020
MidAmerican Energy -
Electric utility margin increased $117 million, or 8%, for the first nine months of 20202021 compared to 2019, MidAmerican Funding's2020, due to:
•a $90 million increase in retail utility margin primarily due to $42 million from higher usage for certain industrial customers; $17 million from the favorable impact of weather; $17 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); $7 million due to price impacts from changes in sales mix and $6 million from liquidated damages related to a wind-powered generation project. Retail customer volumes increased 6.5%; and
•a $29 million increase in wholesale utility margin due to higher volumes of 50.5%, partially offset by lower margins per unit of $10 million, reflecting higher energy costs; partially offset by
•a $2 million decrease in Multi-Value Projects transmission revenue.
Natural gas utility margin increased $1 million, or 1%, for the first nine months of 2021 compared to 2020 primarily due to:
•a $5 million increase in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•a $2 million increase natural gas transportation margin, reflecting higher volumes; partially offset by
•a $7 million decrease from higher refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit).
Operations and maintenance increased $18 million, or 3%, for the first nine months of 2021 compared to 2020 primarily due to higher other generation operations and maintenance expenses of $12 million due to additional wind turbines and easements, higher energy efficiency program expense of $9 million (offset in operating revenue), higher natural gas distribution costs of $6 million and higher transmission operations costs from MISO of $3 million, partially offset by lower electric distribution costs of $15 million due to storm restoration costs in 2020.
Depreciation and amortization for the first nine months of 2021 increased $103 million, or 19%, compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $39 million from a regulatory mechanism deferring certain depreciation expense in 2020 and $18 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects. Refer to "Overview" above for a discussion of an IUB order extending the regulatory mechanism deferring certain depreciation expense.
Allowance for borrowed and equity funds decreased $12 million, or 27%, for the first nine months of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.
Other, net increased $4 million, or 13%, for the first nine months of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies, partially offset by higher non-service costs of postretirement employee benefit plans.
Income tax benefitincreased $128$45 million, or 11%, for the first nine months of 2021 compared to 2020, and the effective tax rate was (162)% for 2021 and (142)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was primarily due to the higher PTCs and a lower pretax income. PTCs for the first nine months of 2021 and 2020 totaled $400 million and $352 million, respectively.
MidAmerican Funding -
Income tax benefit increased $46 million, or 11%, for the first nine months of 2021 compared to 2020, and the effective tax rate was (172)% for 2021 and (147)% for 2020 and (85)% for 2019.2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of September 30, 2020,2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
| | | | | | | | |
MidAmerican Energy: | | |
Cash and cash equivalents | | $ | 541 | |
| | |
Credit facilities, maturing 2022 and 2024 | | 1,505 | |
Less: | | |
| | |
Tax-exempt bond support | | (370) | |
Net credit facilities | | 1,135 | |
| | |
MidAmerican Energy total net liquidity | | $ | 1,676 | |
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 1,676 | |
Cash and cash equivalents | | 1 | |
MHC, Inc. credit facility, maturing 2022 | | 4 | |
MidAmerican Funding total net liquidity | | $ | 1,681 | |
|
| | | | |
MidAmerican Energy: | | |
Cash and cash equivalents | | $ | 188 |
|
| | |
Credit facilities, maturing 2021 and 2022 | | 1,505 |
|
Less: | | |
Tax-exempt bond support | | (370 | ) |
Net credit facilities | | 1,135 |
|
MidAmerican Energy total net liquidity | | $ | 1,323 |
|
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 1,323 |
|
Cash and cash equivalents | | 5 |
|
MHC, Inc. credit facility, maturing 2021 | | 4 |
|
MidAmerican Funding total net liquidity | | $ | 1,332 |
|
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020, and 2019, were $1,209$1,290 million and $1,211$1,209 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020, and 2019, were $1,199$1,276 million and $1,194$1,199 million, respectively. Cash flows from operating activities reflect higher income tax receipts and lower payments for the settlement of asset retirement obligations, partially offset by lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses, including delayed recovery of higher interest paid due to long-term debt issuednatural gas costs in October 2019, higher settlement payments for asset retirement obligationsFebruary 2021, discussed below, and higher payments to vendors.
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the nine-month period ended September 30, 2021.
The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
MidAmerican Energy's net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020, and 2019, were $(1,339)$(1,276) million and $(1,903)$(1,339) million, respectively. MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020, and 2019, were $(1,338)$(1,276) million and $(1,903)$(1,338) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which decreased primarily due to lower wind-powered generating facility construction and repowering expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments. Other, net for 2020 reflects $9 million of proceeds from corporate-owned life insurance policies.
Financing Activities
MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $(1)$489 million and $720$(1) million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2021 and 2020, were $503 million and 2019, were $12 million, and $737 million, respectively. In January 2019,Proceeds from long-term debt reflect MidAmerican Energy issued $600Energy's issuance in July 2021 of $500 million of its 3.65%2.70% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. Through its commercial paper program, MidAmerican Energy paid $240 million in 2019.August 2052. MidAmerican Funding received $13 million in 2021 and $17 million in 2020, and 2019, respectively, through its note payable with BHE.
Debt Authorizations and Related Matters
MidAmerican Energy has authority from the FERC to issue, through April 2, 2022, commercial paper and bank notes aggregating $1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points. MidAmerican Energy has a $900 million$1.5 billion unsecured credit facility expiring in June 2022.2024. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. MidAmerican Energy has a $600 million unsecured credit facility, which expires in May 2021, with an option to extend for up to three months, and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
MidAmerican Energy currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021.13, 2024. Additionally, following the July 2021 issuance of $500 million of first mortgage bonds, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2021,2023, long-term debt securities up to an aggregate of $850 million at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points$2.0 billion and preferred stock up to an aggregate of $500 million and from the ICCIllinois Commerce Commission to issue long-term debt securities up to an aggregate of $850$350 million through August 20, 2022.
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have 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 and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
MidAmerican Energy 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.
MidAmerican Energy'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):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Wind generation | $ | 713 | | | $ | 605 | | | $ | 807 | |
Electric distribution | 189 | | | 154 | | | 260 | |
Electric transmission | 132 | | | 105 | | | 194 | |
Solar generation | 2 | | | 97 | | | 180 | |
Other | 305 | | | 305 | | | 502 | |
Total | $ | 1,341 | | | $ | 1,266 | | | $ | 1,943 | |
|
| | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2019 | | 2020 | | 2020 |
| | | | | |
Wind-powered generation under ratemaking principles | $ | 1,027 |
| | $ | 274 |
| | $ | 387 |
|
Renewable generation not under ratemaking principles | — |
| | 404 |
| | 501 |
|
Wind-powered generation repowering | 332 |
| | 25 |
| | 44 |
|
Other | 550 |
| | 638 |
| | 991 |
|
Total | $ | 1,909 |
| | $ | 1,341 |
| | $ | 1,923 |
|
MidAmerican Energy's historical and forecast capital expenditures for 2020 includeprovided above consist of the following:
The•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa. Wind XI, a 2,000-MW project constructed over several years, was completed in January 2020. Wind XII is a 592-MW project, including 253 MWs placed in-service as
◦Construction and acquisition of wind-powered generating facilities totaled $275 million and $676 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the construction of additional wind-powered generating facilities totals $73 million for the remainder of 2021 and includes 203 MWs of wind-powered generating facilities expected to be placed in-service by the end of 2020. MidAmerican Energy obtained pre-approved ratemaking principles for both of these projects and expects all of these wind-powered generating facilities to qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates.2021.
Additionally, MidAmerican Energy continues to evaluate wind-powered and other renewable generating facilities that will not be subject to pre-approved ratemaking principles. MidAmerican Energy currently has three such wind-powered generation projects under construction totaling 319 MWs that are expected to be placed in-service by the end of 2020 and to qualify for 100% of PTCs available. In the nine-month period ended September 30, 2020, MidAmerican Energy purchased 80 MWs (nominal ratings)◦Repowering of wind-powered generating facilities that began commercial operation in 2012totaled $274 million and are not eligible$25 million for PTCs.
Thethe nine-month periods ended September 30, 2021 and 2020, respectively. Planned spending for the repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. The repowering projects entailtotals $101 million for the replacementremainder of significant components of the2021. MidAmerican Energy expects its repowered facilities which is expected to qualify such facilitiesmeet Internal Revenue Service guidelines for the re-establishment of PTCs for ten10 years following each facility's return to servicefrom the date the facilities are placed in-service. The rate at rates that dependwhich PTCs are re-established for a facility depends upon the year in whichdate construction begins. Of the 998892 MWs of current repowering projects not in-service as of September 30, 2020,2021, 591 MWs are currently expected to qualify for 80% of the PTCs available for ten10 years following each facility's return to service and 407301 MWs are expected to qualify for 60% of such credits.
•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.
•Solar reflects 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.
•Remaining costs expenditures primarily relate to routine expenditures for other generation, transmission,natural gas distribution, technology, facilities and other infrastructure neededoperational needs to serve existing and expected demand.
Contractual Obligations
As of September 30, 2020,2021, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2019.2020.
In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by MidAmerican Energy. While COVID-19 has impacted MidAmerican Energy's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, all states in which MidAmerican Energy operates instituted varying levels of "stay-at-home" orders and other measures, requiring non-essential businesses to remain closed, which impacted MidAmerican Energy's customers and, therefore, their needs and usage patterns for electricity and natural gas as evidenced by a reduction in consumption due to COVID-19 through September 2020 compared to the same period in 2019. These states have since moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity or natural gas may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by MidAmerican Energy related to customer collection activity and suspension of disconnections for non-payment, MidAmerican Energy has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019, but uncertainty remains. Regulatory jurisdictions may allow for recovery of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.
MidAmerican Energy's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system and its natural gas distribution system. In response to the effects of COVID-19, MidAmerican Energy has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.
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 state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expandsexpanded the breadth and scope of the PJM's MOPR, which isbecame effective as of the PJM's next capacity auction.auction for the 2022-2023 planning year in May 2021. 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,A number of parties, including Exelon, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC issued an order denying requestson July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. A request for rehearing of its April 16, 2020 order and acceptingthe FERC's notice establishing the effective date for the PJM's two compliance filings, subject to a further compliance filing to revise minor aspectsproposed market reforms was filed on October 5, 2021, and remains pending.
Assuming the continued effectiveness 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.
Illinois zero emission standard, 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,no longer considers Quad Cities Station couldto be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction 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.auction.
Regulatory Matters
MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local 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 its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, 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 the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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 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 MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2019.2020. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2019.
2020.
Nevada Power Company 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 Shareholder of
Nevada Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2020,2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, and of cash flows for the nine-month periods ended September 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 Nevada Power as of December 31, 2019,2020, and the related consolidated statements of operations, changes in shareholder's 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 Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power 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
Las Vegas, Nevada
November 6, 20205, 2021
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 85 | | | $ | 25 | |
Trade receivables, net | 353 | | | 234 | |
Inventories | 66 | | | 69 | |
Derivative contracts | 3 | | | 26 | |
Regulatory assets | 217 | | | 48 | |
Prepayments | 37 | | | 38 | |
| | | |
Other current assets | 36 | | | 26 | |
Total current assets | 797 | | | 466 | |
| | | |
Property, plant and equipment, net | 6,829 | | | 6,701 | |
Finance lease right of use assets, net | 330 | | | 351 | |
Regulatory assets | 686 | | | 746 | |
Other assets | 73 | | | 72 | |
| | | |
Total assets | $ | 8,715 | | | $ | 8,336 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 249 | | | $ | 181 | |
Accrued interest | 38 | | | 32 | |
Accrued property, income and other taxes | 60 | | | 25 | |
| | | |
| | | |
Current portion of finance lease obligations | 26 | | | 27 | |
Regulatory liabilities | 54 | | | 50 | |
Customer deposits | 44 | | | 47 | |
Asset retirement obligation | 16 | | | 25 | |
| | | |
Other current liabilities | 38 | | | 22 | |
Total current liabilities | 525 | | | 409 | |
| | | |
Long-term debt | 2,498 | | | 2,496 | |
Finance lease obligations | 313 | | | 334 | |
Regulatory liabilities | 1,118 | | | 1,163 | |
Deferred income taxes | 753 | | | 738 | |
Other long-term liabilities | 281 | | | 257 | |
Total liabilities | 5,488 | | | 5,397 | |
| | | |
Commitments and contingencies (Note 8) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — | | | — | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 922 | | | 634 | |
Accumulated other comprehensive loss, net | (3) | | | (3) | |
Total shareholder's equity | 3,227 | | | 2,939 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,715 | | | $ | 8,336 | |
| | | |
The accompanying notes are an integral part of the consolidated financial statements. |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 152 |
| | $ | 15 |
|
Trade receivables, net | 386 |
| | 215 |
|
Inventories | 66 |
| | 62 |
|
Prepayments | 54 |
| | 42 |
|
Other current assets | 70 |
| | 30 |
|
Total current assets | 728 |
| | 364 |
|
| | | |
Property, plant and equipment, net | 6,643 |
| | 6,538 |
|
Finance lease right of use assets, net | 354 |
| | 441 |
|
Regulatory assets | 782 |
| | 800 |
|
Other assets | 59 |
| | 59 |
|
| | | |
Total assets | $ | 8,566 |
| | $ | 8,202 |
|
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 209 |
| | $ | 194 |
|
Accrued interest | 38 |
| | 30 |
|
Accrued property, income and other taxes | 76 |
| | 25 |
|
Current portion of long-term debt | — |
| | 575 |
|
Regulatory liabilities | 172 |
| | 93 |
|
Customer deposits | 50 |
| | 62 |
|
Other current liabilities | 84 |
| | 58 |
|
Total current liabilities | 629 |
| | 1,037 |
|
| | | |
Long-term debt | 2,496 |
| | 1,776 |
|
Finance lease obligations | 338 |
| | 430 |
|
Regulatory liabilities | 1,129 |
| | 1,163 |
|
Deferred income taxes | 712 |
| | 714 |
|
Other long-term liabilities | 276 |
| | 285 |
|
Total liabilities | 5,580 |
| | 5,405 |
|
| | | |
Commitments and contingencies (Note 8) |
| |
|
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — |
| | — |
|
Additional paid-in capital | 2,308 |
| | 2,308 |
|
Retained earnings | 682 |
| | 493 |
|
Accumulated other comprehensive loss, net | (4 | ) | | (4 | ) |
Total shareholder's equity | 2,986 |
| | 2,797 |
|
| | | |
Total liabilities and shareholder's equity | $ | 8,566 |
| | $ | 8,202 |
|
| | | |
The accompanying notes are an integral part of the consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Operating revenue | $ | 802 | | | $ | 808 | | | $ | 1,731 | | | $ | 1,706 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 328 | | | 287 | | | 745 | | | 654 | |
Operations and maintenance | 88 | | | 139 | | | 228 | | | 295 | |
Depreciation and amortization | 103 | | | 92 | | | 304 | | | 273 | |
Property and other taxes | 12 | | | 12 | | | 36 | | | 35 | |
Total operating expenses | 531 | | | 530 | | | 1,313 | | | 1,257 | |
| | | | | | | |
Operating income | 271 | | | 278 | | | 418 | | | 449 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (38) | | | (40) | | | (115) | | | (122) | |
Allowance for borrowed funds | — | | | 1 | | | 2 | | | 3 | |
Allowance for equity funds | 2 | | | 1 | | | 5 | | | 5 | |
Interest and dividend income | 5 | | | 3 | | | 13 | | | 8 | |
Other, net | 4 | | | 3 | | | 14 | | | 4 | |
Total other income (expense) | (27) | | | (32) | | | (81) | | | (102) | |
| | | | | | | |
Income before income tax expense | 244 | | | 246 | | | 337 | | | 347 | |
Income tax expense | 27 | | | 52 | | | 36 | | | 74 | |
Net income | $ | 217 | | | $ | 194 | | | $ | 301 | | | $ | 273 | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Operating revenue | $ | 808 |
| | $ | 806 |
| | $ | 1,706 |
| | $ | 1,728 |
|
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 287 |
| | 353 |
| | 654 |
| | 752 |
|
Operations and maintenance | 139 |
| | 109 |
| | 295 |
| | 263 |
|
Depreciation and amortization | 92 |
| | 89 |
| | 273 |
| | 267 |
|
Property and other taxes | 12 |
| | 11 |
| | 35 |
| | 34 |
|
Total operating expenses | 530 |
| | 562 |
| | 1,257 |
| | 1,316 |
|
| | | | | | | |
Operating income | 278 |
| | 244 |
| | 449 |
| | 412 |
|
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (40 | ) | | (41 | ) | | (122 | ) | | (129 | ) |
Allowance for borrowed funds | 1 |
| | 1 |
| | 3 |
| | 2 |
|
Allowance for equity funds | 1 |
| | 2 |
| | 5 |
| | 4 |
|
Other, net | 6 |
| | 4 |
| | 12 |
| | 17 |
|
Total other income (expense) | (32 | ) | | (34 | ) | | (102 | ) | | (106 | ) |
| | | | | | | |
Income before income tax expense | 246 |
| | 210 |
| | 347 |
| | 306 |
|
Income tax expense | 52 |
| | 45 |
| | 74 |
| | 66 |
|
Net income | $ | 194 |
| | $ | 165 |
| | $ | 273 |
| | $ | 240 |
|
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. | | |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Additional | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | |
Balance, June 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 488 | | | $ | (4) | | | $ | 2,792 | |
Net income | | — | | | — | | | — | | | 194 | | | — | | | 194 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 682 | | | $ | (4) | | | $ | 2,986 | |
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 493 | | | $ | (4) | | | $ | 2,797 | |
Net income | | — | | | — | | | — | | | 273 | | | — | | | 273 | |
Dividends declared | | — | | | — | | | — | | | (85) | | | — | | | (85) | |
Other equity transactions | | — | | | — | | | — | | | 1 | | | — | | | 1 | |
Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 682 | | | $ | (4) | | | $ | 2,986 | |
| | | | | | | | | | | | |
Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 705 | | | $ | (3) | | | $ | 3,010 | |
Net income | | — | | | — | | | — | | | 217 | | | — | | | 217 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 922 | | | $ | (3) | | | $ | 3,227 | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | |
Net income | | — | | | — | | | — | | | 301 | | | — | | | 301 | |
Dividends declared | | — | | | — | | | — | | | (13) | | | — | | | (13) | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 922 | | | $ | (3) | | | $ | 3,227 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Additional | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | |
Balance, June 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 580 |
| | $ | (4 | ) | | $ | 2,884 |
|
Net income | | — |
| | — |
| | — |
| | 165 |
| | — |
| | 165 |
|
Balance, September 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 745 |
| | $ | (4 | ) | | $ | 3,049 |
|
| | | | | | | | | | | | |
Balance, December 31, 2018 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 600 |
| | $ | (4 | ) | | $ | 2,904 |
|
Net income | | — |
| | — |
| | — |
| | 240 |
| | — |
| | 240 |
|
Dividends declared | | — |
| | — |
| | — |
| | (95 | ) | | — |
| | (95 | ) |
Balance, September 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 745 |
| | $ | (4 | ) | | $ | 3,049 |
|
| | | | | | | | | | | | |
Balance, June 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 488 |
| | $ | (4 | ) | | $ | 2,792 |
|
Net income | | — |
| | — |
| | — |
| | 194 |
| | — |
| | 194 |
|
Balance, September 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 682 |
| | $ | (4 | ) | | $ | 2,986 |
|
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 493 |
| | $ | (4 | ) | | $ | 2,797 |
|
Net income | | — |
| | — |
| | — |
| | 273 |
| | — |
| | 273 |
|
Dividends declared | | — |
| | — |
| | — |
| | (85 | ) | | — |
| | (85 | ) |
Other equity transactions | | — |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
Balance, September 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 682 |
| | $ | (4 | ) | | $ | 2,986 |
|
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 301 | | | $ | 273 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
| | | |
Depreciation and amortization | 304 | | | 273 | |
Allowance for equity funds | (5) | | | (5) | |
Changes in regulatory assets and liabilities | (11) | | | 38 | |
Deferred income taxes and amortization of investment tax credits | (19) | | | (3) | |
Deferred energy | (154) | | | (38) | |
Amortization of deferred energy | (7) | | | (30) | |
Other, net | 1 | | | 5 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (133) | | | (112) | |
Inventories | 3 | | | (4) | |
Accrued property, income and other taxes | 28 | | | 48 | |
Accounts payable and other liabilities | 97 | | | (39) | |
Net cash flows from operating activities | 405 | | | 406 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (323) | | | (343) | |
| | | |
Proceeds from sale of assets | — | | | 26 | |
Other, net | 1 | | | — | |
Net cash flows from investing activities | (322) | | | (317) | |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | — | | | 718 | |
Repayments of long-term debt | — | | | (575) | |
| | | |
| | | |
| | | |
Dividends paid | (13) | | | (85) | |
Other, net | (12) | | | (12) | |
Net cash flows from financing activities | (25) | | | 46 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 58 | | | 135 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 36 | | | 25 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 94 | | | $ | 160 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2020 | | 2019 |
Cash flows from operating activities: | | | |
Net income | $ | 273 |
| | $ | 240 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 273 |
| | 267 |
|
Allowance for equity funds | (5 | ) | | (4 | ) |
Changes in regulatory assets and liabilities | 38 |
| | 62 |
|
Deferred income taxes and amortization of investment tax credits | (3 | ) | | (42 | ) |
Deferred energy | (38 | ) | | 39 |
|
Amortization of deferred energy | (30 | ) | | 37 |
|
Other, net | 5 |
| | (4 | ) |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (112 | ) | | (110 | ) |
Inventories | (4 | ) | | 2 |
|
Accrued property, income and other taxes | 48 |
| | 53 |
|
Accounts payable and other liabilities | (39 | ) | | 15 |
|
Net cash flows from operating activities | 406 |
| | 555 |
|
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (343 | ) | | (283 | ) |
Proceeds from sale of assets | 26 |
| | 2 |
|
Net cash flows from investing activities | (317 | ) | | (281 | ) |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | 718 |
| | 495 |
|
Repayments of long-term debt | (575 | ) | | (500 | ) |
Dividends paid | (85 | ) | | (95 | ) |
Other, net | (12 | ) | | (11 | ) |
Net cash flows from financing activities | 46 |
| | (111 | ) |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 135 |
| | 163 |
|
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 25 |
| | 121 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 160 |
| | $ | 284 |
|
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is 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 September 30, 20202021 and for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The results of operations for the three- and nine-month periods ended September 30, 20202021 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 Nevada Power'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 Nevada Power's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.2021.
Coronavirus Disease 2019 ("COVID-19")
(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of Nevada Power's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted Nevada Power's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial, industrial and distribution only service customer classes as the longer term impacts of COVID-19 and related customer and governmental responses remain uncertain, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers. The duration and extent of COVID-19 and its future impact on Nevada Power's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of Nevada Power's unaudited Consolidated Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to Nevada Power and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.
In March 2020, the Public Utilities Commission of Nevada ("PUCN") issued an emergency order for Nevada Power to establish a regulatory asset account related to 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.
| |
(2)
| Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
|
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 as of September 30, 20202021 and December 31, 2019,2020, consist of funds restricted by the PUCNPublic Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 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):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 85 | | | $ | 25 | |
Restricted cash and cash equivalents included in other current assets | 9 | | | 11 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 94 | | | $ | 36 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Cash and cash equivalents | $ | 152 |
| | $ | 15 |
|
Restricted cash and cash equivalents included in other current assets | 8 |
| | 10 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 160 |
| | $ | 25 |
|
(3) Property, Plant and Equipment, Net
| |
(3) | Property, Plant and Equipment, Net |
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| Depreciable Life | | September 30, | | December 31, |
| | 2021 | | 2020 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,780 | | | $ | 3,690 | |
Transmission | 45 - 70 years | | 1,493 | | | 1,468 | |
Distribution | 20 - 65 years | | 3,878 | | | 3,771 | |
General and intangible plant | 5 - 65 years | | 810 | | | 791 | |
Utility plant | | | 9,961 | | | 9,720 | |
Accumulated depreciation and amortization | | | (3,350) | | | (3,162) | |
Utility plant, net | | | 6,611 | | | 6,558 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,612 | | | 6,559 | |
Construction work-in-progress | | | 217 | | | 142 | |
Property, plant and equipment, net | | | $ | 6,829 | | | $ | 6,701 | |
(4) Recent Financing Transactions
|
| | | | | | | | | |
| | | As of |
| Depreciable Life | | September 30, | | December 31, |
| | 2020 | | 2019 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,612 |
| | $ | 3,541 |
|
Transmission | 45 - 70 years | | 1,455 |
| | 1,444 |
|
Distribution | 20 - 65 years | | 3,738 |
| | 3,567 |
|
General and intangible plant | 5 - 65 years | | 784 |
| | 741 |
|
Utility plant | | | 9,589 |
| | 9,293 |
|
Accumulated depreciation and amortization | | | (3,112 | ) | | (2,951 | ) |
Utility plant, net | | | 6,477 |
| | 6,342 |
|
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 |
| | 1 |
|
Plant, net | | | 6,478 |
| | 6,343 |
|
Construction work-in-progress | | | 165 |
| | 195 |
|
Property, plant and equipment, net | | | $ | 6,643 |
| | $ | 6,538 |
|
Credit Facilities
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.
Regulatory Rate Review
In June 2020,2021, Nevada Power filedamended and restated its existing $400 million secured credit facility expiring in June 2022 with no remaining one-year extension options. The amendment extended the expiration date to June 2024 and increased the available maturity extension options to 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 Powerunlimited number, subject to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuationlender consent.
(5)Income Taxes
A reconciliation of the earning sharing mechanism wasfederal statutory income tax rate to the one issue that was not addressed ineffective income tax rate applicable to income before income tax expense is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
| | | | | | | |
Effects of ratemaking | (10) | | | — | | | (10) | | | — | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Effective income tax rate | 11 | % | | 21 | % | | 11 | % | | 21 | % |
Effects of ratemaking is primarily attributable to the settlement. In October 2020,recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by 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.
Natural Disaster Protection Plan
In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires Nevada Power to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 2020, that require Nevada Power 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 Nevada Power to prevent or respond to a fire or other natural disaster. The expenditures incurred by Nevada Power in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with Nevada Power filing an application for recovery on or before March 1 of each year. Nevada Power 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.
2017 Tax Reform
In February 2018, Nevada Power made a filing 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 Nevada Power. 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 Nevada Power 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, Nevada Power 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, Nevada Power 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, Nevada Power filed a notice of appeal to the Nevada Supreme Court of the district court's order. Nevada Power has 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.
| |
(5) | Recent Financing Transactions |
Long-Term Debt
In May 2020, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County Pollution Control Refunding Revenue Bonds, Series 2017, due 2036. The Series 2017A bond was offered at a fixed rate of 1.875% and the Series 2017B and Series 2017 bonds were offered at a fixed rate of 1.65%.
In January 2020, Nevada Power issued $425 million of 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 and $300 million of its 3.125% General and Refunding Mortgage Notes, Series EE, due 2050. Nevada Power used the net proceeds for the early redemption of $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020 and for general corporate purposes.
(6) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts payable toreceivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Qualified Pension Plan: | | | |
Other non-current assets | $ | 11 | | | $ | 8 | |
| | | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
| | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (9) | | | (9) | |
| | | |
Other Postretirement Plans: | | | |
Other non-current assets | 4 | | | 4 | |
| | | |
| | | |
(7) Fair Value Measurements
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Qualified Pension Plan: | | | |
Other long-term liabilities | $ | 18 |
| | $ | 18 |
|
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | 1 |
| | 1 |
|
Other long-term liabilities | 9 |
| | 9 |
|
| | | |
Other Postretirement Plans: | | | |
Other long-term liabilities | 2 |
| | 2 |
|
| |
(7) | Fair Value Measurements |
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of September 30, 2021 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
Money market mutual funds | 74 | | | — | | | — | | | 74 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 77 | | | $ | — | | | $ | 4 | | | $ | 81 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (18) | | | $ | (18) | |
| | | | | | | |
As of December 31, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 26 | | | $ | 26 | |
Money market mutual funds | 21 | | | — | | | — | | | 21 | |
Investment funds | 2 | | | — | | | — | | | 2 | |
| $ | 23 | | | $ | — | | | $ | 26 | | | $ | 49 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (11) | | | $ | (11) | |
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of September 30, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — |
| | $ | — |
| | $ | 6 |
| | $ | 6 |
|
Money market mutual funds(1) | 142 |
| | — |
| | — |
| | 142 |
|
Investment funds | 2 |
| | — |
| | — |
| | 2 |
|
| $ | 144 |
| | $ | — |
| | $ | 6 |
| | $ | 150 |
|
| | | | | | | |
Liabilities - commodity derivatives | $ | — |
| | $ | — |
| | $ | (6 | ) | | $ | (6 | ) |
| | | | | | | |
As of December 31, 2019 | | | | | | | |
Assets: | | | | | | | |
Money market mutual funds(1) | $ | 10 |
| | $ | — |
| | $ | — |
| | $ | 10 |
|
Investment funds | 2 |
| | — |
| | — |
| | 2 |
|
| $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 12 |
|
| | | | | | | |
Liabilities - commodity derivatives | $ | — |
| | $ | — |
| | $ | (8 | ) | | $ | (8 | ) |
| |
(1) | Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of September 30, 20202021 and December 31, 2019,2020, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.
Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Beginning balance | $ | 25 | | | $ | (44) | | | $ | 15 | | | $ | (8) | |
Changes in fair value recognized in regulatory assets | 6 | | | 13 | | | 11 | | | (31) | |
| | | | | | | |
Settlements | (45) | | | 31 | | | (40) | | | 39 | |
Ending balance | $ | (14) | | | $ | — | | | $ | (14) | | | $ | — | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Beginning balance | $ | (44 | ) | | (11 | ) | | $ | (8 | ) | | $ | 3 |
|
Changes in fair value recognized in regulatory assets | 13 |
| | (13 | ) | | (31 | ) | | (30 | ) |
Settlements | 31 |
| | 6 |
| | 39 |
| | 9 |
|
Ending balance | $ | — |
| | $ | (18 | ) | | $ | — |
| | $ | (18 | ) |
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,498 | | | $ | 3,122 | | | $ | 2,496 | | | $ | 3,245 | |
(8) Commitments and Contingencies
|
| | | | | | | | | | | | | | | |
| As of September 30, 2020 | | As of December 31, 2019 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,496 |
| | $ | 3,210 |
| | $ | 2,351 |
| | $ | 2,848 |
|
| |
(8) | Commitments and Contingencies |
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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 Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
130
| |
(9) | Revenue from Contracts with Customers
|
(9) Revenue from Contracts with Customers
The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 477 | | | $ | 495 | | | $ | 998 | | | $ | 993 | |
Commercial | 129 | | | 127 | | | 323 | | | 317 | |
Industrial | 152 | | | 147 | | | 310 | | | 300 | |
Other | 4 | | | 3 | | | 10 | | | 8 | |
Total fully bundled | 762 | | | 772 | | | 1,641 | | | 1,618 | |
Distribution only service | 6 | | | 8 | | | 17 | | | 20 | |
Total retail | 768 | | | 780 | | | 1,658 | | | 1,638 | |
Wholesale, transmission and other | 28 | | | 21 | | | 57 | | | 48 | |
Total Customer Revenue | 796 | | | 801 | | | 1,715 | | | 1,686 | |
Other revenue | 6 | | | 7 | | | 16 | | | 20 | |
Total revenue | $ | 802 | | | $ | 808 | | | $ | 1,731 | | | $ | 1,706 | |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Customer Revenue: | | | | |
| | |
Retail: | | | | |
| | |
Residential | $ | 495 |
| | $ | 468 |
| | $ | 993 |
| | $ | 934 |
|
Commercial | 127 |
| | 142 |
| | 317 |
| | 346 |
|
Industrial | 147 |
| | 169 |
| | 300 |
| | 351 |
|
Other | 3 |
| | 4 |
| | 8 |
| | 15 |
|
Total fully bundled | 772 |
| | 783 |
| | 1,618 |
| | 1,646 |
|
Distribution only service | 8 |
| | 9 |
| | 20 |
| | 24 |
|
Total retail | 780 |
| | 792 |
| | 1,638 |
| | 1,670 |
|
Wholesale, transmission and other | 21 |
| | 8 |
| | 48 |
| | 39 |
|
Total Customer Revenue | 801 |
| | 800 |
| | 1,686 |
| | 1,709 |
|
Other revenue | 7 |
| | 6 |
| | 20 |
| | 19 |
|
Total revenue | $ | 808 |
| | $ | 806 |
| | $ | 1,706 |
| | $ | 1,728 |
|
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Months of 20202021 and 20192020
Overview
Net income for the third quarter of 20202021 was $194$217 million, an increase of $29$23 million, or 18%12%, compared to 20192020 primarily due to $68$51 million of higherlower operations and maintenance expenses, primarily due to lower earnings sharing and lower net regulatory instructed deferrals and amortizations, $25 million of lower income tax expenses primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021 and $5 million of lower other expense. These increases are offset by $47 million of lower utility margin, primarily due to lower retail rates from the favorable impacts of weather, price impacts from changes in sales mix and2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable regulatory decision. This increase isdecision, partially offset by $30higher transmission revenue, and $11 million of higher operationsdepreciation and maintenance expenses, primarilyamortization, mainly due to a higher accrual for earnings sharing of $20 millionregulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher regulatory-directed debits of $11 million, partially offset by lower long-term incentive plan costs and higher income tax expense of $7 million due to higher pre-tax income.plant placed in service.
Net income for the first nine months of 20202021 was $273$301 million, an increase of $33$28 million, or 14%10%, compared to 20192020 primarily due to $76$67 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations, lower earnings sharing and costs recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation, $38 million of lower income tax expense primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021, $10 million of higher other, net, mainly due to lower pension expense and higher cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and higher interest and dividend income of $5 million. These increases are offset by $66 million of lower utility margin, primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, lower revenue recognized due to a favorable impacts of weather,regulatory decision and an adjustment to regulatory-related revenue deferrals, partially offset by price impacts from changes in sales mix, an increase in the average number of customers and higher transmission revenue, recognized due to a favorable regulatory decision. The increase is offset by $32and $31 million of higher operationsdepreciation and maintenance expenses, primarilyamortization, mainly due to higher regulatory-directed debits of $22 million and a higher accrual for earnings sharing of $14 million, partially offset by lower plant operation and maintenance costs of $9 million, lower long-term incentive plan costsregulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher income tax expense of $8 million due to higher pre-tax income.plant placed in service.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 802 | | | $ | 808 | | | $ | (6) | | (1) | % | | $ | 1,731 | | | $ | 1,706 | | | $ | 25 | | 1 | % |
Cost of fuel and energy | | 328 | | | 287 | | | 41 | | 14 | | | 745 | | | 654 | | | 91 | | 14 | |
Utility margin | | 474 | | | 521 | | | (47) | | (9) | | | 986 | | | 1,052 | | | (66) | | (6) | |
Operations and maintenance | | 88 | | | 139 | | | (51) | | (37) | | | 228 | | | 295 | | | (67) | | (23) | |
Depreciation and amortization | | 103 | | | 92 | | | 11 | | 12 | | | 304 | | | 273 | | | 31 | | 11 | |
Property and other taxes | | 12 | | | 12 | | | — | | — | | | 36 | | | 35 | | | 1 | | 3 | |
Operating income | | $ | 271 | | | $ | 278 | | | $ | (7) | | (3) | % | | $ | 418 | | | $ | 449 | | | $ | (31) | | (7) | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 808 |
| | $ | 806 |
| | $ | 2 |
| — | % | | $ | 1,706 |
| | $ | 1,728 |
| | $ | (22 | ) | (1 | )% |
Cost of fuel and energy | | 287 |
| | 353 |
| | (66 | ) | (19 | ) | | 654 |
| | 752 |
| | (98 | ) | (13 | ) |
Utility margin | | 521 |
| | 453 |
| | 68 |
| 15 |
| | 1,052 |
| | 976 |
| | 76 |
| 8 |
|
Operations and maintenance | | 139 |
| | 109 |
| | 30 |
| 28 |
| | 295 |
| | 263 |
| | 32 |
| 12 |
|
Depreciation and amortization | | 92 |
| | 89 |
| | 3 |
| 3 |
| | 273 |
| | 267 |
| | 6 |
| 2 |
|
Property and other taxes | | 12 |
| | 11 |
| | 1 |
| 9 |
| | 35 |
| | 34 |
| | 1 |
| 3 |
|
Operating income | | $ | 278 |
| | $ | 244 |
| | $ | 34 |
| 14 | % | | $ | 449 |
| | $ | 412 |
| | $ | 37 |
| 9 | % |
Utility Margin
A comparison of Nevada Power's key operating results related to utility margin is as follows:
| | | | Third Quarter | | First Nine Months | | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change | | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | Utility margin (in millions): | | | | | | | | | | | | |
Operating revenue | | $ | 808 |
| | $ | 806 |
| | $ | 2 |
| — | % | | $ | 1,706 |
| | $ | 1,728 |
| | $ | (22 | ) | (1 | )% | Operating revenue | | $ | 802 | | | $ | 808 | | | $ | (6) | | (1) | % | | $ | 1,731 | | | $ | 1,706 | | | $ | 25 | | 1 | % |
Cost of fuel and energy | | 287 |
| | 353 |
| | (66 | ) | (19 | ) | | 654 |
| | 752 |
| | (98 | ) | (13 | ) | Cost of fuel and energy | | 328 | | | 287 | | | 41 | | 14 | | | 745 | | | 654 | | | 91 | | 14 | |
Utility margin | | $ | 521 |
| | $ | 453 |
| | $ | 68 |
| 15 | % | | $ | 1,052 |
| | $ | 976 |
| | $ | 76 |
| 8 | % | Utility margin | | $ | 474 | | | $ | 521 | | | $ | (47) | | (9) | % | | $ | 986 | | | $ | 1,052 | | | $ | (66) | | (6) | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | Sales (GWhs): | |
Residential | | 4,378 |
| | 3,908 |
| | 470 |
| 12 | % | | 8,557 |
| | 7,692 |
| | 865 |
| 11 | % | Residential | | 4,343 | | | 4,378 | | | (35) | | (1) | % | | 8,737 | | | 8,557 | | | 180 | | 2 | % |
Commercial | | 1,471 |
| | 1,569 |
| | (98 | ) | (6 | ) | | 3,553 |
| | 3,698 |
| | (145 | ) | (4 | ) | Commercial | | 1,568 | | | 1,471 | | | 97 | | 7 | | | 3,793 | | | 3,553 | | | 240 | | 7 | |
Industrial | | 1,477 |
| | 1,600 |
| | (123 | ) | (8 | ) | | 3,735 |
| | 4,140 |
| | (405 | ) | (10 | ) | Industrial | | 1,611 | | | 1,477 | | | 134 | | 9 | | | 3,978 | | | 3,735 | | | 243 | | 7 | |
Other | | 48 |
| | 49 |
| | (1 | ) | (2 | ) | | 142 |
| | 143 |
| | (1 | ) | (1 | ) | Other | | 52 | | | 48 | | | 4 | | 8 | | | 144 | | | 142 | | | 2 | | 1 | |
Total fully bundled(1) | | 7,374 |
| | 7,126 |
| | 248 |
| 3 |
| | 15,987 |
| | 15,673 |
| | 314 |
| 2 |
| Total fully bundled(1) | | 7,574 | | | 7,374 | | | 200 | | 3 | | | 16,652 | | | 15,987 | | | 665 | | 4 | |
Distribution only service | | 664 |
| | 786 |
| | (122 | ) | (16 | ) | | 1,776 |
| | 2,006 |
| | (230 | ) | (11 | ) | Distribution only service | | 787 | | | 664 | | | 123 | | 19 | | | 1,923 | | | 1,776 | | | 147 | | 8 | |
Total retail | | 8,038 |
| | 7,912 |
| | 126 |
| 2 |
| | 17,763 |
| | 17,679 |
| | 84 |
| — |
| Total retail | | 8,361 | | | 8,038 | | | 323 | | 4 | | | 18,575 | | | 17,763 | | | 812 | | 5 | |
Wholesale | | 82 |
| | 50 |
| | 32 |
| 64 |
| | 316 |
| | 314 |
| | 2 |
| 1 |
| Wholesale | | 93 | | | 82 | | | 11 | | 13 | | | 266 | | | 316 | | | (50) | | (16) | |
Total GWhs sold | | 8,120 |
| | 7,962 |
| | 158 |
| 2 | % | | 18,079 |
| | 17,993 |
| | 86 |
| — | % | Total GWhs sold | | 8,454 | | | 8,120 | | | 334 | | 4 | % | | 18,841 | | | 18,079 | | | 762 | | 4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 970 |
| | 954 |
| | 16 |
| 2 | % | | 966 |
| | 950 |
| | 16 |
| 2 | % | Average number of retail customers (in thousands) | | 988 | | | 970 | | | 18 | | 2 | % | | 983 | | | 966 | | | 17 | | 2 | % |
| | | | | | | | | | | | | | | |
| | Average revenue per MWh: | | | | | | | | | | | | | | | Average revenue per MWh: | |
Retail - fully bundled(1) | | $ | 104.72 |
| | $ | 109.94 |
| | $ | (5.22 | ) | (5 | )% | | $ | 101.21 |
| | $ | 105.04 |
| | $ | (3.83 | ) | (4 | )% | Retail - fully bundled(1) | | $ | 100.56 | | | $ | 104.72 | | | $ | (4.16) | | (4) | % | | $ | 98.54 | | | $ | 101.21 | | | $ | (2.67) | | (3) | % |
| Wholesale | | $ | 78.36 |
| | $ | 36.63 |
| | $ | 41.73 |
| 114 | % | | $ | 41.28 |
|
| $ | 35.64 |
|
| $ | 5.64 |
| 16 | % | Wholesale | | $ | 90.60 | | | $ | 78.36 | | | $ | 12.24 | | 16 | % | | $ | 61.65 | | | $ | 41.28 | | | $ | 20.37 | | 49 | % |
| | | | | | | | | | | | | | | |
Heating degree days | | — |
| | — |
| | — |
| — |
| | 984 |
| | 1,108 |
| | (124 | ) | (11 | )% | Heating degree days | | — | | | — | | | — | | — | | 1,008 | | | 984 | | | 24 | | 2 | % |
Cooling degree days | | 2,537 |
| | 2,392 |
| | 145 |
| 6 | % | | 3,847 |
| | 3,511 |
| | 336 |
| 10 | % | Cooling degree days | | 2,447 | | | 2,537 | | | (90) | | (4) | % | | 3,930 | | | 3,847 | | | 83 | | 2 | % |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | | Sources of energy (GWhs)(2)(3): | |
Natural gas | | 4,888 |
| | 5,042 |
| | (154 | ) | (3 | )% | | 10,628 |
| | 10,296 |
| | 332 |
| 3 | % | Natural gas | | 4,776 | | | 4,888 | | | (112) | | (2) | % | | 10,857 | | | 10,628 | | | 229 | | 2 | % |
Coal | | — |
| | 377 |
| | (377 | ) | * |
| | — |
| | 968 |
| | (968 | ) | * |
| |
| Renewables | | 18 |
| | 20 |
| | (2 | ) | (10 | ) | | 54 |
| | 50 |
| | 4 |
| 8 |
| Renewables | | 19 | | | 18 | | | 1 | | 6 | | | 55 | | | 54 | | | 1 | | 2 | |
Total energy generated | | 4,906 |
| | 5,439 |
| | (533 | ) | (10 | ) | | 10,682 |
| | 11,314 |
| | (632 | ) | (6 | ) | Total energy generated | | 4,795 | | | 4,906 | | | (111) | | (2) | | | 10,912 | | | 10,682 | | | 230 | | 2 | |
Energy purchased | | 2,366 |
| | 1,787 |
| | 579 |
| 32 |
| | 5,532 |
| | 4,958 |
| | 574 |
| 12 |
| Energy purchased | | 2,727 | | | 2,366 | | | 361 | | 15 | | | 6,186 | | | 5,532 | | | 654 | | 12 | |
Total | | 7,272 |
| | 7,226 |
| | 46 |
| 1 | % | | 16,214 |
| | 16,272 |
| | (58 | ) | — | % | Total | | 7,522 | | | 7,272 | | | 250 | | 3 | % | | 17,098 | | | 16,214 | | | 884 | | 5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Average total cost of energy per MWh(4) | | $ | 39.38 |
| | $ | 48.80 |
| | $ | (9.42 | ) | (19 | )% | | $ | 40.32 |
| | $ | 48.33 |
| | $ | (8.01 | ) | (17 | )% | |
Average cost of energy per MWh(4): | | Average cost of energy per MWh(4): | |
Energy generated | | Energy generated | | $ | 24.71 | | | $ | 11.83 | | | $ | 12.88 | | * | | $ | 21.49 | | | $ | 16.00 | | | $ | 5.49 | | 34 | % |
Energy purchased | | Energy purchased | | $ | 76.77 | | | $ | 96.51 | | | $ | (19.74) | | (20) | % | | $ | 82.53 | | | $ | 87.27 | | | $ | (4.74) | | (5) | % |
* Not meaningful
| |
(1) | (1) Fully bundled includes sales to customers for combined energy, transmission and distribution services. |
| |
(2) | The average total cost of energy per MWh and sources of energy excludes - GWhs and 15 GWhs of coal and 152 GWhs and 199 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes - GWhs and 133 GWhs of coal and 1,180 GWhs and 1,122 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2020 and 2019, respectively. |
| |
(3) | GWh amounts are net of energy used by the related generating facilities. |
| |
(4) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
(2) The average cost of energy per MWh and sources of energy excludes 163 GWhs and 152 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 1,095 GWhs and 1,180 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.
Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020
Utility margin increased $68 decreased $47 million, or 15%9%, for the third quarter of 20202021 compared to 20192020 primarily due to:
•$2127 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,
•$17 million in higher residential customer volumes from the favorable impact of weather,
$143 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 1.6%4.0% primarily due to the favorable impacts of weather,changes in customer usage patterns, offset by the impactsunfavorable impact of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and higher residential customer usage,weather,
•$9 million of higher transmission and wholesale revenue,
$43 million due to higherlower energy efficiency program rates (offset in operations and maintenance expense) and
•$41 million of lower other revenue due to a regulatory amortization of an impact fee that ended December 2020.
The decrease in utility margin was offset by:
•$5 million of higher transmission revenue and
•$3 million due to an increase in the average number of customers, primarily from the residential customer growth mainly from residential customers.class.
Operations and maintenance increased $30 decreased $51 million, or 28%37%, for the third quarter of 20202021 compared to 20192020 primarily due to a higher accrual forlower earnings sharing, of $20 million, higher regulatory-directed debits of $11 million,lower net regulatory instructed deferrals and amortizations, mainly relating to costs recognized for a bill credit to be paiddeferrals in the fourth quarter as a result of the Nevada Power regulatory rate review stipulation, the deferral2020 of the non-labor cost savingsavings from the Navajo generating station retirement which was approved for amortization in 2019the 2020 regulatory rate review with new rates effective January 2021, and timing of the deferral of costsregulatory impacts for the ON Line lease to be returned to customers (offsetcost reallocation, costs recognized in depreciation2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation and amortization and other income (expense)) and higherlower energy efficiency program costs (offset in operating revenue), partially offset by lower long-term incentive plan costs..
Depreciation and amortization increased $3$11 million, or 3%12%, for the third quarter of 20202021 compared to 20192020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service, offset by lower depreciationservice.
Interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is favorable decreased $2 million, or 6%5%, for the third quarter of 20202021 compared to 20192020 primarily due to lower carrying charges on regulatory balances.
Interest and dividend income increased $2 million, or 67%, for the third quarter of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $1 million, or 33%, for the third quarter of 2021 compared to 2020 primarily due to lower pension expense, partially offset by lower cash surrender value of corporate-owned life insurance policies, lower interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense) and lower pension costs.policies.
Income tax expense increased $7 decreased $25 million, or 16%48%, for the third quarter of 20202021 compared to 2019 due to higher pre-tax income.2020. The effective tax rate was 11% in 2021 and 21% in 2020 and 2019.decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.
First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020
Utility margin increased $76 decreased $66 million, or 8%6%, for the first nine months of 20202021 compared to 20192020 primarily due to:
•$32 million in higher residential customer volumes from the favorable impacts of weather,
$2151 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$20 million of lower revenue recognized due to a favorable regulatory decision in 2020,
•$97 million due to higherlower energy efficiency program rates (offset in operations and maintenance expense),
•$86 million due to an adjustment to regulatory-related revenue deferrals and
•$3 million due to a regulatory amortization of an impact fee that ended December 2020.
The decrease in utility margin was offset by:
•$11 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 0.5%4.6% primarily due to favorable changes in customer usage patterns and the favorable impactsimpact of weather, offset by
•$5 million due to an increase in the impactsaverage number of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and highercustomers, primarily from the residential customer usage,class and
•$75 million of higher transmission and wholesale revenue andrevenue.
$4 million due to customer growth, mainly residential.
The increase in utility margin was offset by:
$5 million of higher revenue reductions related to customer service agreements.
Operations and maintenance increased $32 decreased $67 million, or 12%23%, for the first nine months of 20202021 compared to 20192020 primarily due to higher regulatory-directed debits of $22 million,lower net regulatory instructed deferrals and amortizations, mainly relating to the deferraldeferrals in 2020 of the non-labor cost savingsavings from the Navajo generating station retirement which was approved for amortization in 2019, the deferral2020 regulatory rate review with new rates effective January 2021, and timing of coststhe regulatory impacts for the ON Line lease to be returned to customers due to the regulatory-directedcost reallocation, of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) and costs recognized for a bill credit to be paid in the fourth quarter as a result of the Nevada Power regulatory rate review stipulation, a higher accrual forlower earnings sharing, of $14 million and higherlower energy efficiency program costs (offset in operating revenue), partially offset by lower plant operation and maintenance costs and lower long-term incentive plan costs.recognized in 2020 for a bill credit paid as a result of the 2020 regulatory rate review stipulation.
Depreciation and amortizationincreased $6$31 million, or 2%11%, for the first nine months of 20202021 compared to 20192020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service, offset by lower depreciationservice.
Interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is favorable $4 decreased $7 million, or 4%6%, for the first nine months of 20202021 compared to 20192020 primarily due to lower interest expensecarrying charges on the ON Line lease due to the regulatory-directed reallocationregulatory balances of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense), lower pension costs$5 million and lower interest expense on long-term debtdebt.
Interest and dividend income increased $5 million, or 63%, for the first nine months of 2021 compared to 2020 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net increased $10 million for the first nine months of 2021 compared to 2020 primarily due to lower interest rates, offset by lowerpension expense of $6 million and higher cash surrender value of corporate-owned life insurance policies and lower other income due to a licensing agreement with a third party in 2019.policies.
Income tax expense increased $8 decreased $38 million, or 12%(51)%, for the first nine months of 20202021 compared to 2019 due to higher pre-tax income.2020. The effective tax rate was 11% in 2021 and 21% in 2020 and 22% in 2019.decreased primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021.
Liquidity and Capital Resources
As of September 30, 2020,2021, Nevada Power's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 85 | |
Credit facility | | 400 | |
| | |
| | |
| | |
| | |
Total net liquidity | | $ | 485 | |
Credit facility: | | |
Maturity date | | 2024 |
|
| | | | |
Cash and cash equivalents | | $ | 152 |
|
Credit facility | | 400 |
|
Total net liquidity | | $ | 552 |
|
Credit facility: | | |
Maturity date | | 2022 |
|
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $406$405 million and $555$406 million, respectively. The change was primarily due to lowerthe timing of payments for fuel and energy costs and higher payments for income taxes, partially offset by higher collections from customers, the timing of payments for operating costs, higher payments for generation long-term service agreements, decreasedincreased collections of customer advances and lower proceeds from a licensing agreement with a third party in 2019, partially offset by lower payments for income taxes, a decrease in payments for fuel costs and lower interest payments for long-term debt.inventory purchases.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $(317)$(322) million and $(281)$(317) million, respectively. The change was primarily due to increased capital expenditures, partially offset by higher proceeds from sale of assets primarily related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific.expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $46$(25) million and $(111)$46 million, respectively. The change was primarily due to greaterlower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt and lower dividends paid to NV Energy, Inc., partially offset by higher repayments of long-term debt.
Long-Term Debt
In May 2020, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County Pollution Control Refunding Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County Pollution Control Refunding Revenue Bonds, Series 2017, due 2036. The Series 2017A bond was offered at a fixed rate of 1.875% and the Series 2017B and Series 2017 bonds were offered at a fixed rate of 1.65%.
In January 2020, Nevada Power issued $425 million of 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 and $300 million of 3.125% General and Refunding Mortgage Notes, Series EE, due 2050. Nevada Power used the net proceeds for the early redemption of $575 million of its 2.75% General and Refunding Mortgage Notes, Series BB, due April 2020 and for general corporate purposes.
Debt Authorizations
Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.2 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.
Future Uses of Cash
Nevada Power 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; 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. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
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):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Electric distribution | $ | 182 | | | $ | 137 | | | $ | 194 | |
Electric transmission | 27 | | | 38 | | | 67 | |
Solar generation | — | | | 7 | | | 21 | |
Other | 134 | | | 141 | | | 208 | |
Total | $ | 343 | | | $ | 323 | | | $ | 490 | |
|
| | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2019 | | 2020 | | 2020 |
| | | | | |
Generation development | $ | — |
| | $ | 17 |
| | $ | 20 |
|
Distribution | 148 |
| | 182 |
| | 229 |
|
Transmission system investment | 18 |
| | 13 |
| | 21 |
|
Other | 117 |
| | 131 |
| | 203 |
|
Total | $ | 283 |
| | $ | 343 |
| | $ | 473 |
|
Nevada Power's approved Fourth Amendment to the 2018 Joint IRP included an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates may change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include investments relatedthe following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects thatprimarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific. In this project, the company proposed to build a 350-mile, 525 kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to build a 235-mile, 525 kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West. Operating expenditures consist of routine expenditures for generation, transmission distribution and other infrastructure needed to serve existing and expected demand.
•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, that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Contractual Obligations
As of September 30, 2020,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2019.2020.
In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by Nevada Power. While COVID-19 has impacted Nevada Power's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, the state of Nevada instituted a "stay-at-home" order requiring non-essential businesses, including casinos, to remain closed, which impacted Nevada Power's customers and, therefore, their needs and usage patterns for electricity as evidenced by a reduction in weather-normalized consumption due to COVID-19 through September 2020 compared to the same period in 2019. The state of Nevada has since moved to a long-term recovery plan with most businesses, including casinos, opening subject to capacity and other operating limitations that will be revised as the state and counties meet certain metrics. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity may continue to occur, particularly in the commercial and industrial classes as well as distribution only service customers. Due to regulatory requirements and voluntary actions taken by Nevada Power related to customer collection activity and suspension of disconnections for non-payment, Nevada Power has seen delays and reductions in cash receipts, from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. The PUCN has approved the deferral of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.
Nevada Power's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system. In response to the effects of COVID-19, Nevada Power has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.
Regulatory Matters
Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local 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 Nevada Power's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, 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 the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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 long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2019.2020. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2019.
2020.
Sierra Pacific Power Company 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 Shareholder of
Sierra Pacific Power Company
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of September 30, 2020,2021, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 20202021 and 2019,2020, and of cash flows for the nine-month periods ended September 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 Sierra Pacific as of December 31, 2019,2020, and the related consolidated statements of operations, changes in shareholder's 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 Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific 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
Las Vegas, Nevada
November 6, 20205, 2021
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 14 | | | $ | 19 | |
Trade receivables, net | 118 | | | 97 | |
| | | |
Inventories | 68 | | | 77 | |
| | | |
Regulatory assets | 168 | | | 67 | |
| | | |
Other current assets | 48 | | | 45 | |
Total current assets | 416 | | | 305 | |
| | | |
Property, plant and equipment, net | 3,265 | | | 3,164 | |
| | | |
Regulatory assets | 265 | | | 267 | |
Other assets | 184 | | | 183 | |
| | | |
Total assets | $ | 4,130 | | | $ | 3,919 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 121 | | | $ | 108 | |
Accrued interest | 11 | | | 14 | |
Accrued property, income and other taxes | 18 | | | 14 | |
Short-term debt | 127 | | | 45 | |
| | | |
| | | |
Regulatory liabilities | 23 | | | 34 | |
Customer deposits | 15 | | | 15 | |
Other current liabilities | 31 | | | 25 | |
Total current liabilities | 346 | | | 255 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
Finance lease obligations | 116 | | | 121 | |
Regulatory liabilities | 446 | | | 463 | |
Deferred income taxes | 396 | | | 374 | |
Other long-term liabilities | 144 | | | 131 | |
Total liabilities | 2,612 | | | 2,508 | |
| | | |
Commitments and contingencies (Note 8) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
Additional paid-in capital | 1,111 | | | 1,111 | |
Retained earnings | 408 | | | 301 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,518 | | | 1,411 | |
| | | |
Total liabilities and shareholder's equity | $ | 4,130 | | | $ | 3,919 | |
| | | |
The accompanying notes are an integral part of the consolidated financial statements. |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 22 |
| | $ | 27 |
|
Trade receivables, net | 102 |
| | 109 |
|
Income taxes receivable | 2 |
| | 14 |
|
Inventories | 75 |
| | 57 |
|
Regulatory assets | 50 |
| | 12 |
|
Other current assets | 29 |
| | 20 |
|
Total current assets | 280 |
| | 239 |
|
| | | |
Property, plant and equipment, net | 3,143 |
| | 3,075 |
|
Regulatory assets | 287 |
| | 283 |
|
Other assets | 159 |
| | 74 |
|
| | | |
Total assets | $ | 3,869 |
| | $ | 3,671 |
|
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 133 |
| | $ | 103 |
|
Accrued interest | 11 |
| | 14 |
|
Accrued property, income and other taxes | 12 |
| | 12 |
|
Regulatory liabilities | 44 |
| | 49 |
|
Customer deposits | 16 |
| | 21 |
|
Other current liabilities | 36 |
| | 21 |
|
Total current liabilities | 252 |
| | 220 |
|
| | | |
Long-term debt | 1,164 |
| | 1,135 |
|
Finance lease obligations | 123 |
| | 40 |
|
Regulatory liabilities | 460 |
| | 489 |
|
Deferred income taxes | 362 |
| | 347 |
|
Other long-term liabilities | 118 |
| | 120 |
|
Total liabilities | 2,479 |
| | 2,351 |
|
| | | |
Commitments and contingencies (Note 9) |
| |
|
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — |
| | — |
|
Additional paid-in capital | 1,111 |
| | 1,111 |
|
Retained earnings | 280 |
| | 210 |
|
Accumulated other comprehensive loss, net | (1 | ) | | (1 | ) |
Total shareholder's equity | 1,390 |
| | 1,320 |
|
| | | |
Total liabilities and shareholder's equity | $ | 3,869 |
| | $ | 3,671 |
|
| | | |
The accompanying notes are an integral part of the financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 266 | | | $ | 220 | | | $ | 636 | | | $ | 569 | |
Regulated natural gas | 16 | | | 15 | | | 75 | | | 83 | |
Total operating revenue | 282 | | | 235 | | | 711 | | | 652 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 120 | | | 81 | | | 295 | | | 233 | |
Cost of natural gas purchased for resale | 6 | | | 4 | | | 35 | | | 44 | |
Operations and maintenance | 40 | | | 40 | | | 117 | | | 123 | |
Depreciation and amortization | 35 | | | 36 | | | 107 | | | 104 | |
Property and other taxes | 6 | | | 6 | | | 18 | | | 17 | |
Total operating expenses | 207 | | | 167 | | | 572 | | | 521 | |
| | | | | | | |
Operating income | 75 | | | 68 | | | 139 | | | 131 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (14) | | | (14) | | | (41) | | | (42) | |
Allowance for borrowed funds | 1 | | | — | | | 2 | | | 1 | |
Allowance for equity funds | 2 | | | 1 | | | 5 | | | 3 | |
Interest and dividend income | 3 | | | 1 | | | 6 | | | 3 | |
Other, net | 3 | | | 2 | | | 9 | | | 4 | |
Total other income (expense) | (5) | | | (10) | | | (19) | | | (31) | |
| | | | | | | |
Income before income tax expense | 70 | | | 58 | | | 120 | | | 100 | |
Income tax expense | 8 | | | 6 | | | 13 | | | 10 | |
Net income | $ | 62 | | | $ | 52 | | | $ | 107 | | | $ | 90 | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 220 |
| | $ | 232 |
| | $ | 569 |
| | $ | 586 |
|
Regulated natural gas | 15 |
| | 16 |
| | 83 |
| | 75 |
|
Total operating revenue | 235 |
| | 248 |
| | 652 |
| | 661 |
|
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 81 |
| | 93 |
| | 233 |
| | 254 |
|
Cost of natural gas purchased for resale | 4 |
| | 6 |
| | 44 |
| | 35 |
|
Operations and maintenance | 40 |
| | 46 |
| | 123 |
| | 130 |
|
Depreciation and amortization | 36 |
| | 31 |
| | 104 |
| | 94 |
|
Property and other taxes | 6 |
| | 5 |
| | 17 |
| | 17 |
|
Total operating expenses | 167 |
| | 181 |
| | 521 |
| | 530 |
|
| | | | | | | |
Operating income | 68 |
| | 67 |
| | 131 |
| | 131 |
|
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (14 | ) | | (12 | ) | | (42 | ) | | (36 | ) |
Allowance for borrowed funds | — |
| | — |
| | 1 |
| | 1 |
|
Allowance for equity funds | 1 |
| | — |
| | 3 |
| | 2 |
|
Other, net | 3 |
| | 1 |
| | 7 |
| | 4 |
|
Total other income (expense) | (10 | ) | | (11 | ) | | (31 | ) | | (29 | ) |
| | | | | | | |
Income before income tax expense | 58 |
| | 56 |
| | 100 |
| | 102 |
|
Income tax expense | 6 |
| | 12 |
| | 10 |
| | 22 |
|
Net income | $ | 52 |
| | $ | 44 |
| | $ | 90 |
| | $ | 80 |
|
| | | | | | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Additional | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | |
Balance, June 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 228 | | | $ | (1) | | | $ | 1,338 | |
Net income | | — | | | — | | | — | | | 52 | | | — | | | 52 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 280 | | | $ | (1) | | | $ | 1,390 | |
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 210 | | | $ | (1) | | | $ | 1,320 | |
Net income | | — | | | — | | | — | | | 90 | | | — | | | 90 | |
Dividends declared | | — | | | — | | | — | | | (20) | | | — | | | (20) | |
| | | | | | | | | | | | |
Balance, September 30, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 280 | | | $ | (1) | | | $ | 1,390 | |
| | | | | | | | | | | | |
Balance, June 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 346 | | | $ | (1) | | | $ | 1,456 | |
Net income | | — | | | — | | | — | | | 62 | | | — | | | 62 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 408 | | | $ | (1) | | | $ | 1,518 | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | |
Net income | | — | | | — | | | — | | | 107 | | | — | | | 107 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, September 30, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 408 | | | $ | (1) | | | $ | 1,518 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | Accumulated | | |
| | | | | | Additional | | | | Other | | Total |
| | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| | | | | | | | | | | | |
Balance, June 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 143 |
| | $ | — |
| | $ | 1,254 |
|
Net income | | — |
| | — |
| | — |
| | 44 |
| | — |
| | 44 |
|
Balance, September 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 187 |
| | $ | — |
| | $ | 1,298 |
|
| | | | | | | | | | | | |
Balance, December 31, 2018 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 153 |
| | $ | — |
| | $ | 1,264 |
|
Net income | | — |
| | — |
| | — |
| | 80 |
| | — |
| | 80 |
|
Dividends declared | | — |
| | — |
| | — |
| | (46 | ) | | — |
| | (46 | ) |
Balance, September 30, 2019 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 187 |
| | $ | — |
| | $ | 1,298 |
|
| | | | | | | | | | | | |
Balance, June 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 228 |
| | $ | (1 | ) | | $ | 1,338 |
|
Net income | | — |
| | — |
| | — |
| | 52 |
| | — |
| | 52 |
|
Balance, September 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 280 |
| | $ | (1 | ) | | $ | 1,390 |
|
| | | | | | | | | | | | |
Balance, December 31, 2019 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 210 |
| | $ | (1 | ) | | $ | 1,320 |
|
Net income | | — |
| | — |
| | — |
| | 90 |
| | — |
| | 90 |
|
Dividends declared | | — |
| | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
Balance, September 30, 2020 | | 1,000 |
| | $ | — |
| | $ | 1,111 |
| | $ | 280 |
| | $ | (1 | ) | | $ | 1,390 |
|
| | | | | | | | | | | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 107 | | | $ | 90 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
Depreciation and amortization | 107 | | | 104 | |
Allowance for equity funds | (5) | | | (3) | |
Changes in regulatory assets and liabilities | (30) | | | (30) | |
Deferred income taxes and amortization of investment tax credits | 10 | | | 3 | |
Deferred energy | (95) | | | (5) | |
Amortization of deferred energy | 12 | | | (6) | |
Other, net | (1) | | | — | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (25) | | | (83) | |
Inventories | 9 | | | (18) | |
Accrued property, income and other taxes | 3 | | | 8 | |
Accounts payable and other liabilities | 21 | | | 119 | |
Net cash flows from operating activities | 113 | | | 179 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (196) | | | (192) | |
| | | |
| | | |
Net cash flows from investing activities | (196) | | | (192) | |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | — | | | 30 | |
Net proceeds from short-term debt | 82 | | | — | |
| | | |
Dividends paid | — | | | (20) | |
Other, net | (5) | | | (3) | |
Net cash flows from financing activities | 77 | | | 7 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (6) | | | (6) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 26 | | | 32 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 20 | | | $ | 26 | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements. |
|
| | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2020 | | 2019 |
Cash flows from operating activities: | | | |
Net income | $ | 90 |
| | $ | 80 |
|
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 104 |
| | 94 |
|
Allowance for equity funds | (3 | ) | | (2 | ) |
Changes in regulatory assets and liabilities | (30 | ) | | 30 |
|
Deferred income taxes and amortization of investment tax credits | 3 |
| | (5 | ) |
Deferred energy | (5 | ) | | 7 |
|
Amortization of deferred energy | (6 | ) | | (5 | ) |
Other, net | — |
| | (3 | ) |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (83 | ) | | (3 | ) |
Inventories | (18 | ) | | (7 | ) |
Accrued property, income and other taxes | 8 |
| | 10 |
|
Accounts payable and other liabilities | 119 |
| | (7 | ) |
Net cash flows from operating activities | 179 |
| | 189 |
|
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (192 | ) | | (165 | ) |
Other, net | — |
| | 1 |
|
Net cash flows from investing activities | (192 | ) | | (164 | ) |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | 30 |
| | 125 |
|
Repayments of long-term debt | — |
| | (109 | ) |
Dividends paid | (20 | ) | | (46 | ) |
Other, net | (3 | ) | | (3 | ) |
Net cash flows from financing activities | 7 |
| | (33 | ) |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (6 | ) | | (8 | ) |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 32 |
| | 76 |
|
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 26 |
| | $ | 68 |
|
| | | |
The accompanying notes are an integral part of these financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is 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 September 30, 20202021 and for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 20202021 and 2019.2020. The results of operations for the three- and nine-month periods ended September 30, 20202021 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 Sierra Pacific'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 Sierra Pacific's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2020.2021.
Coronavirus Disease 2019 ("COVID-19")
(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and on economic conditions in the United States. COVID-19 has impacted many of Sierra Pacific's customers ranging from high unemployment levels, an inability to pay bills and business closures or operating at reduced capacity levels. While COVID-19 has impacted Sierra Pacific's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. These impacts include, but are not limited to, lower operating revenue from reductions in the consumption of electricity by retail utility customers, particularly in the commercial, industrial and distribution only service customer classes as the longer term impacts of COVID-19 and related customer and governmental responses remain uncertain, and higher bad debt expense resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers. The duration and extent of COVID-19 and its future impact on Sierra Pacific's business cannot be reasonably estimated at this time. Accordingly, significant estimates used in the preparation of Sierra Pacific's unaudited Financial Statements, including those associated with evaluations of certain long-lived assets for impairment, expected credit losses on amounts owed to Sierra Pacific and potential regulatory recovery of certain costs may be subject to significant adjustments in future periods.
In March 2020, the Public Utilities Commission of Nevada ("PUCN") issued an emergency order for Sierra Pacific to establish a regulatory asset account related to 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.
| |
(2)
| Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
|
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 as of September 30, 20202021 and December 31, 2019,2020, consist of funds restricted by the PUCNPublic Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 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):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 14 | | | $ | 19 | |
Restricted cash and cash equivalents included in other current assets | 6 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 20 | | | $ | 26 | |
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Cash and cash equivalents | $ | 22 |
| | $ | 27 |
|
Restricted cash and cash equivalents included in other current assets | 4 |
| | 5 |
|
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 26 |
| | $ | 32 |
|
(3) Property, Plant and Equipment, Net
| |
(3) | Property, Plant and Equipment, Net
|
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| Depreciable Life | | September 30, | | December 31, |
| | 2021 | | 2020 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,140 | | | $ | 1,130 | |
Electric transmission | 50 - 100 years | | 914 | | | 908 | |
Electric distribution | 20 - 100 years | | 1,806 | | | 1,754 | |
Electric general and intangible plant | 5 - 70 years | | 199 | | | 189 | |
Natural gas distribution | 35 - 70 years | | 433 | | | 429 | |
Natural gas general and intangible plant | 5 - 70 years | | 15 | | | 15 | |
Common general | 5 - 70 years | | 361 | | | 355 | |
Utility plant | | | 4,868 | | | 4,780 | |
Accumulated depreciation and amortization | | | (1,834) | | | (1,755) | |
Utility plant, net | | | 3,034 | | | 3,025 | |
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | — | | | 2 | |
Plant, net | | | 3,034 | | | 3,027 | |
Construction work-in-progress | | | 231 | | | 137 | |
Property, plant and equipment, net | | | $ | 3,265 | | | $ | 3,164 | |
(4) Recent Financing Transactions
|
| | | | | | | | | |
| | | As of |
| Depreciable Life | | September 30, | | December 31, |
| | 2020 | | 2019 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,129 |
| | $ | 1,133 |
|
Electric transmission | 50 - 100 years | | 911 |
| | 840 |
|
Electric distribution | 20 - 100 years | | 1,724 |
| | 1,669 |
|
Electric general and intangible plant | 5 - 70 years | | 187 |
| | 178 |
|
Natural gas distribution | 35 - 70 years | | 424 |
| | 417 |
|
Natural gas general and intangible plant | 5 - 70 years | | 14 |
| | 14 |
|
Common general | 5 - 70 years | | 344 |
| | 338 |
|
Utility plant | | | 4,733 |
| | 4,589 |
|
Accumulated depreciation and amortization | | | (1,733 | ) | | (1,629 | ) |
Utility plant, net | | | 3,000 |
| | 2,960 |
|
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | 2 |
| | 2 |
|
Plant, net | | | 3,002 |
| | 2,962 |
|
Construction work-in-progress | | | 141 |
| | 113 |
|
Property, plant and equipment, net | | | $ | 3,143 |
| | $ | 3,075 |
|
Credit Facilities
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Statements of Operations but rather is deferred and recorded as a regulatory asset on the Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.
Regulatory Rate Review
In June 2019,2021, Sierra Pacific filed an electric regulatory rate reviewamended and restated its existing $250 million secured credit facility expiring in June 2022 with the PUCN.no remaining one-year extension options. 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 a 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 the 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.
Natural Disaster Protection Plan
In May 2019, Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law, which requires Sierra Pacific to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations in January 2020, that require Sierra Pacific 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 Sierra Pacific to prevent or respond to a fire or other natural disaster. The expenditures incurred by Sierra Pacific in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with Sierra Pacific filing an application for recovery on or before March 1 of each year. Sierra Pacific 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.
2017 Tax Reform
In February 2018, Sierra Pacific made a filing 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 Sierra Pacific. The new rates were effective April 1, 2018. The orderamendment extended the procedural scheduleexpiration date to allow parties additional discovery relevantJune 2024 and increased the available maturity extension options to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Sierra Pacific 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, Sierra Pacific 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, Sierra Pacific 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, Sierra Pacific filed a notice of appeal to the Nevada Supreme Court of the district court's order. Sierra Pacific has 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.
| |
(5) | Recent Financing Transactions
|
Long-Term Debt
In September 2020, Sierra Pacific entered into a re-offering of $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036. The series was offered at a fixed rate of 0.625% for a two-year termunlimited number, subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.lender consent.
In April 2020, Sierra Pacific entered into a re-offering of the following series of tax-exempt bonds that were held in treasury: $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $59 million of its Washoe County Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031; and $20 million of its Humboldt County Water Facilities Refunding Revenue Bonds, Series 2016A, due 2029. The interest rate mode of these bonds was changed to a variable rate from an annual fixed rate. Sierra Pacific holds the Washoe and Humboldt County Series 2016A bonds and they could be issued at a future date if deemed necessary.
(6)(5)Income Taxes
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:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (10) | | | (11) | | | (10) | | | (10) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Other | — | | | — | | | — | | | (1) | |
Effective income tax rate | 11 | % | | 10 | % | | 11 | % | | 10 | % |
|
| | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
Effects of ratemaking | (11 | ) | | — |
| | (10 | ) | | — |
|
Other | — |
| | — |
| | (1 | ) | | 1 |
|
Effective income tax rate | 10 | % | | 21 | % | | 10 | % | | 22 | % |
Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2020.
147
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(7) | Employee Benefit Plans
|
(6) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $1 million to the Other Postretirement Plans for the nine-month period ended September 30, 2021. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts payable toreceivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Qualified Pension Plan: | | | |
| | | |
Other non-current assets | $ | 31 | | | $ | 26 | |
| | | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
| | | |
| | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (8) | |
| | | |
Other Postretirement Plans: | | | |
| | | |
| | | |
| | | |
Other long-term liabilities | (13) | | | (13) | |
(7) Fair Value Measurements
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Qualified Pension Plan: | | | |
Other long-term liabilities | $ | 2 |
| | $ | 4 |
|
| | | |
Non-Qualified Pension Plans: | | | |
Other current liabilities | 1 |
| | 1 |
|
Other long-term liabilities | 7 |
| | 8 |
|
| | | |
Other Postretirement Plans: | | | |
Other long-term liabilities | 7 |
| | 7 |
|
| |
(8) | Fair Value Measurements
|
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of September 30, 2021 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
Money market mutual funds | 11 | | | — | | | — | | | 11 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 12 | | | $ | — | | | $ | 2 | | | $ | 14 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | |
| | | | | | | |
As of December 31, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 9 | | | $ | 9 | |
Money market mutual funds | 17 | | | — | | | — | | | 17 | |
| | | | | | | |
| $ | 17 | | | $ | — | | | $ | 9 | | | $ | 26 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (2) | | | $ | (2) | |
|
| | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of September 30, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — |
| | $ | — |
|
| $ | 2 |
| | $ | 2 |
|
Money market mutual funds(1) | 18 |
| | — |
| | — |
| | 18 |
|
Investment funds | 1 |
| | — |
| | — |
| | 1 |
|
| $ | 19 |
| | $ | — |
| | $ | 2 |
| | $ | 21 |
|
| | | | | | | |
As of December 31, 2019 | | | | | | | |
Assets - money market mutual funds(1) | $ | 25 |
| | $ | — |
| | $ | — |
| | $ | 25 |
|
| | | | | | | |
Liabilities - commodity derivatives | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | (1 | ) |
| |
(1) | Amounts are included in cash and cash equivalents on the Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Sierra Pacific's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of September 30, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,164 | | | $ | 1,328 | | | $ | 1,164 | | | $ | 1,358 | |
|
| | | | | | | | | | | | | | | |
| As of September 30, 2020 | | As of December 31, 2019 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 1,164 |
| | $ | 1,362 |
| | $ | 1,135 |
| | $ | 1,258 |
|
(8) Commitments and Contingencies
| |
(9) | Commitments and Contingencies
|
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, 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 Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
| |
(10) | Revenue from Contracts with Customers
|
(9) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 1110 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: | | | | | | | | | | | |
Retail: | | | | | | | | | | | |
Residential | $ | 91 | | | $ | 11 | | | $ | 102 | | | $ | 76 | | | $ | 11 | | | $ | 87 | |
Commercial | 84 | | | 3 | | | 87 | | | 71 | | | 3 | | | 74 | |
Industrial | 71 | | | 2 | | | 73 | | | 57 | | | 1 | | | 58 | |
Other | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
Total fully bundled | 247 | | | 16 | | | 263 | | | 205 | | | 15 | | | 220 | |
Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
Total retail | 248 | | | 16 | | | 264 | | | 206 | | | 15 | | | 221 | |
Wholesale, transmission and other | 18 | | | — | | | 18 | | | 13 | | | — | | | 13 | |
Total Customer Revenue | 266 | | | 16 | | | 282 | | | 219 | | | 15 | | | 234 | |
Other revenue | — | | | — | | | — | | | 1 | | | — | | | 1 | |
Total revenue | $ | 266 | | | $ | 16 | | | $ | 282 | | | $ | 220 | | | $ | 15 | | | $ | 235 | |
| | | Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2021 | | 2020 |
| Electric |
| Natural Gas |
| Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: |
|
|
|
|
| |
| |
| | | Customer Revenue: | | | | | | | | | | | |
Retail: |
|
|
|
|
| |
| |
| | | Retail: | |
Residential | $ | 76 |
|
| $ | 11 |
|
| $ | 87 |
| | $ | 75 |
| | $ | 11 |
| | $ | 86 |
| Residential | $ | 229 | | | $ | 50 | | | $ | 279 | | | $ | 208 | | | $ | 54 | | | $ | 262 | |
Commercial | 71 |
|
| 3 |
|
| 74 |
| | 80 |
| | 3 |
| | 83 |
| Commercial | 202 | | | 18 | | | 220 | | | 183 | | | 20 | | | 203 | |
Industrial | 57 |
|
| 1 |
|
| 58 |
| | 58 |
| | 1 |
| | 59 |
| Industrial | 151 | | | 6 | | | 157 | | | 132 | | | 8 | | | 140 | |
Other | 1 |
|
| — |
|
| 1 |
| | 2 |
| | — |
| | 2 |
| Other | 4 | | | — | | | 4 | | | 3 | | | — | | | 3 | |
Total fully bundled | 205 |
|
| 15 |
|
| 220 |
| | 215 |
| | 15 |
| | 230 |
| Total fully bundled | 586 | | | 74 | | | 660 | | | 526 | | | 82 | | | 608 | |
Distribution only service | 1 |
|
| — |
|
| 1 |
| | 1 |
| | — |
| | 1 |
| Distribution only service | 2 | | | — | | | 2 | | | 3 | | | — | | | 3 | |
Total retail | 206 |
|
| 15 |
|
| 221 |
| | 216 |
| | 15 |
| | 231 |
| Total retail | 588 | | | 74 | | | 662 | | | 529 | | | 82 | | | 611 | |
Wholesale, transmission and other | 13 |
|
| — |
|
| 13 |
| | 16 |
| | — |
| | 16 |
| Wholesale, transmission and other | 46 | | | — | | | 46 | | | 37 | | | — | | | 37 | |
Total Customer Revenue | 219 |
|
| 15 |
|
| 234 |
| | 232 |
| | 15 |
| | 247 |
| Total Customer Revenue | 634 | | | 74 | | | 708 | | | 566 | | | 82 | | | 648 | |
Other revenue | 1 |
|
| — |
|
| 1 |
| | — |
| | 1 |
| | 1 |
| Other revenue | 2 | | | 1 | | | 3 | | | 3 | | | 1 | | | 4 | |
Total revenue | $ | 220 |
|
| $ | 15 |
|
| $ | 235 |
| | $ | 232 |
| | $ | 16 |
| | $ | 248 |
| Total revenue | $ | 636 | | | $ | 75 | | | $ | 711 | | | $ | 569 | | | $ | 83 | | | $ | 652 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2020 | | 2019 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: | | | | | | | | | | | |
Retail: | | | | | | | | | | | |
Residential | $ | 208 |
| | $ | 54 |
| | $ | 262 |
| | $ | 201 |
| | $ | 49 |
| | $ | 250 |
|
Commercial | 183 |
| | 20 |
| | 203 |
| | 188 |
| | 18 |
| | 206 |
|
Industrial | 132 |
| | 8 |
| | 140 |
| | 143 |
| | 6 |
| | 149 |
|
Other | 3 |
| | — |
| | 3 |
| | 5 |
| | — |
| | 5 |
|
Total fully bundled | 526 |
| | 82 |
| | 608 |
| | 537 |
| | 73 |
| | 610 |
|
Distribution only service | 3 |
| | — |
| | 3 |
| | 3 |
| | — |
| | 3 |
|
Total retail | 529 |
| | 82 |
| | 611 |
| | 540 |
| | 73 |
| | 613 |
|
Wholesale, transmission and other | 37 |
| | — |
| | 37 |
| | 44 |
| | — |
| | 44 |
|
Total Customer Revenue | 566 |
| | 82 |
| | 648 |
| | 584 |
| | 73 |
| | 657 |
|
Other revenue | 3 |
| | 1 |
| | 4 |
| | 2 |
| | 2 |
| | 4 |
|
Total revenue | $ | 569 |
| | $ | 83 |
| | $ | 652 |
| | $ | 586 |
| | $ | 75 |
| | $ | 661 |
|
(10)Segment Information
Sierra Pacific has identified two2 reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.
The following tables provide information on a reportable segment basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 266 | | | $ | 220 | | | $ | 636 | | | $ | 569 | |
Regulated natural gas | 16 | | | 15 | | | 75 | | | 83 | |
Total operating revenue | $ | 282 | | | $ | 235 | | | $ | 711 | | | $ | 652 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 74 | | | $ | 66 | | | $ | 126 | | | $ | 119 | |
Regulated natural gas | 1 | | | 2 | | | 13 | | | 12 | |
Total operating income | 75 | | | 68 | | | 139 | | | 131 | |
Interest expense | (14) | | | (14) | | | (41) | | | (42) | |
Allowance for borrowed funds | 1 | | | — | | | 2 | | | 1 | |
Allowance for equity funds | 2 | | | 1 | | | 5 | | | 3 | |
Interest and dividend income | 3 | | | 1 | | | 6 | | | 3 | |
Other, net | 3 | | | 2 | | | 9 | | | 4 | |
Income before income tax expense | $ | 70 | | | $ | 58 | | | $ | 120 | | | $ | 100 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | As of |
| | | | | September 30, | | December 31, |
| | | | | 2021 | | 2020 |
Assets: | | | | | | | |
Regulated electric | | | | | $ | 3,744 | | | $ | 3,540 | |
Regulated natural gas | | | | | 354 | | | 342 | |
Other(1) | | | | | 32 | | | 37 | |
Total assets | | | | | $ | 4,130 | | | $ | 3,919 | |
(1) Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.
|
| | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Operating revenue: | | | | | | | |
Regulated electric | $ | 220 |
| | $ | 232 |
| | $ | 569 |
| | $ | 586 |
|
Regulated natural gas | 15 |
| | 16 |
| | 83 |
| | 75 |
|
Total operating revenue | $ | 235 |
| | $ | 248 |
| | $ | 652 |
| | $ | 661 |
|
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | $ | 66 |
| | $ | 67 |
| | $ | 119 |
| | $ | 119 |
|
Regulated natural gas | 2 |
| | — |
| | 12 |
| | 12 |
|
Total operating income | 68 |
| | 67 |
| | 131 |
| | 131 |
|
Interest expense | (14 | ) | | (12 | ) | | (42 | ) | | (36 | ) |
Allowance for borrowed funds | — |
| | — |
| | 1 |
| | 1 |
|
Allowance for equity funds | 1 |
| | — |
| | 3 |
| | 2 |
|
Other, net | 3 |
| | 1 |
| | 7 |
| | 4 |
|
Income before income tax expense | $ | 58 |
| | $ | 56 |
| | $ | 100 |
| | $ | 102 |
|
|
| | | | | | | |
| As of |
| September 30, | | December 31, |
| 2020 | | 2019 |
Assets: | | | |
Regulated electric | $ | 3,515 |
| | $ | 3,319 |
|
Regulated natural gas | 318 |
| | 308 |
|
Other(1) | 36 |
| | 44 |
|
Total assets | $ | 3,869 |
| | $ | 3,671 |
|
| |
(1) | Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments. |
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Monthsof 20202021 and 20192020
Overview
Net income for the third quarter of 20202021 was $52$62 million, an increase of $8$10 million, or 18%19%, compared to 20192020 primarily due to $6 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020, $6 million of lower operations and maintenance expenses, primarily due to lower long-term incentive plan costs and higher regulatory-directed credits, partially offset by $5$7 million of higher depreciationelectric utility margin, mainly from price impacts from changes in sales mix and amortizationhigher transmission and wholesale revenue, and $2 million of higher interest and dividend income, mainly due to higher plant in service.from carrying charges on regulatory balances.
Net income for the first nine months of 20202021 was $90$107 million, an increase of $10$17 million, or 13%19%, compared to 20192020 primarily due to $12 million of lower income tax expense due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020, $7$6 million of lower operations and maintenance expenses, primarilymainly due to higher regulatory-directed creditslower plant operations and maintenance expenses and lower long-term incentive plan costs, and $4earnings sharing, $5 million of higher electric utility margin, mainly from price impacts from changes in sales mix and an increase in the average number of customer, primarily from the residential customer class, partially offset by $10lower revenue recognized due to a favorable regulatory decision and an adjustment to regulatory-related revenue deferrals, $5 million of higher other, net, mainly due to lower pension costs and higher cash surrender value of corporate-owned life insurance policies, and $3 million of higher interest and dividend income, mainly from carrying charges on regulatory balances, partially offset by $3 million of higher depreciation and amortization, mainly due tofrom regulatory amortizations and higher plant in service, and $2$3 million of unfavorable otherhigher income (expense).tax expense primarily due to higher pretax income.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 266 | | | $ | 220 | | | $ | 46 | | 21 | % | | $ | 636 | | | $ | 569 | | | $ | 67 | | 12 | % |
Cost of fuel and energy | | 120 | | | 81 | | | 39 | | 48 | | | 295 | | | 233 | | | 62 | | 27 | |
Electric utility margin | | 146 | | | 139 | | | 7 | | 5 | | | 341 | | | 336 | | | 5 | | 1 | |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 16 | | | 15 | | | 1 | | 7 | % | | 75 | | | 83 | | | (8) | | (10) | % |
Natural gas purchased for resale | | 6 | | | 4 | | | 2 | | 50 | | | 35 | | | 44 | | | (9) | | (20) | |
Natural gas utility margin | | 10 | | | 11 | | | (1) | | (9) | | | 40 | | | 39 | | | 1 | | 3 | |
| | | | | | | | | | | | | | |
Utility margin | | 156 | | | 150 | | | 6 | | 4 | % | | 381 | | | 375 | | | 6 | | 2 | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 40 | | | 40 | | | — | | — | % | | 117 | | | 123 | | | (6) | | (5) | % |
Depreciation and amortization | | 35 | | | 36 | | | (1) | | (3) | | | 107 | | | 104 | | | 3 | | 3 | |
Property and other taxes | | 6 | | | 6 | | | — | | — | | | 18 | | | 17 | | | 1 | | 6 | |
Operating income | | $ | 75 | | | $ | 68 | | | $ | 7 | | 10 | % | | $ | 139 | | | $ | 131 | | | $ | 8 | | 6 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 220 |
| | $ | 232 |
| | $ | (12 | ) | (5 | )% | | $ | 569 |
| | $ | 586 |
| | $ | (17 | ) | (3 | )% |
Cost of fuel and energy | | 81 |
| | 93 |
| | (12 | ) | (13 | ) | | 233 |
| | 254 |
| | (21 | ) | (8 | ) |
Electric utility margin | | 139 |
| | 139 |
| | — |
| — |
| | 336 |
| | 332 |
| | 4 |
| 1 |
|
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 15 |
| | 16 |
| | (1 | ) | (6 | )% | | 83 |
| | 75 |
| | 8 |
| 11 | % |
Natural gas purchased for resale | | 4 |
| | 6 |
| | (2 | ) | (33 | ) | | 44 |
| | 35 |
| | 9 |
| 26 |
|
Natural gas utility margin | | 11 |
| | 10 |
| | 1 |
| 10 |
| | 39 |
| | 40 |
| | (1 | ) | (3 | ) |
| | | | | | | | | | | | | | |
Utility margin | | 150 |
| | 149 |
| | 1 |
| 1 | % | | 375 |
| | 372 |
| | 3 |
| 1 | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | 40 |
| | 46 |
| | (6 | ) | (13 | )% | | 123 |
| | 130 |
| | (7 | ) | (5 | )% |
Depreciation and amortization | | 36 |
| | 31 |
| | 5 |
| 16 |
| | 104 |
| | 94 |
| | 10 |
| 11 |
|
Property and other taxes | | 6 |
| | 5 |
| | 1 |
| 20 |
| | 17 |
| | 17 |
| | — |
| — |
|
Operating income | | $ | 68 |
| | $ | 67 |
| | $ | 1 |
| 1 | % | | $ | 131 |
| | $ | 131 |
| | $ | — |
| — | % |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 266 | | | $ | 220 | | | $ | 46 | | 21 | % | | $ | 636 | | | $ | 569 | | | $ | 67 | | 12 | % |
Cost of fuel and energy | | 120 | | | 81 | | | 39 | | 48 | | | 295 | | | 233 | | | 62 | | 27 | |
Utility margin | | $ | 146 | | | $ | 139 | | | $ | 7 | | 5 | % | | $ | 341 | | | $ | 336 | | | $ | 5 | | 1 | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 828 | | | 796 | | | 32 | | 4 | % | | 2,125 | | | 2,016 | | | 109 | | 5 | % |
Commercial | | 897 | | | 865 | | | 32 | | 4 | | | 2,362 | | | 2,288 | | | 74 | | 3 | |
Industrial | | 989 | | | 923 | | | 66 | | 7 | | | 2,786 | | | 2,643 | | | 143 | | 5 | |
Other | | 4 | | | 4 | | | — | | — | | | 11 | | | 12 | | | (1) | | (8) | |
Total fully bundled(1) | | 2,718 | | | 2,588 | | | 130 | | 5 | | | 7,284 | | | 6,959 | | | 325 | | 5 | |
Distribution only service | | 403 | | | 422 | | | (19) | | (5) | | | 1,220 | | | 1,259 | | | (39) | | (3) | |
Total retail | | 3,121 | | | 3,010 | | | 111 | | 4 | | | 8,504 | | | 8,218 | | | 286 | | 3 | |
Wholesale | | 204 | | | 87 | | | 117 | | * | | 504 | | | 376 | | | 128 | | 34 | |
Total GWhs sold | | 3,325 | | | 3,097 | | | 228 | | 7 | % | | 9,008 | | | 8,594 | | | 414 | | 5 | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 366 | | | 359 | | | 7 | | 2 | % | | 365 | | | 358 | | | 7 | | 2 | % |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 91.05 | | | $ | 79.22 | | | $ | 11.83 | | 15 | % | | $ | 80.56 | | | $ | 75.65 | | | $ | 4.91 | | 6 | % |
| | | | | | | | | | | | | | |
Wholesale | | $ | 48.32 | | | $ | 79.72 | | | $ | (31.40) | | (39) | % | | $ | 53.39 | | | $ | 54.54 | | | $ | (1.15) | | (2) | % |
| | | | | | | | | | | | | | |
Heating degree days | | 41 | | 15 | | 26 | | * | | 2,737 | | | 2,672 | | | 65 | | 2 | % |
Cooling degree days | | 997 | | | 946 | | | 51 | | 5 | % | | 1,366 | | | 1,166 | | | 200 | | 17 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 1,463 | | | 1,587 | | | (124) | | (8) | % | | 3,678 | | | 3,967 | | | (289) | | (7) | % |
Coal | | 373 | | | 496 | | | (123) | | (25) | % | | 838 | | | 716 | | | 122 | | 17 | % |
Renewables(4) | | 8 | | | 12 | | | (4) | | (33) | | | 27 | | | 31 | | | (4) | | (13) | |
Total energy generated | | 1,844 | | | 2,095 | | | (251) | | (12) | | | 4,543 | | | 4,714 | | | (171) | | (4) | |
Energy purchased | | 1,383 | | | 1,173 | | | 210 | | 18 | | | 3,905 | | | 3,625 | | | 280 | | 8 | |
Total | | 3,227 | | | 3,268 | | | (41) | | (1) | % | | 8,448 | | | 8,339 | | | 109 | | 1 | % |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(5): | | | | | | | | | | | | | | |
Energy generated | | $ | 23.64 | | | $ | 13.75 | | | $ | 9.89 | | 72 | % | | $ | 24.11 | | | $ | 21.13 | | | $ | 2.98 | | 14 | % |
Energy purchased | | $ | 55.46 | | | $ | 44.97 | | | $ | 10.49 | | 23 | % | | $ | 47.52 | | | $ | 36.83 | | | $ | 10.69 | | 29 | % |
* Not meaningful
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2021 and 2020, respectively. The average cost of energy per MWh and sources of energy excludes 2 GWhs and 3 GWhs of coal and 6 GWhs and 7 GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2021 and 2020, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.
(5) The average cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Electric utility margin (in millions): | | | | | | | | | | | | | | |
Electric operating revenue | | $ | 220 |
| | $ | 232 |
| | $ | (12 | ) | (5 | )% | | $ | 569 |
| | $ | 586 |
| | $ | (17 | ) | (3 | )% |
Cost of fuel and energy | | 81 |
| | 93 |
| | (12 | ) | (13 | ) | | 233 |
| | 254 |
| | (21 | ) | (8 | ) |
Electric utility margin | | $ | 139 |
| | $ | 139 |
| | $ | — |
| — | % | | $ | 336 |
| | $ | 332 |
| | $ | 4 |
| 1 | % |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 796 |
| | 696 |
| | 100 |
| 14 | % | | 2,016 |
| | 1,881 |
| | 135 |
| 7 | % |
Commercial | | 865 |
| | 903 |
| | (38 | ) | (4 | ) | | 2,288 |
| | 2,281 |
| | 7 |
| — |
|
Industrial | | 923 |
| | 886 |
| | 37 |
| 4 |
| | 2,643 |
| | 2,815 |
| | (172 | ) | (6 | ) |
Other | | 4 |
| | 4 |
| | — |
| — |
| | 12 |
| | 12 |
| | — |
| — |
|
Total fully bundled(1) | | 2,588 |
| | 2,489 |
| | 99 |
| 4 |
| | 6,959 |
| | 6,989 |
| | (30 | ) | — |
|
Distribution only service | | 422 |
| | 416 |
| | 6 |
| 1 |
| | 1,259 |
| | 1,212 |
| | 47 |
| 4 |
|
Total retail | | 3,010 |
| | 2,905 |
| | 105 |
| 4 |
| | 8,218 |
| | 8,201 |
| | 17 |
| — |
|
Wholesale | | 87 |
| | 100 |
| | (13 | ) | (13 | ) | | 376 |
| | 458 |
| | (82 | ) | (18 | ) |
Total GWhs sold | | 3,097 |
| | 3,005 |
| | 92 |
| 3 | % | | 8,594 |
| | 8,659 |
| | (65 | ) | (1 | )% |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 359 |
| | 353 |
| | 6 |
| 2 | % | | 358 |
| | 352 |
| | 6 |
| 2 | % |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 79.22 |
| | $ | 85.85 |
| | $ | (6.63 | ) | (8 | )% | | $ | 75.65 |
| | $ | 76.73 |
| | $ | (1.08 | ) | (1 | )% |
Wholesale | | $ | 79.72 |
| | $ | 46.68 |
| | $ | 33.04 |
| 71 | % | | $ | 54.54 |
| | $ | 50.03 |
| | $ | 4.51 |
| 9 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 15 |
| | 119 |
| | (104 | ) | (87 | )% | | 2,672 |
| | 2,882 |
| | (210 | ) | (7 | )% |
Cooling degree days | | 946 |
| | 891 |
| | 55 |
| 6 | % | | 1,166 |
| | 1,107 |
| | 59 |
| 5 | % |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 1,587 |
| | 1,468 |
| | 119 |
| 8 | % | | 3,967 |
| | 3,714 |
| | 253 |
| 7 | % |
Coal | | 496 |
| | 376 |
| | 120 |
| 32 |
| | 716 |
| | 928 |
| | (212 | ) | (23 | ) |
Renewables(4) | | 12 |
| | 13 |
| | (1 | ) | (8 | ) | | 31 |
| | 30 |
| | 1 |
| 3 |
|
Total energy generated | | 2,095 |
| | 1,857 |
| | 238 |
| 13 |
| | 4,714 |
| | 4,672 |
| | 42 |
| 1 |
|
Energy purchased | | 1,173 |
| | 937 |
| | 236 |
| 25 |
| | 3,625 |
| | 3,243 |
| | 382 |
| 12 |
|
Total | | 3,268 |
| | 2,794 |
| | 474 |
| 17 | % | | 8,339 |
| | 7,915 |
| | 424 |
| 5 | % |
| | | | | | | | | | | | | | |
Average total cost of energy per MWh(5) | | $ | 24.95 |
| | $ | 33.33 |
| | $ | (8.38 | ) | (25 | )% | | $ | 27.96 |
| | $ | 32.05 |
| | $ | (4.09 | ) | (13 | )% |
| |
(1) | Fully bundled includes sales to customers for combined energy, transmission and distribution services. |
| |
(2) | The average total cost of energy per MWh and sources of energy excludes 3 GWhs and - GWhs of coal and 7 GWhs and - GWhs of gas generated energy that is purchased at cost by related parties for the third quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes 3 GWhs and - GWhs of coal and 7 GWhs and - GWhs of gas generated energy that is purchased at cost by related parties for the first nine months of 2020 and 2019, respectively. |
| |
(3) | GWh amounts are net of energy used by the related generating facilities. |
| |
(4) | Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific. |
| |
(5) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2021 | | 2020 | | Change | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 16 | | | $ | 15 | | | $ | 1 | | 7 | % | | $ | 75 | | | $ | 83 | | | $ | (8) | | (10) | % |
Natural gas purchased for resale | | 6 | | | 4 | | | 2 | | 50 | | | 35 | | | 44 | | | (9) | | (20) | |
Utility margin | | $ | 10 | | | $ | 11 | | | $ | (1) | | (9) | % | | $ | 40 | | | $ | 39 | | | $ | 1 | | 3 | % |
| | | | | | | | | | | | | | |
Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 774 | | | 786 | | | (12) | | (2) | % | | 6,882 | | | 6,724 | | | 158 | | 2 | % |
Commercial | | 471 | | | 424 | | | 47 | | 11 | | | 3,550 | | | 3,309 | | | 241 | | 7 | |
Industrial | | 274 | | | 249 | | | 25 | | 10 | | | 1,414 | | | 1,244 | | | 170 | | 14 | |
Total retail | | 1,519 | | | 1,459 | | | 60 | | 4 | % | | 11,846 | | | 11,277 | | | 569 | | 5 | % |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 177 | | | 174 | | | 3 | | 2 | % | | 177 | | | 174 | | | 3 | | 2 | % |
| | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | $ | 10.51 | | | $ | 9.89 | | | $ | 0.62 | | 6 | % | | $ | 6.30 | | | $ | 7.33 | | | $ | (1.03) | | (14) | % |
| | | | | | | | | | | | | | |
Heating degree days | | 41 | | | 15 | | | 26 | | * | | 2,737 | | | 2,672 | | | 65 | | 2 | % |
| | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | $ | 3.78 | | | $ | 3.01 | | | $ | 0.77 | | 26 | % | | $ | 2.97 | | | $ | 3.93 | | | $ | (0.96) | | (24) | % |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Third Quarter | | First Nine Months |
| | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 15 |
| | $ | 16 |
| | $ | (1 | ) | (6 | )% | | $ | 83 |
| | $ | 75 |
| | $ | 8 |
| 11 | % |
Natural gas purchased for resale | | 4 |
| | 6 |
| | (2 | ) | (33 | ) | | 44 |
| | 35 |
| | 9 |
| 26 |
|
Natural gas utility margin | | $ | 11 |
| | $ | 10 |
| | $ | 1 |
| 10 | % | | $ | 39 |
| | $ | 40 |
| | $ | (1 | ) | (3 | )% |
| | | | | | | | | | | | | | |
Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 786 |
| | 814 |
| | (28 | ) | (3 | )% | | 6,724 |
| | 7,454 |
| | (730 | ) | (10 | )% |
Commercial | | 424 |
| | 491 |
| | (67 | ) | (14 | ) | | 3,309 |
| | 3,878 |
| | (569 | ) | (15 | ) |
Industrial | | 249 |
| | 278 |
| | (29 | ) | (10 | ) | | 1,244 |
| | 1,357 |
| | (113 | ) | (8 | ) |
Total retail | | 1,459 |
| | 1,583 |
| | (124 | ) | (8 | )% | | 11,277 |
| | 12,689 |
| | (1,412 | ) | (11 | )% |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 174 |
| | 171 |
| | 3 |
| 2 | % | | 174 |
| | 170 |
| | 4 |
| 2 | % |
| | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | $ | 9.89 |
| | $ | 10.11 |
| | $ | (0.22 | ) | (2 | )% | | $ | 7.33 |
| | $ | 5.91 |
| | $ | 1.42 |
| 24 | % |
| | | | | | | | | | | | | | |
Heating degree days | | 15 |
| | 119 |
| | (104 | ) | (87 | )% | | 2,672 |
| | 2,882 |
| | (210 | ) | (7 | )% |
| | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | $ | 3.01 |
| | $ | 3.79 |
| | $ | (0.78 | ) | (21 | )% | | $ | 3.93 |
| | $ | 2.76 |
| | $ | 1.18 |
| 43 | % |
Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020
Electric utility margin remained consistentincreased$7 million, or 5%, for the third quarter of 20202021 compared to 20192020 primarily due:due to:
•$2 million in higher residential customer volumes from the favorable impacts of weather,
$1 million due to higher energy efficiency program rates (offset in operations and maintenance expense),
$1 million of residential customer growth and
$15 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 3.6%3.7% primarily due to favorable changes in customer usage patterns and the favorable impactsimpact of weather, offset by the impacts of COVID-19, which resulted in consistent industrial and commercial usage and higher residential customer usage.
The increase in utility margin was offset by:
•$42 million of lowerhigher transmission and wholesale revenue and
•$1 million due to an increase in the average number of customers, primarily from the residential customer class.
Interest and dividend income increased $2 million for the third quarter of 2021 compared to 2020 primarily due to higher revenue reductions related to customer service agreements.interest income, mainly from carrying charges on regulatory balances.
Operations and maintenance decreased $6Income tax expense increased $2 million, or 13%33%, for the third quarter of 20202021 compared to 20192020, primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)), lower long-term incentive plan costs and lower plant operations and maintenance expenses, partially offset by higher energy efficiency program costs (offset in operating revenue) and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019.
Depreciation and amortization increased $5 million, or 16%, for the third quarter of 2020 compared to 2019 primarily due to higher plant placed in service and higher depreciation expense on the ON Line finance lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is favorable $1 million, or 9%, for the third quarter of 2020 compared to 2019 primarily due to lower pension costs, offset by higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Income tax expense decreased $6 million, or 50%, for the third quarter of 2020 compared to 2019.pretax income. The effective tax rate was 11% in 2021 and 10% in 2020 and 21% in 2019 and decreased due2020.
First Nine Months Ended September 30, 2021 Compared to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020.First Nine Months Ended September 30, 2020
Electric utility marginincreased $4$5 million, or 1%, for the first nine months of 20202021 compared to 20192020 primarily due:due to:
•$4 million in higher residential customer volumes from the favorable impact of weather,
$3 million due to higher energy efficiency program rates (offset in operations and maintenance expense),
$2 million of residential customer growth and
$19 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, increased 0.2%3.5% primarily due to favorable changes in customer usage patterns and the favorable impact of weather, offset by
•$2 million due to an increase in the impactsaverage number of COVID-19, which resulted in lower industrial and commercial usage and highercustomers, primarily from the residential customer usage.class and
•$2 million of higher transmission and wholesale revenue.
The increase in utility margin was offset by:
•$53 million ofin lower transmissionrevenue recognized due to a favorable regulatory decision in 2020,
•$3 million due to an adjustment to regulatory-related revenue deferrals and wholesale revenue and
•$1 million of higher revenue reductions relateddue to customer service agreements.lower energy efficiency program rates (offset in operations and maintenance expense).
Operations and maintenance decreased $7$6 million, or 5%, for the first nine months of 20202021 compared to 20192020 primarily due to higher regulatory-directed credits relating to the deferral of costs for the ON Line lease to be collected from customers due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in depreciation and amortization and other income (expense)) of $7 million, lower plant operations and maintenance expenses, lower earnings sharing and lower long-term incentive plan costs, offset by higher energy efficiency program costs (offset in operating revenue) and lower regulatory-directed credits relating to the amortization of an excess reserve balance that ended in 2019..
Depreciation and amortizationincreased $10$3 million, or 11%3%, for the first nine months of 20202021 compared to 20192020 primarily due to regulatory amortizations and higher plant in service.
Interest and dividend income increased $3 million for the first nine months of 2021 compared to 2020 primarily due to higher plant placed in serviceinterest income, mainly from carrying charges on regulatory balances.
Other, net increased $5 million for the first nine months of 2021 compared to 2020 primarily due to lower pension costs and higher depreciationcash surrender value of corporate-owned life insurance policies.
Income tax expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense).
Other income (expense) is unfavorable $2increased $3 million, or 7%30%, for the first nine months of 20202021 compared to 20192020, primarily due to higher interest expense on the ON Line lease due to the regulatory-directed reallocation of costs between Nevada Power and Sierra Pacific (offset in operations and maintenance expense) and lower cash surrender value of corporate-owned life insurance policies, offset by lower pension costs.
Income tax expense decreased $12 million, or 55%, for the first nine months of 2020 compared to 2019.pretax income. The effective tax rate was 11% in 2021 and 10% in 2020 and 22% in 2019 and decreased due to the recognition of amortization of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act following regulatory approval effective January 1, 2020.
Liquidity and Capital Resources
As of September 30, 2020,2021, Sierra Pacific's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 14 | |
| | |
Credit facility | | 250 | |
Less - | | |
| | |
Short-term debt | | (127) | |
Net credit facility | | 123 | |
| | |
Total net liquidity | | $ | 137 | |
Credit facility: | | |
Maturity date | | 2024 |
|
| | | | |
Cash and cash equivalents | | $ | 22 |
|
Credit facility | | 250 |
|
Total net liquidity | | $ | 272 |
|
Credit facility: | | |
Maturity date | | 2022 |
|
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $179$113 million and $189$179 million, respectively. The change was primarily due to lower collections from customers, higher inventory purchases and decreased collections of customer advances, partially offset by lower payments for income taxes and the timing of payments for operating costs.fuel and energy costs, partially offset by higher collections from customers, lower inventory purchases and increased collections of customer advances.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $(192)$(196) million and $(164)$(192) million, respectively. The change was primarily due to increased capital expenditures including expenditures related to the regulatory-directed reallocation of ON Line assets between Nevada Power and Sierra Pacific.expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the nine-month periods ended September 30, 2021 and 2020 and 2019 were $7$77 million and $(33)$7 million, respectively. The change was primarily due to lower payments to repurchase long-termhigher proceeds from short-term debt and lower dividends paid to NV Energy, Inc., partially offset by lower proceeds from the re-offeringissuance of previously repurchased long-term debt.
Long-Term Debt
In September 2020, Sierra Pacific entered into a re-offering of $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036. The series was offered at a fixed rate of 0.625% for a two-year term subject to mandatory purchase by Sierra Pacific in April 2022 at which date the interest rate may be adjusted.
In April 2020, Sierra Pacific entered into a re-offering of the following series of tax-exempt bonds that were held in treasury: $30 million of its Washoe County Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $59 million of its Washoe County Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031; and $20 million of its Humboldt County Water Facilities Refunding Revenue Bonds, Series 2016A, due 2029. The interest rate mode of these bonds was changed to a variable rate from an annual fixed rate. Sierra Pacific holds the Washoe and Humboldt County Series 2016A bonds and they could be issued at a future date if deemed necessary.
Debt Authorizations
Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.
Future Uses of Cash
Sierra Pacific 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; 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. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.
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):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
| | | | | |
Electric distribution | $ | 101 | | | $ | 66 | | | $ | 113 | |
Electric transmission | 51 | | | 50 | | | 90 | |
Solar generation | — | | | — | | | 18 | |
Other | 40 | | | 80 | | | 118 | |
Total | $ | 192 | | | $ | 196 | | | $ | 339 | |
|
| | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2019 | | 2020 | | 2020 |
| | | | | |
Distribution | $ | 117 |
| | $ | 107 |
| | $ | 132 |
|
Transmission system investment | 10 |
| | 46 |
| | 28 |
|
Other | 38 |
| | 39 |
| | 57 |
|
Total | $ | 165 |
| | $ | 192 |
| | $ | 217 |
|
Sierra Pacific's approved Fourth Amendment to the 2018 Joint IRP included an increase in electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates may change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include investments relatedthe following:
•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth projects and operating expenditures. Growth projects thatprimarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program of which costs are split 70% to Nevada Power and 30% to Sierra Pacific. In this project, the company proposed to build a 350-mile, 525 kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation. Construction of the project was approved by the PUCN in the Fourth Amendment to the 2018 Joint IRP with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. In addition, and as instructed in Senate Bill 448 and submitted in the company's amendment to the 2021 Joint IRP, the company proposed to build a 235-mile, 525 kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345 kV transmission line from the new Ft. Churchill substation to the Mira Loma substations; and a 38-mile, 345 kV transmission line from the new Ft. Churchill substation to the Comstock Meadows substations and the Northwest substation to Harry Allen substation segment of Greenlink West. Operating expenditures consist of routine expenditures for generation, transmission distribution and other infrastructure needed to serve existing and expected demand.
•Other investments include both growth projects and operating expenditures consisting of routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Contractual Obligations
As of September 30, 2020,2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2019.2020.
COVID-19
In March 2020, COVID-19 was declared a global pandemic and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by Sierra Pacific. While COVID-19 has impacted Sierra Pacific's financial results and operations through September 30, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. In April 2020, the state of Nevada instituted a "stay-at-home" order requiring non-essential businesses, including casinos, to remain closed, which impacted Sierra Pacific's customers and, therefore, their needs and usage patterns for electricity and natural gas. The state of Nevada has since moved to a long-term recovery plan with most businesses, including casinos, opening subject to capacity and other operating limitations that will be revised as the state and counties meet certain metrics. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, a reduction in the consumption of electricity or natural gas may occur, particularly in the commercial and industrial classes as well as distribution only service customers. Due to regulatory requirements and voluntary actions taken by Sierra Pacific related to customer collection activity and suspension of disconnections for non-payment, Sierra Pacific has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through September 2020 has not been material compared to the same period in 2019 but uncertainty remains. The PUCN has approved the deferral of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for further discussion.
Sierra Pacific's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system and its natural gas distribution system. In response to the effects of COVID-19, Sierra Pacific has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local 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 Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, 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 the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
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 long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2019.2020. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2019.2020.
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Eastern Energy Gas Holdings, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of September 30, 2021, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and nine-month periods ended September 30, 2021 and 2020, and of cash flows for the nine-month periods ended September 30, 2021 and 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 Eastern Energy Gas as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 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, 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 Eastern Energy Gas' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Eastern Energy Gas 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
Richmond, Virginia
November 5, 2021
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, 2021 | | December 31, 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 90 | | | $ | 35 | |
Restricted cash and cash equivalents | 17 | | | 13 | |
Trade receivables, net | 143 | | | 177 | |
Receivables from affiliates | 70 | | | 139 | |
Income taxes receivable | 52 | | | 20 | |
Other receivables | 7 | | | 51 | |
Inventories | 127 | | | 119 | |
Prepayments | 90 | | | 60 | |
Natural gas imbalances | 69 | | | 26 | |
Other current assets | 19 | | | 16 | |
Total current assets | 684 | | | 656 | |
| | | |
Property, plant and equipment, net | 10,195 | | | 10,144 | |
Goodwill | 1,286 | | | 1,286 | |
| | | |
Investments | 259 | | | 244 | |
| | | |
Other assets | 167 | | | 291 | |
| | | |
Total assets | $ | 12,591 | | | $ | 12,621 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| September 30, 2021 | | December 31, 2020 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 71 | | | $ | 71 | |
Accounts payable to affiliates | 35 | | | 39 | |
Accrued interest | 49 | | | 19 | |
Accrued property, income and other taxes | 73 | | | 29 | |
| | | |
Notes payable | — | | | 9 | |
| | | |
| | | |
Current portion of long-term debt | — | | | 500 | |
Other current liabilities | 178 | | | 147 | |
Total current liabilities | 406 | | | 814 | |
| | | |
Long-term debt | 3,910 | | | 3,925 | |
| | | |
| | | |
Regulatory liabilities | 646 | | | 669 | |
| | | |
Other long-term liabilities | 239 | | | 218 | |
Total liabilities | 5,201 | | | 5,626 | |
| | | |
Commitments and contingencies (Note 9) | 0 | | 0 |
| | | |
Equity: | | | |
Member's equity: | | | |
| | | |
Membership interests | 3,388 | | | 2,957 | |
| | | |
| | | |
Accumulated other comprehensive loss, net | (42) | | | (53) | |
Total member's equity | 3,346 | | | 2,904 | |
Noncontrolling interests | 4,044 | | | 4,091 | |
Total equity | 7,390 | | | 6,995 | |
| | | |
Total liabilities and equity | $ | 12,591 | | | $ | 12,621 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Operating revenue | $ | 456 | | | $ | 531 | | | $ | 1,379 | | | $ | 1,597 | |
| | | | | | | |
Operating expenses: | | | | | | | |
| | | | | | | |
(Excess) cost of gas | (3) | | | 14 | | | (13) | | | 23 | |
Operations and maintenance | 125 | | | 119 | | | 362 | | | 922 | |
Depreciation and amortization | 83 | | | 95 | | | 244 | | | 282 | |
Property and other taxes | 38 | | | 38 | | | 115 | | | 109 | |
| | | | | | | |
Total operating expenses | 243 | | | 266 | | | 708 | | | 1,336 | |
| | | | | | | |
Operating income | 213 | | | 265 | | | 671 | | | 261 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (32) | | | (186) | | | (118) | | | (294) | |
| | | | | | | |
Allowance for equity funds | 2 | | | 1 | | | 5 | | | 11 | |
Interest and dividend income | — | | | 10 | | | — | | | 67 | |
| | | | | | | |
Other, net | (1) | | | 11 | | | 1 | | | 39 | |
Total other income (expense) | (31) | | | (164) | | | (112) | | | (177) | |
| | | | | | | |
Income before income tax expense (benefit) and equity income | 182 | | | 101 | | | 559 | | | 84 | |
Income tax expense (benefit) | 21 | | | (10) | | | 70 | | | (40) | |
Equity income | 8 | | | 7 | | | 31 | | | 30 | |
| | | | | | | |
| | | | | | | |
Net income | 169 | | | 118 | | | 520 | | | 154 | |
Net income attributable to noncontrolling interests | 100 | | | 32 | | | 302 | | | 97 | |
Net income attributable to Eastern Energy Gas | $ | 69 | | | $ | 86 | | | $ | 218 | | | $ | 57 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Net income | $ | 169 | | | $ | 118 | | | $ | 520 | | | $ | 154 | |
| | | | | | | |
Other comprehensive (loss) income, net of tax: | | | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $—, $(1), $— and $— | — | | | (4) | | | 4 | | | (1) | |
| | | | | | | |
| | | | | | | |
Unrealized (losses) gains on cash flow hedges, net of tax of $(1), $37, $2 and $8 | (2) | | | 111 | | | 11 | | | 24 | |
Total other comprehensive (loss) income, net of tax | (2) | | | 107 | | | 15 | | | 23 | |
| | | | | | | |
Comprehensive income | 167 | | | 225 | | | 535 | | | 177 | |
Comprehensive income attributable to noncontrolling interests | 100 | | | 32 | | | 306 | | | 97 | |
Comprehensive income attributable to Eastern Energy Gas | $ | 67 | | | $ | 193 | | | $ | 229 | | | $ | 80 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | | | | | | | | Membership | | Comprehensive | | Noncontrolling | | Total |
| | | | | | | | | Interests | | Loss, Net | | Interests | | Equity |
| | | | | | | | | | | | | | | |
Balance, June 30, 2020 | | | | | | | | | $ | 7,352 | | | $ | (271) | | | $ | 1,375 | | | $ | 8,456 | |
Net income | | | | | | | | | 86 | | | — | | | 32 | | | 118 | |
Other comprehensive income | | | | | | | | | — | | | 107 | | | — | | | 107 | |
Contributions | | | | | | | | | 299 | | | — | | | — | | | 299 | |
Distributions | | | | | | | | | (2,394) | | | — | | | (36) | | | (2,430) | |
Balance, September 30, 2020 | | | | | | | | | $ | 5,343 | | | $ | (164) | | | $ | 1,371 | | | $ | 6,550 | |
| | | | | | | | | | | | | | | |
Balance, December 31, 2019 | | | | | | | | | $ | 9,031 | | | $ | (187) | | | $ | 1,385 | | | $ | 10,229 | |
Net income | | | | | | | | | 57 | | | — | | | 97 | | | 154 | |
Other comprehensive income | | | | | | | | | — | | | 23 | | | — | | | 23 | |
| | | | | | | | | | | | | | | |
Contributions | | | | | | | | | 299 | | | — | | | — | | | 299 | |
Distributions | | | | | | | | | (4,044) | | | — | | | (111) | | | (4,155) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, September 30, 2020 | | | | | | | | | $ | 5,343 | | | $ | (164) | | | $ | 1,371 | | | $ | 6,550 | |
| | | | | | | | | | | | | | | |
Balance, June 30, 2021 | | | | | | | | | $ | 3,366 | | | $ | (40) | | | $ | 4,072 | | | $ | 7,398 | |
Net income | | | | | | | | | 69 | | | — | | | 100 | | | 169 | |
Other comprehensive loss | | | | | | | | | — | | | (2) | | | — | | | (2) | |
Contributions | | | | | | | | | 2 | | | — | | | — | | | 2 | |
Distributions | | | | | | | | | (49) | | | — | | | (128) | | | (177) | |
Balance, September 30, 2021 | | | | | | | | | $ | 3,388 | | | $ | (42) | | | $ | 4,044 | | | $ | 7,390 | |
| | | | | | | | | | | | | | | |
Balance, December 31, 2020 | | | | | | | | | $ | 2,957 | | | $ | (53) | | | $ | 4,091 | | | $ | 6,995 | |
Net income | | | | | | | | | 218 | | | — | | | 302 | | | 520 | |
Other comprehensive income | | | | | | | | | — | | | 11 | | | 4 | | | 15 | |
Contributions | | | | | | | | | 284 | | | — | | | — | | | 284 | |
Distributions | | | | | | | | | (71) | | | — | | | (353) | | | (424) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, September 30, 2021 | | | | | | | | | $ | 3,388 | | | $ | (42) | | | $ | 4,044 | | | $ | 7,390 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Nine-Month Periods |
| Ended September 30, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 520 | | | $ | 154 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
(Gains) losses on other items, net | (9) | | | 463 | |
Depreciation and amortization | 244 | | | 282 | |
Allowance for equity funds | (5) | | | (11) | |
Equity (income) loss, net of distributions | (1) | | | 33 | |
Changes in regulatory assets and liabilities | (2) | | | 19 | |
Deferred income taxes | 135 | | | (103) | |
Other, net | (11) | | | 8 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 13 | | | 271 | |
Derivative collateral, net | 7 | | | 148 | |
Pension and other postretirement benefit plans | — | | | (46) | |
Accrued property, income and other taxes | (61) | | | 36 | |
Accounts payable and other liabilities | 37 | | | 5 | |
Net cash flows from operating activities | 867 | | | 1,259 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (291) | | | (258) | |
| | | |
| | | |
Repayment of loans by affiliates | 269 | | | 3,422 | |
Loans to affiliates | (170) | | | (225) | |
| | | |
Other, net | (9) | | | (9) | |
Net cash flows from investing activities | (201) | | | 2,930 | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Repayments of long-term debt | (500) | | | — | |
Net repayments of short-term debt | — | | | (62) | |
Repayment of notes payable, net | (9) | | | (253) | |
| | | |
| | | |
Proceeds from equity contributions | 256 | | | 299 | |
Distributions | (353) | | | (4,155) | |
| | | |
Other, net | (1) | | | (1) | |
Net cash flows from financing activities | (607) | | | (4,172) | |
| | | |
| | | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 59 | | | 17 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 48 | | | 39 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 107 | | | $ | 56 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Eastern Energy Gas Holdings, LLC and its subsidiaries ("Eastern Energy Gas") is a holding company that conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United States and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transportation pipeline.
In July 2020, Dominion Energy, Inc. ("DEI") entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, to Berkshire Hathaway Energy Company ("BHE"). Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the acquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction") and the proposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). In July 2021, Dominion Questar and DEI delivered a written notice to BHE stating that BHE and Dominion Questar have mutually elected to terminate the Q-Pipe Transaction. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business. On November 1, 2020, BHE completed the GT&S Transaction. As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. 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 September 30, 2021 and for the three- and nine-month periods ended September 30, 2021 and 2020. The results of operations for the three- and nine-month periods ended September 30, 2021 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 Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2021.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions): | | | | | | | | | | | | | | | | | |
| | | As of |
| | | September 30, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
| | | | | |
Interstate natural gas pipeline assets | 24 - 43 years | | $ | 8,555 | | | $ | 8,382 | |
Intangible plant | 5 - 10 years | | 111 | | | 115 | |
Utility plant in service | | | 8,666 | | | 8,497 | |
Accumulated depreciation and amortization | | | (2,859) | | | (2,759) | |
Utility plant in service, net | | | 5,807 | | | 5,738 | |
| | | | | |
Nonutility Plant: | | | | | |
| | | | | |
LNG facility | 40 years | | 4,466 | | | 4,454 | |
Intangible plant | 14 years | | 25 | | | 25 | |
Nonutility plant in service | | | 4,491 | | | 4,479 | |
Accumulated depreciation and amortization | | | (396) | | | (283) | |
Nonutility plant in service, net | | | 4,095 | | | 4,196 | |
| | | | | |
Plant, net | | | 9,902 | | | 9,934 | |
Construction work-in-progress | | | 293 | | | 210 | |
Property, plant and equipment, net | | | $ | 10,195 | | | $ | 10,144 | |
Construction work-in-progress includes $266 million and $196 million as of September 30, 2021 and December 31, 2020, respectively, related to the construction of utility plant.
(3) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
Investments: | | | |
Investment funds | $ | 13 | | | $ | — | |
| | | |
| | | |
Equity method investments: | | | |
Iroquois | 246 | | | 244 | |
| | | |
| | | |
Total investments | 259 | | | 244 | |
| | | |
Restricted cash and cash equivalents: | | | |
Customer deposits | 17 | | | 13 | |
Total restricted cash and cash equivalents | 17 | | | 13 | |
| | | |
Total investments and restricted cash and cash equivalents | $ | 276 | | | $ | 257 | |
| | | |
Reflected as: | | | |
Current assets | $ | 17 | | | $ | 13 | |
Noncurrent assets | 259 | | | 244 | |
Total investments and restricted cash and cash equivalents | $ | 276 | | | $ | 257 | |
Equity Method Investments
Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.
As of September 30, 2021 and December 31, 2020, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $30 million and $63 million for the nine-month periods ended September 30, 2021 and 2020, respectively.
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
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 as of September 30, 2021 and December 31, 2020 consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2021 and December 31, 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):
| | | | | | | | | | | |
| As of |
| September 30, | | December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 90 | | | $ | 35 | |
Restricted cash and cash equivalents | 17 | | | 13 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 107 | | | $ | 48 | |
(4) Regulatory Matters
Eastern Gas Transmission and Storage, Inc.
In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion. EGTS has requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022 subject to refund and the outcome of hearing procedures. This matter is pending.
In July 2017, the FERC audit staff communicated to EGTS that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge of $129 million ($94 million after-tax) for the year ended December 31, 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) estimated charge for disallowance of capitalized allowance for funds used during construction. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized allowance for funds used during construction, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in its Consolidated Statements of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.
In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statements of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million asset retirement obligation. In the third quarter of 2020, Eastern Energy Gas recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to the previously established asset retirement obligation, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statements of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.
Cove Point
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.
(5) Recent Financing Transactions
On June 30, 2021, as part of an intercompany transaction with its wholly owned subsidiary EGTS, Eastern Energy Gas exchanged a total of $1.6 billion of its issued and outstanding third party notes, making EGTS the primary obligor of the exchanged notes. The intercompany debt exchange was a common control transaction accounted for as a debt modification with no gain or loss recognized in the Consolidated Financial Statements. The following table details the exchanged notes prior to, and subsequent to, the transaction (in millions):
| | | | | | | | | | | | | | | | | |
| Prior to Exchange | | Subsequent to Exchange |
| Eastern Energy Gas Par Value | | Eastern Energy Gas Par Value | | EGTS Par Value |
| | | | | |
3.6% Senior Notes due 2024 | $ | 450 | | | $ | 339 | | | $ | 111 | |
3.0% Senior Notes due 2029 | 600 | | | 174 | | | 426 | |
4.8% Senior Notes due 2043 | 400 | | | 54 | | | 346 | |
4.6% Senior Notes due 2044 | 500 | | | 56 | | | 444 | |
3.9% Senior Notes due 2049 | 300 | | | 27 | | | 273 | |
| $ | 2,250 | | | $ | 650 | | | $ | 1,600 | |
(6) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | 2 | | | (3) | | | 2 | | | (29) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Equity interest | 1 | | | — | | | 1 | | | 8 | |
Effects of ratemaking | (1) | | | (2) | | | (1) | | | (6) | |
| | | | | | | |
| | | | | | | |
Change in tax status | — | | | (18) | | | — | | | (24) | |
| | | | | | | |
AFUDC-equity | — | | | — | | | — | | | (2) | |
Noncontrolling interest | (11) | | | (6) | | | (11) | | | (24) | |
Write-off of regulatory assets | — | | | — | | | — | | | 9 | |
Other, net | — | | | (2) | | | 1 | | | (1) | |
Effective income tax rate | 12 | % | | (10) | % | | 13 | % | | (48) | % |
Noncontrolling interest is attributable to Eastern Energy Gas' ownership in Cove Point. The GT&S Transaction resulted in a change of noncontrolling interest to 75% as of September 30, 2021 from 25% as of September 30, 2020. Additionally, Eastern Energy Gas' effective tax rate for the periods ended September 30, 2020 is primarily a function of the impacts associated with the cancellation of the Atlantic Coast Pipeline project, the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries.
Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing date of the GT&S Transaction. Subsequent to the GT&S Transaction, Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Eastern Energy Gas received net cash payments for income tax from BHE totaling $34 million for the nine-month period ended September 30, 2021.
(7) Employee Benefit Plans
Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. Also prior to the GT&S Transaction, pension benefits for Eastern Energy Gas employees represented by collective bargaining units were provided by a separate plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Company ("MidAmerican Energy") Pension Plan, similar to the DEI plan.
Prior to the GT&S Transaction, certain retiree healthcare and life insurance benefits for Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Also prior to the GT&S Transaction, retiree health and life insurance benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTS and Hope. Subsequent to the GT&S Transaction, Eastern Energy Gas employees are covered by the MidAmerican Energy Retiree Health and Welfare plan, similar to the DEI plan.
Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | $ | — | | | $ | 2 | | | $ | — | | | $ | 5 | |
Interest cost | — | | | 3 | | | — | | | 8 | |
Expected return on plan assets | — | | | (14) | | | — | | | (42) | |
Net amortization | — | | | 1 | | | — | | | 5 | |
Net periodic benefit credit | $ | — | | | $ | (8) | | | $ | — | | | $ | (24) | |
| | | | | | | |
Other Postretirement: | | | | | | | |
Service cost | $ | — | | | $ | — | | | $ | — | | | $ | 1 | |
Interest cost | — | | | 1 | | | — | | | 3 | |
Expected return on plan assets | — | | | (4) | | | — | | | (14) | |
Net amortization | — | | | (1) | | | — | | | (2) | |
Net periodic benefit credit | $ | — | | | $ | (4) | | | $ | — | | | $ | (12) | |
(8) Fair Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
The following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
As of September 30, 2021 | | | | | | | | |
Assets: | | | | | | | | |
| | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | 8 | | | $ | — | | | $ | 8 | |
Money market mutual funds | | 75 | | | — | | | — | | | 75 | |
Investment funds | | 13 | | | — | | | — | | | 13 | |
| | $ | 88 | | | $ | 8 | | | $ | — | | | $ | 96 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | |
Foreign currency exchange rate derivatives | | — | | | (4) | | | — | | | (4) | |
| | | | | | | | |
| | $ | — | | | $ | (5) | | | $ | — | | | $ | (5) | |
| | | | | | | | |
As of December 31, 2020 | | | | | | | | |
Assets: | | | | | | | | |
| | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | |
| | | | | | | | |
| | $ | — | | | $ | 20 | | | $ | — | | | $ | 20 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | (1) | | | $ | — | | | $ | (1) | |
Foreign currency exchange rate derivatives | | — | | | (2) | | | — | | | (2) | |
Interest rate derivatives | | — | | | (6) | | | — | | | (6) | |
| | $ | — | | | $ | (9) | | | $ | — | | | $ | (9) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Eastern Energy Gas' variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of September 30, 2021 | | As of December 31, 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 3,910 | | | $ | 4,327 | | | $ | 4,425 | | | $ | 5,012 | |
(9) Commitments and Contingencies
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
(10) Revenue from Contracts with Customers
The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Nine-Month Periods |
| Ended September 30, | | Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
Customer Revenue: | | | | | | | |
Regulated: | | | | | | | |
Gas transportation and storage | $ | 249 | | | $ | 311 | | | $ | 774 | | | $ | 957 | |
Wholesale | 14 | | | 25 | | | 31 | | | 27 | |
Other | 1 | | | 1 | | | (1) | | | 4 | |
Total regulated | 264 | | | 337 | | | 804 | | | 988 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Nonregulated | 193 | | | 193 | | | 573 | | | 606 | |
Total Customer Revenue | 457 | | | 530 | | | 1,377 | | | 1,594 | |
Other revenue | (1) | | | 1 | | | 2 | | | 3 | |
Total operating revenue | $ | 456 | | | $ | 531 | | | $ | 1,379 | | | $ | 1,597 | |
Remaining Performance Obligations
The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of September 30, 2021 (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
Eastern Energy Gas | $ | 1,574 | | | $ | 16,413 | | | $ | 17,987 | |
(11) Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | | | | | Accumulated |
| | Amounts On | | Unrealized | | | | Other |
| | Retirement | | Losses on Cash | | Noncontrolling | | Comprehensive |
| | Benefits | | Flow Hedges | | Interests | | Loss, Net |
Balance, December 31, 2019 | | $ | (106) | | | $ | (81) | | | $ | — | | | $ | (187) | |
Other comprehensive (loss) income | | (1) | | | 24 | | | — | | | 23 | |
Balance, September 30, 2020 | | $ | (107) | | | $ | (57) | | | $ | — | | | $ | (164) | |
| | | | | | | | |
Balance, December 31, 2020 | | $ | (12) | | | $ | (51) | | | $ | 10 | | | $ | (53) | |
Other comprehensive income (loss) | | 4 | | | 11 | | | (4) | | | 11 | |
Balance, September 30, 2021 | | $ | (8) | | | $ | (40) | | | $ | 6 | | | $ | (42) | |
In July 2020, Eastern Energy Gas recorded a loss of $141 million ($105 million after-tax) in interest expense in the Consolidated Statement of Operations, for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.
(12) Variable Interest Entities
The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
In November 2019, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $3 million for each of the three-month periods ended September 30, 2021 and 2020, and $9 million and $10 million for the nine-month periods ended September 30, 2021 and 2020, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $31 million and $22 million as of September 30, 2021 and December 31, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $7 million and $21 million for the three- and nine-month periods ended September 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $22 million and $80 million for the three- and nine-month periods ended September 30, 2020, respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.
(13) Related Party Transactions
Transactions Prior to the GT&S Transaction
Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other DEI subsidiaries (affiliates). Eastern Energy Gas' receivable and payable balances with affiliates were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. All affiliate payables or receivables were settled with DEI prior to the closing of the GT&S Transaction.
Eastern Energy Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entered into certain other contracts with affiliates, and related parties, including construction services, which were presented separately from contracts involving commodities or services. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 7.
DES, Carolina Gas Services, DEQPS and other affiliates provided accounting, legal, finance and certain administrative and technical services to Eastern Energy Gas. Eastern Energy Gas provided certain services to related parties, including technical services.
The financial statements for the three-month and nine-month periods ended September 30, 2020 include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Eastern Energy Gas on the basis of direct and allocated methods in accordance with Eastern Energy Gas' services agreements with DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related-party transactions.
Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the three- and nine-month periods ended September 30, 2020 (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Period | | Nine-Month Period | | | | |
| Ended September 30, 2020 | | Ended September 30, 2020 | | | | |
Sales of natural gas and transportation and storage services | $ | 60 | | | $ | 188 | | | | | |
Purchases of natural gas and transportation and storage services | 3 | | | 9 | | | | | |
Services provided by related parties(1) | 34 | | | 114 | | | | | |
Services provided to related parties(2) | 17 | | | 78 | | | | | |
(1) Includes capitalized expenditures of $5 million and $12 million for the three- and nine-month periods ended September 30, 2020, respectively.
(2) Amounts primarily attributable to Atlantic Coast Pipeline, LLC, a related-party VIE prior to the GT&S Transaction.
Interest income related to the affiliated notes receivable under the DEI money pool was $3 million for the nine-month period ended September 30, 2020.
Interest income related to Eastern Energy Gas' affiliated notes receivable from DEI was $9 million and $32 million for the three- and nine-month periods ended September 30, 2020, respectively.
Interest income related to Eastern Energy Gas' affiliated notes receivable from East Ohio Gas Company was $33 million for the nine-month period ended September 30, 2020.
Interest charges related to Eastern Energy Gas' total borrowings under an intercompany revolving credit agreement with DEI were $3 million for the nine-month period ended September 30, 2020.
Interest charges related to CPMLP Holdings Company, LLC's total borrowings from DES were $3 million for the nine-month period ended September 30, 2020.
For the nine-month period ended September 30, 2020, Eastern Energy Gas distributed $4.2 billion to DEI.
Transactions Subsequent to the GT&S Transaction
Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $31 million and $20 million as of September 30, 2021 and December 31, 2020, respectively.
Other assets included amounts due from an affiliate of $4 million and $7 million as of September 30, 2021 and December 31, 2020, respectively.
As of September 30, 2021, Eastern Energy Gas had $3 million of natural gas imbalances payable to affiliates, presented in other current liabilities on the Consolidated Balance Sheet.
Presented below are Eastern Energy Gas' significant transactions with affiliated and related parties for the three- and nine-month periods ended September 30, 2021 (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Period | | Nine-Month Period | | | | |
| Ended September 30, 2021 | | Ended September 30, 2021 | | | | |
Sales of natural gas and transportation and storage services | $ | 7 | | | $ | 21 | | | | | |
Purchases of natural gas and transportation and storage services | 1 | | | 4 | | | | | |
Services provided by related parties | 16 | | | 31 | | | | | |
Services provided to related parties | 8 | | | 24 | | | | | |
Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, LLC ("BHE GT&S") expiring in November 2022. The credit facility, which is for general corporate purposes and provides for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of September 30, 2021 and December 31, 2020, $— million and $9 million, respectively, was outstanding under the credit agreement.
BHE GT&S has an intercompany revolving credit agreement from Eastern Energy Gas expiring in December 2022. In March 2021, BHE GT&S increased its credit facility limit from $200 million to $400 million. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of September 30, 2021 and December 31, 2020, $28 million and $124 million, respectively, was outstanding under the credit agreement.
Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 7. As of September 30, 2021 and December 31, 2020, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $110 million and $115 million, respectively.
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results of Operations for the Third Quarter and First Nine Months of 2021 and 2020
Overview
Net income attributable to Eastern Energy Gas for the third quarter of 2021 was $69 million, a decrease of $17 million compared to 2020. Net income decreased primarily due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point LNG, LP ("Cove Point") of $68 million, the November 2020 disposition of Questar Pipeline Group of $26 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $14 million, all of which were a result of the GT&S Transaction, and income tax expense of $21 million in 2021 versus income tax benefit of $10 million in 2020, primarily due to higher pre-tax income. These decreases were partially offset by a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction.
Net income attributable to Eastern Energy Gas for the first nine months of 2021 was $218 million, an increase of $161 million compared to 2020. Net income increased primarily due to a 2020 charge of $463 million associated with the probable abandonment of a significant portion of a project previously intended for EGTS to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"), a 2020 charge of $141 million for cash flow hedges of debt-related items that were probable of not occurring as a result of the GT&S Transaction and higher margins of $39 million due to favorable natural gas prices. These increases were partially offset by a decrease in net income due to an increase in net income attributable to DEI's 50% noncontrolling interest in Cove Point of $205 million, the November 2020 disposition of Questar Pipeline Group of $68 million, interest income from DEI and its affiliates recognized in 2020 of $65 million and a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI of $42 million, all of which were a result of the GT&S Transaction, and income tax expense of $70 million in 2021 versus income tax benefit of $40 million in 2020, primarily due to higher pre-tax income.
Quarter Ended September 30, 2021 Compared to Quarter Ended September 30, 2020
Operating revenue decreased $75 million, or 14%, for the third quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $58 million and a decrease in regulated gas sales for operational and system balancing purposes primarily due to decreased prices of $11 million.
(Excess) cost of gas was a credit of $3 million for the third quarter of 2021 compared to an expense of $14 million for the third quarter of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices.
Operations and maintenance increased $6 million, or 5%, for the third quarter of 2021 compared to 2020, primarily due to a 2020 benefit associated with the probable abandonment of a significant portion of the Supply Header Project of $19 million, partially offset by the November 2020 disposition of Questar Pipeline Group of $13 million.
Depreciation and amortization decreased $12 million, or 13%, for the third quarter of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.
Interest expense decreased$154 million, or 83%, for the third quarter of 2021 compared to 2020, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $5 million and lower interest expense of $5 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.
Interest and dividend income decreased $10 million for the third quarter of 2021 compared to 2020, primarily due to interest income from DEI recognized in 2020 as a result of the GT&S Transaction.
Other, net was an expense of $1 million for the third quarter of 2021 compared to income of $11 million for the third quarter of 2020. The change in other, net is primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.
Income tax expense (benefit) was an expense of $21 million for the third quarter of 2021 compared to a benefit of $10 million for the third quarter of 2020 and the effective tax rate was 12% for the third quarter of 2021 and (10)% for the third quarter of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.
Net income attributable to noncontrolling interests increased $68 million for the third quarter of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.
First Nine Months Ended September 30, 2021 Compared to First Nine Months Ended September 30, 2020
Operating revenue decreased $218 million, or 14%, for the first nine months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group of $178 million and a decrease in services performed for Atlantic Coast Pipeline, LLC of $40 million, which is offset in operations and maintenance expense. This decrease in operating revenue was partially offset by an increase in regulated gas sales for operational and system balancing purposes primarily due to increased prices of $6 million.
(Excess) cost of gas was a credit of $13 million for the first nine months of 2021 compared to an expense of $23 million for the first nine months of 2020. The change in (excess) cost of gas is primarily due to a favorable change in natural gas prices of $48 million and the November 2020 disposition of Questar Pipeline Group of $3 million, partially offset by an increase in prices of natural gas sold of $15 million.
Operations and maintenance decreased $560 million, or 61%, for the first nine months of 2021 compared to 2020, primarily due to a 2020 charge associated with the probable abandonment of a significant portion of the Supply Header Project of $463 million, a decrease in services performed for Atlantic Coast Pipeline, LLC of $41 million and the November 2020 disposition of Questar Pipeline Group of $39 million.
Depreciation and amortization decreased $38 million, or 13%, for the first nine months of 2021 compared to 2020, primarily due to the November 2020 disposition of Questar Pipeline Group.
Property and other taxes increased$6 million, or 6%, for the first nine months of 2021 compared to 2020, primarily due to higher tax assessments.
Interest expense decreased $176 million, or 60%, for the first nine months of 2021 compared to 2020, primarily due to a charge in 2020 for cash flow hedges of $141 million of debt-related items that were probable of not occurring as a result of the GT&S Transaction, the November 2020 disposition of Questar Pipeline Group of $15 million and lower interest expense of $15 million from the repayment of $700 million of long-term debt in the fourth quarter of 2020 and $4 million from the repayment of $500 million of long-term debt in the second quarter of 2021.
Allowance for equity funds decreased $6 million, or 55%, for the first nine months of 2021 compared to 2020, primarily due to lower capital expenditures related to the Supply Header Project as a result of the abandonment of the project.
Interest and dividend income decreased $67 million for the first nine months of 2021 compared to 2020, primarily due to interest income from the East Ohio Gas Company of $33 million and DEI of $32 million recognized in 2020 as a result of the GT&S Transaction.
Other, net decreased $38 million, or 97%, for the first nine months of 2021 compared to 2020, primarily due to a decrease in non-service cost credits related to certain Eastern Energy Gas benefit plans that were retained by DEI as a result of the GT&S Transaction.
Income tax expense (benefit) was an expense of $70 million for the first nine months of 2021 compared to a benefit of $40 million for the first nine months of 2020 and the effective tax rate was 13% for the first nine months of 2021 and (48)% for the first nine months of 2020. The effective tax rate increased primarily due to the change in the noncontrolling interest of Cove Point as a result of the GT&S Transaction, lower pre-tax income driven by charges associated with the Supply Header Project and the finalization of the effects from the change in tax status of certain Eastern Energy Gas subsidiaries in 2020.
Net income attributable to noncontrolling interests increased $205 million for the first nine months of 2021 compared to 2020 primarily due to DEI's 50% noncontrolling interest in Cove Point effective with the GT&S Transaction.
Liquidity and Capital Resources
As of September 30, 2021, Eastern Energy Gas' total net liquidity was $490 million as follows (in millions):
| | | | | | | | |
Item 3.Cash and cash equivalents | Quantitative and Qualitative Disclosures About Market Risk | $ | 90 | |
| | |
Intercompany credit agreement(1) | | 400 | |
| | |
| | |
| | |
| | |
| | |
Total net liquidity | | $ | 490 | |
| | |
Intercompany credit agreement: | | |
Maturity date | | 2022 |
(1)Refer to Note 13 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for further discussion regarding Eastern Energy Gas' intercompany credit agreement.
Operating Activities
Net cash flows from operating activities for the nine-month periods ended September 30, 2021 and 2020 were $867 million and $1.3 billion, respectively. The change was primarily due to lower collections from affiliates, lower income tax receipts, lower distributions from equity method investments and the timing of payments of operating costs.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the nine-month periods ended September 30, 2021 and 2020 were $(201) million and $2.9 billion, respectively. The change was primarily due to a decrease in repayments of loans by affiliates of $3.2 billion, partially offset by a decrease in loans to affiliates of $55 million.
Financing Activities
Net cash flows from financing activities for the nine-month period ended September 30, 2021 were $(607) million. Sources of cash totaled $256 million and consisted of proceeds from equity contributions, that primarily included a contribution from its indirect parent, BHE, to Eastern Energy Gas to assist in the repayment of $500 million of debt. Uses of cash totaled $863 million and consisted mainly of repayments of long-term debt of $500 million, distributions to noncontrolling interests from Cove Point of $353 million and repayment of notes to affiliates of $9 million.
Net cash flows from financing activities for the nine-month period ended September 30, 2020 were $(4.2) billion. Sources of cash totaled $299 million and consisted of equity contributions. Uses of cash totaled $4.5 billion and consisted mainly of distributions to DEI of $4.2 billion, repayment of notes to affiliates of $253 million and repayments of short-term debt of $62 million.
Future Uses of Cash
Eastern Energy Gas 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 use of credit agreements, capital contributions 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 Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; 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 acquisition of existing assets.
Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Nine-Month Periods | | Annual |
| Ended September 30, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Natural gas transmission and storage | $ | 89 | | | $ | 15 | | | $ | 22 | |
Other | 169 | | | 276 | | | 454 | |
Total | $ | 258 | | | $ | 291 | | | $ | 476 | |
Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.
Contractual Obligations
As of September 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 Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020.
Regulatory Matters
Eastern Energy Gas is subject to comprehensive regulation. Refer to Note 4 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, air and water quality, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, 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 and local agencies. Eastern Energy Gas 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.
Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2020.
Item 3.Quantitative and Qualitative Disclosures About Market Risk
For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019.2020. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2019.2020. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2020.2021.
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Item 4. | Controls and Procedures |
Item 4.Controls and Procedures
At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, and Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended September 30, 20202021 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
PART II
Item 1.Legal Proceedings
Berkshire Hathaway Energy and PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et.et al. vs.v. PacifiCorp et al., Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed on behalf of certain namedby Oregon residents and businesses andwho seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon beginning on or after September 7, 2020.allegedly caused by PacifiCorp. On November 3, 2021, the plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain, South Obenchain, Two Four Two and Santiam Canyon (also known as Beachie Creek) fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The amended complaint was amended November 2, 2020 to seekseeks the following damages:damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses in excess of not less than $600 million; (ii)(iii) double the amount of property and economic damages based on alleged gross negligence; (iii)damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (iv)(v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages.
On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21cv33595, Multnomah County, Oregon, in which two complaints, Case No. 21cv09339 and Case No. 21cv09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek Fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek Fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) prejudgmentalternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to allege claimsadd a claim for punitive damages.
Other individual lawsuits alleging similar claims have been filed in Oregon and California related to the 2020 wildfires.Wildfires. Investigations as tointo the causecauses and originorigins of thethose wildfires are ongoing.
For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.
Item 1A.Risk Factors
There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2019, except as disclosed below.2020.
Each Registrant's business could be adversely affected by COVID-19 or other pathogens, or similar crises.
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Each Registrant's business could be adversely affected by the worldwide outbreak of COVID-19 generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services and thereby reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. For example, if the tourism industry in Nevada experiences a significant and extended decrease as a result of changes in customer behavior, demand for electricity sold by Nevada Power and Sierra Pacific could decrease. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local legislation related to COVID-19 (or other similar laws, regulations, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related assessment of late fees, due to non-payment or other circumstances. Certain Registrants have already temporarily implemented certain of these measures, either voluntarily or in accordance with requirements of the respective Registrant's public utility commissions. These requirements will likely remain for the duration of the COVID-19 emergency. Additionally, HomeServices' residential real estate brokerage business could experience a decline (which could be significant) in residential property transactions if potential customers elect to defer purchases in reaction to any substantial outbreak, or fear of such outbreak, of COVID-19 or other pathogen, or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.
Further, the recent outbreak of COVID-19, or another pathogen, could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of PacifiCorp's and MidAmerican Energy's wind-powered generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.
Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.
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Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
On October 29, 2020, BHE issued 3,750,000 shares of its 4.00% Perpetual Preferred Stock (the "Perpetual Preferred") to certain subsidiaries of its parent, Berkshire Hathaway, for an aggregate purchase price of $3.75 billion (the "New Preferred Investment"), in order to provide funding for (i) the GT&S Cash Consideration and (ii) the Q-Pipe Cash Consideration, each as defined in Note 2 of the Notes to Consolidated Financial Statements of BHE in Part I, Item 1 of this Form 10-Q.
The New Preferred Investment was effected pursuant to a private placement and was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.
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Item 3. | Defaults Upon Senior Securities |
Not applicable.
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Item 4. | Mine Safety Disclosures |
Item 3.Defaults Upon Senior Securities
Not applicable.
Item 4.Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.
Item 5.Other Information
Not applicable.
Item 6.Exhibits
The following is a list of exhibits filed as part of this Quarterly Report.
BERKSHIRE HATHAWAY ENERGY
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4.1 | Fourteenth Supplemental Indenture, dated as of March 24, 2020, by and between Berkshire Hathaway EnergyNorthern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., as trustee,Fiscal Agent, relating to the 4.05% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to$550,000,000 in principal amount of the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 25, 2020). |
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4.510.1 | Twenty-Third Supplemental Indenture, dated as of September 11, 2020, by$3,500,000,000 Second Amended and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, as trustee, relating to the C$225,000,000 in principal amount of the 1.509% Series 2020-1 Senior Secured Notes due 2021. |
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10.1 | Restated Credit Agreement, dated as of April 27, 2020,June 30, 2021, among AltaLink, L.P.,Berkshire Hathaway Energy Company, as borrower, AltaLink Management Ltd.,Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as general partner, TheInitial Lenders, MUFG Union Bank, of Nova Scotia,N.A, as administrative agent,Administrative Agent and Lendersthe LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020)2021). |
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10.215.1 | Credit Agreement, dated as of April 27, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020). |
PACIFICORP
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
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9510.2 | $1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 30, 2021, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, asInitial Lenders, JP Morgan Chase Bank, N.A. as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.2 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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95 | |
MIDAMERICAN ENERGY
BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY
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4.3 | |
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10.34.4 | |
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10.3 | $600,000,000, 364-Day1,500,000,000 Second Amended and Restated Credit Agreement, dated as of May 12, 2020,June 30, 2021, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and Mizuho Bank, Ltd., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020)2021). |
MIDAMERICAN FUNDING
NEVADA POWER
SIERRA PACIFIC
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
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31.1110.4 | $400,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
SIERRA PACIFIC
ALL REGISTRANTS
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
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10.5 | $250,000,000 Fourth Amended and Restated Credit Agreement, dated as of June 30, 2021, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.5 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
EASTERN ENERGY GAS
BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
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4.5 | Fifteenth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, as trustee, to the Indenture dated as of October 1, 2013, by and between Eastern Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas (incorporated by reference to Exhibit 4.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated July 1, 2021). |
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4.6 | |
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4.7 | First Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.900% Senior Notes due 2049 (incorporated by reference to Exhibit 4.7 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.8 | Second Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.600% Senior Notes due 2044 (incorporated by reference to Exhibit 4.8 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.9 | Third Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 4.800% Senior Notes due 2043 (incorporated by reference to Exhibit 4.9 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.10 | Fourth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.000% Senior Notes due 2029 (incorporated by reference to Exhibit 4.10 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
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4.11 | Fifth Supplemental Indenture, dated as of June 30, 2021, by and between Eastern Gas Transmission and Storage, Inc. and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of June 30, 2021, and relating to the 3.600% Senior Notes due 2024 (incorporated by reference to Exhibit 4.11 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended June 30, 2021). |
ALL REGISTRANTS
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101 | The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020,2021, is formatted in XBRL (eXtensibleiXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail. |
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104 | Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| BERKSHIRE HATHAWAY ENERGY COMPANY |
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| BERKSHIRE HATHAWAY ENERGY COMPANY |
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Date: November 6, 20205, 2021 | /s/ Calvin D. Haack |
| Calvin D. Haack |
| Senior Vice President and Chief Financial Officer |
| (principal financial and accounting officer) |
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| PACIFICORP |
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Date: November 6, 20205, 2021 | /s/ Nikki L. Kobliha |
| Nikki L. Kobliha |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| MIDAMERICAN FUNDING, LLC |
| MIDAMERICAN ENERGY COMPANY |
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Date: November 6, 20205, 2021 | /s/ Thomas B. Specketer |
| Thomas B. Specketer |
| Vice President and Controller |
| of MidAmerican Funding, LLC and |
| Vice President and Chief Financial Officer |
| of MidAmerican Energy Company |
| (principal financial and accounting officer) |
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| NEVADA POWER COMPANY |
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Date: November 6, 20205, 2021 | /s/ Michael E. Cole |
| Michael E. Cole |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| SIERRA PACIFIC POWER COMPANY |
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Date: November 6, 20205, 2021 | /s/ Michael E. Cole |
| Michael E. Cole |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |
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| EASTERN ENERGY GAS HOLDINGS, LLC |
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Date: November 5, 2021 | /s/ Scott C. Miller |
| Scott C. Miller |
| Vice President, Chief Financial Officer and Treasurer |
| (principal financial and accounting officer) |