CONSOLIDATED
BALANCE SHEETS—(Continued)STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
| | September 30, 2020 | | | December 31, 2019(1) | |
(millions) | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | | | | | | | |
Securities due within one year | | $ | 1,199 | | | $ | 700 | |
Short-term debt | | | 0 | | | | 62 | |
Accounts payable | | | 81 | | | | 59 | |
Payables to affiliates | | | 97 | | | | 82 | |
Affiliated current borrowings | | | 7 | | | | 260 | |
Accrued interest, payroll and taxes | | | 160 | | | | 128 | |
Derivative liabilities | | | 186 | | | | 33 | |
Other(2) | | | 159 | | | | 128 | |
Total current liabilities | | | 1,889 | | | | 1,452 | |
Long-Term Debt | | | | | | | | |
Long-term debt | | | 4,337 | | | | 4,821 | |
Finance leases | | | 4 | | | | 5 | |
Total long-term debt | | | 4,341 | | | | 4,826 | |
Deferred Credits and Other Liabilities | | | | | | | | |
Deferred income taxes | | | 1,189 | | | | 1,288 | |
Other | | | 978 | | | | 989 | |
Total deferred credits and other liabilities | | | 2,167 | | | | 2,277 | |
Total liabilities | | | 8,397 | | | | 8,555 | |
Commitments and Contingencies (see Note 14) | | | | | | | | |
Equity | | | | | | | | |
Membership interests | | | 5,343 | | | | 9,031 | |
Accumulated other comprehensive loss | | | (164 | ) | | | (187 | ) |
Total members' equity | | | 5,179 | | | | 8,844 | |
Noncontrolling interests | | | 1,371 | | | | 1,385 | |
Total equity | | | 6,550 | | | | 10,229 | |
Total liabilities and equity | | $ | 14,947 | | | $ | 18,784 | |
(1)
| Eastern Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.
|
(2)
| See Note 16 for amounts attributable to related parties.
|
(Amounts in millions)
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| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Net income | | | | | $ | 110 | | | $ | 673 | |
| | | | | | | |
Other comprehensive income (loss), net of tax: | | | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $4 and $11 | | | | | 7 | | | 34 | |
Foreign currency translation adjustment | | | | | 91 | | | (548) | |
Unrealized gains (losses) on cash flow hedges, net of tax of $5 and $(10) | | | | | 14 | | | (33) | |
Total other comprehensive income (loss), net of tax | | | | | 112 | | | (547) | |
| | | | | | | |
Comprehensive income | | | | | 222 | | | 126 | |
Comprehensive income attributable to noncontrolling interests | | | | | 106 | | | 3 | |
Comprehensive income attributable to BHE shareholders | | | | | $ | 116 | | | $ | 123 | |
The accompanying notes are an integral part of
Eastern Energy’s Consolidated Financial Statements.these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY
GAS HOLDINGS, LLCCOMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
CHANGES IN EQUITY
(Unaudited)
QUARTER-TO-DATE
| | Predecessor Equity | | | Membership Interests | | | AOCI | | | Total Members' Equity | | | Noncontrolling Interests | | | Total | |
(millions) | | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2019 | | $ | 2,859 | | | $ | 4,729 | | | $ | (186 | ) | | $ | 7,402 | | | $ | 1,427 | | | $ | 8,829 | |
Net income | | | 59 | | | | 92 | | | | | | | | 151 | | | | 24 | | | | 175 | |
Dividends and distributions | | | (189 | ) | | | | | | | | | | | (189 | ) | | | (51 | ) | | | (240 | ) |
Other comprehensive loss, net of tax | | | | | | | | | | | (27 | ) | | | (27 | ) | | | | | | | (27 | ) |
Other | | | 4 | | | | | | | | | | | | 4 | | | | | | | | 4 | |
September 30, 2019 | | $ | 2,733 | | | $ | 4,821 | | | $ | (213 | ) | | $ | 7,341 | | | $ | 1,400 | | | $ | 8,741 | |
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June 30, 2020 | | $ | — | | | $ | 7,352 | | | $ | (271 | ) | | $ | 7,081 | | | $ | 1,375 | | | $ | 8,456 | |
Net income | | | | | | | 86 | | | | | | | | 86 | | | | 32 | | | | 118 | |
Dividends and distributions | | | | | | | (2,394 | ) | | | | | | | (2,394 | ) | | | (36 | ) | | | (2,430 | ) |
Equity contributions from Dominion Energy Questar | | | | | | | 299 | | | | | | | | 299 | | | | | | | | 299 | |
Other comprehensive income, net of tax | | | | | | | | | | | 107 | | | | 107 | | | | | | | | 107 | |
September 30, 2020 | | $ | — | | | $ | 5,343 | | | $ | (164 | ) | | $ | 5,179 | | | $ | 1,371 | | | $ | 6,550 | |
(Amounts in millions)YEAR-TO-DATE
| | Predecessor Equity | | | Membership Interests | | | AOCI | | | Total Members' Equity | | | Noncontrolling Interests | | | Total | |
(millions) | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | | $ | 1,804 | | | $ | 4,566 | | | $ | (169 | ) | | $ | 6,201 | | | $ | 2,664 | | | $ | 8,865 | |
Net income | | | 205 | | | | 255 | | | | | | | | 460 | | | | 90 | | | | 550 | |
Acquisition of public interest in Dominion Energy Midstream | | | 1,181 | | | | | | | | | | | | 1,181 | | | | (1,221 | ) | | | (40 | ) |
Dividends and distributions | | | (457 | ) | | | | | | | | | | | (457 | ) | | | (132 | ) | | | (589 | ) |
Other comprehensive loss, net of tax | | | | | | | | | | | (44 | ) | | | (44 | ) | | | (1 | ) | | | (45 | ) |
September 30, 2019 | | $ | 2,733 | | | $ | 4,821 | | | $ | (213 | ) | | $ | 7,341 | | | $ | 1,400 | | | $ | 8,741 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2019 | | $ | — | | | $ | 9,031 | | | $ | (187 | ) | | $ | 8,844 | | | $ | 1,385 | | | $ | 10,229 | |
Net income | | | | | | | 57 | | | | | | | | 57 | | | | 97 | | | | 154 | |
Dividends and distributions | | | | | | | (4,044 | ) | | | | | | | (4,044 | ) | | | (111 | ) | | | (4,155 | ) |
Equity contributions from Dominion Energy Questar | | | | | | | 299 | | | | | | | | 299 | | | | | | | | 299 | |
Other comprehensive income, net of tax | | | | | | | | | | | 23 | | | | 23 | | | | | | | | 23 | |
September 30, 2020 | | $ | — | | | $ | 5,343 | | | $ | (164 | ) | | $ | 5,179 | | | $ | 1,371 | | | $ | 6,550 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| BHE Shareholders' Equity | | | |
| | | | | | | Long-term | | | | Accumulated | | | | |
| | | | | Additional | | Income | | | | Other | | | | |
| Preferred | | Common | | Paid-in | | Tax | | Retained | | Comprehensive | | Noncontrolling | | Total |
| Stock | | Stock | | Capital | | Receivable | | Earnings | | Loss, Net | | Interests | | Equity |
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Balance, December 31, 2019 | $ | 0 | | | $ | 0 | | | $ | 6,389 | | | $ | (530) | | | $ | 28,296 | | | $ | (1,706) | | | $ | 129 | | | $ | 32,578 | |
Net income | — | | | 0 | | | 0 | | | — | | | 670 | | | 0 | | | 3 | | | 673 | |
Other comprehensive loss | — | | | 0 | | | 0 | | | — | | | 0 | | | (547) | | | 0 | | | (547) | |
Common stock purchases | — | | | 0 | | | (6) | | | — | | | (120) | | | 0 | | | 0 | | | (126) | |
Distributions | — | | | 0 | | | 0 | | | — | | | 0 | | | 0 | | | (5) | | | (5) | |
Other equity transactions | — | | | 0 | | | (1) | | | — | | | 0 | | | 0 | | | 0 | | | (1) | |
Balance, March 31, 2020 | $ | 0 | | | $ | 0 | | | $ | 6,382 | | | $ | (530) | | | $ | 28,846 | | | $ | (2,253) | | | $ | 127 | | | $ | 32,572 | |
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Balance, December 31, 2020 | $ | 3,750 | | | $ | 0 | | | $ | 6,377 | | | $ | (658) | | | $ | 35,093 | | | $ | (1,552) | | | $ | 3,967 | | | $ | 46,977 | |
Net income | — | | | 0 | | | 0 | | | — | | | 4 | | | 0 | | | 106 | | | 110 | |
Other comprehensive income | — | | | 0 | | | 0 | | | — | | | 0 | | | 112 | | | 0 | | | 112 | |
Preferred stock dividend | — | | | — | | | — | | | — | | | (38) | | | — | | | — | | | (38) | |
| | | | | | | | | | | | | | | |
Distributions | — | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | (113) | | | (113) | |
| | | | | | | | | | | | | | | |
Other equity transactions | — | | | 0 | | | 0 | | | 0 | | | 1 | | | 0 | | | 2 | | | 3 | |
Balance, March 31, 2021 | $ | 3,750 | | | $ | 0 | | | $ | 6,377 | | | $ | (658) | | | $ | 35,060 | | | $ | (1,440) | | | $ | 3,962 | | | $ | 47,051 | |
The accompanying notes are an integral part of
Eastern Energy’s Consolidated Financial Statements.these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY
GAS HOLDINGS, LLCCOMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended September 30, | | 2020 | | | 2019 | |
(millions) | | | | | | | | |
Operating Activities | | | | | | | | |
Net income including noncontrolling interests | | $ | 154 | | | $ | 550 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | | | 282 | | | | 344 | |
Deferred income taxes | | | (103 | ) | | | 40 | |
Charge related to a voluntary retirement program | | | 0 | | | | 40 | |
Impairment of assets and other charges | | | 463 | | | | 13 | |
Gains on sales of assets | | | 0 | | | | (7 | ) |
Other adjustments | | | 30 | | | | 67 | |
Changes in: | | | | | | | | |
Accounts receivable | | | 41 | | | | 107 | |
Affiliated receivables and payables | | | 225 | | | | (34 | ) |
Inventories | | | (6 | ) | | | (51 | ) |
Prepayments | | | (17 | ) | | | 31 | |
Accounts payable | | | 12 | | | | (110 | ) |
Accrued interest, payroll and taxes | | | 32 | | | | (45 | ) |
Customer deposits | | | 4 | | | | (82 | ) |
Pension and other postretirement benefits | | | (46 | ) | | | (105 | ) |
Other operating assets and liabilities | | | 188 | | | | (34 | ) |
Net cash provided by operating activities | | | 1,259 | | | | 724 | |
Investing Activities | | | | | | | | |
Plant construction and other property additions | | | (258 | ) | | | (537 | ) |
Repayment of loan by Dominion Energy to Cove Point | | | 0 | | | | 2,986 | |
Repayment of loans by affiliates | | | 3,422 | | | | 0 | |
Advances to affiliates, net of repayments | | | (225 | ) | | | 0 | |
Other | | | (9 | ) | | | (19 | ) |
Net cash provided by investing activities | | | 2,930 | | | | 2,430 | |
Financing Activities | | | | | | | | |
Issuance (repayment) of short-term debt, net | | | (62 | ) | | | 270 | |
Issuance (repayment) of affiliated current borrowings, net | | | (253 | ) | | | 32 | |
Repayment of long-term debt | | | 0 | | | | (3,300 | ) |
Issuance of affiliated long-term debt | | | 0 | | | | 395 | |
Repayment of credit facility borrowings | | | 0 | | | | (73 | ) |
Equity contributions from Dominion Energy Questar | | | 299 | | | | 0 | |
Dividends and distributions | | | (4,155 | ) | | | (589 | ) |
Other | | | (1 | ) | | | (1 | ) |
Net cash used in financing activities | | | (4,172 | ) | | | (3,266 | ) |
Increase (decrease) in cash, restricted cash and equivalents | | | 17 | | | | (112 | ) |
Cash, restricted cash and equivalents at beginning of period | | | 39 | | | | 198 | |
Cash, restricted cash and equivalents at end of period | | $ | 56 | | | $ | 86 | |
Supplemental Cash Flow Information | | | | | | | | |
Significant noncash investing and financing activities: | | | | | | | | |
Accrued capital expenditures | | $ | 44 | | | $ | 19 | |
Financing leases | | | 1 | | | | 10 | |
(Amounts in millions) | | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 110 | | | $ | 673 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Losses (gains) on marketable securities, net | 1,118 | | | (27) | |
Depreciation and amortization | 927 | | | 821 | |
Allowance for equity funds | (26) | | | (34) | |
Equity loss, net of distributions | 221 | | | 29 | |
Changes in regulatory assets and liabilities | (9) | | | 0 | |
Deferred income taxes and amortization of investment tax credits | (135) | | | 47 | |
Other, net | 9 | | | 63 | |
Changes in other operating assets and liabilities, net of effects from acquisitions: | | | |
Trade receivables and other assets | (249) | | | (118) | |
Derivative collateral, net | 14 | | | (19) | |
Pension and other postretirement benefit plans | (21) | | | (23) | |
Accrued property, income and other taxes, net | (453) | | | (364) | |
Accounts payable and other liabilities | 19 | | | 117 | |
Net cash flows from operating activities | 1,525 | | | 1,165 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (1,295) | | | (1,356) | |
| | | |
Purchases of marketable securities | (128) | | | (188) | |
Proceeds from sales of marketable securities | 104 | | | 180 | |
Equity method investments | (26) | | | (153) | |
Other, net | (29) | | | 43 | |
Net cash flows from investing activities | (1,374) | | | (1,474) | |
| | | |
Cash flows from financing activities: | | | |
Proceeds from BHE senior debt | 0 | | | 3,231 | |
Repayments of BHE senior debt | (450) | | | (350) | |
| | | |
Common stock purchases | 0 | | | (126) | |
Proceeds from subsidiary debt | 0 | | | 1,093 | |
Repayments of subsidiary debt | (26) | | | (1,347) | |
Net proceeds from (repayments of) short-term debt | 409 | | | (1,109) | |
| | | |
Distributions to noncontrolling interests | (115) | | | (2) | |
Other, net | (9) | | | (32) | |
Net cash flows from financing activities | (191) | | | 1,358 | |
| | | |
Effect of exchange rate changes | 1 | | | (13) | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (39) | | | 1,036 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 1,445 | | | 1,268 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 1,406 | | | $ | 2,304 | |
The accompanying notes are an integral part of
Eastern Energy’s Consolidated Financial Statements.these consolidated financial statements.
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
Note 1. Nature of Operations
Eastern
(1) General
Berkshire Hathaway Energy Company ("BHE") is a holding company that conductsowns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized as 8 business activitiessegments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through FERC-regulatedthese locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas transmission pipeline companies and undergroundinterests in a liquefied natural gas ("LNG") export, import and storage systemsfacility in the eastern regionUnited States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the U.S., as well as the Cove Point LNG Facility and owns a 50% noncontrolling interest in Iroquois. Through October 31, 2020, Eastern Energy also conducted business activities through FERC-regulated interstate natural gas transmission pipeline and underground storage systemslargest residential real estate brokerage franchise networks in the Rocky Mountain RegionUnited States.
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of
the U.S. and owned a 50% noncontrolling interest in White River Hub. Beginning in September 2020, Eastern Energy manages its daily operations through one segment, which includes its gas transmission and storage operations. See Note 3America ("GAAP") for
interim financial information
on the acquisition of Eastern Energy by BHE and the
Dominion Energy Gas Restructuring.Note 2. Significant Accounting Policies
As permitted by theUnited 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 SEC, Eastern Energy’s accompanyingdisclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. Theseall adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements shouldas of March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 are not necessarily indicative of the results to be readexpected for the full year.
The preparation of the unaudited Consolidated Financial Statements in
conjunctionconformity 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’sthe Company's Annual Report on Form 10-K for the year ended December 31,
2019.In Eastern Energy’s opinion,2020 describes the accompanyingmost significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly its financial position at September 30, 2020, its results of operations and changes in equity for the three and nine months ended September 30, 2020 and 2019 and its cash flows for the nine months ended September 30, 2020 and 2019. Such adjustments are normal and recurring in nature unless otherwise noted.
Eastern Energy makes certain estimates and assumptions in preparing its Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.
Eastern Energy’s accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, its accounts, those of its respective majority-owned subsidiaries and non-wholly-owned entities in which it has a controlling financial interest. Brookfield’s 25% interest in Cove Point (effective December 2019) and the public’s ownership interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Eastern Energy’s Consolidated Financial Statements.
The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, other energy-related purchases, purchased gas expenses and other factors.
Certain amounts in Eastern Energy’s 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2020 presentation for comparative purposes; however, such reclassifications did not affect net income, total assets, liabilities, equity or cash flows.
There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.
(2) Business Acquisition
BHE GT&S Acquisition
Transaction Description
On November 1, 2020, BHE completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("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"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash Consideration"), and assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a 25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP), consisting of 100% of the general partnership interest and 25% of the total limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and approval by the Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the transfer of certain licenses earlier in 2020.
On October 5, 2020, DEI and Dominion Questar, as permitted under the terms of the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the Questar Pipeline Group from NoteDominion Questar (the "Q-Pipe Transaction") after receipt of HSR Approval, which is currently anticipated in the first half of 2021, for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI is also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.
Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which is included in other current assets on the Consolidated Balance Sheet as of March 31, 2021 and December 31, 2020, to Dominion Questar on November 2, 2020. If the Q-Pipe Transaction does not close, Dominion Questar has agreed to repay all or (depending on the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021. If HSR Approval has not been obtained by June 30, 2021, upon BHE's written request, Dominion Questar will seek alternative buyers for all or a material portion of the Questar Pipeline Group (an "Alternative Transaction"). The Purchase Price Repayment Amount may be paid in cash or in shares of common stock, no par value, of DEI, or a combination thereof, subject to certain limitations as to stock repayments set forth in the Q-Pipe Purchase Agreement; provided any payment on or after December 15, 2021 must be paid in cash only.
The assets acquired in the GT&S Transaction include (i) approximately 5,400 miles of operated natural gas transmission, gathering and storage pipelines with approximately 12.5 billion cubic feet ("Bcf") per day of design capacity; (ii) 420 Bcf of operated natural gas storage design capacity, of which 306 Bcf is owned by BHE GT&S; and (iii) an LNG export, import and storage facility with LNG storage capacity of approximately 14.6 billions of cubic feet equivalent.
On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.
Included in BHE's Consolidated Statement of Operations within the BHE Pipeline Group reportable segment for the three-month periods ended March 31, 2021, is operating revenue and net income attributable to BHE shareholders of $559 million and $107 million, respectively, as a result of including BHE GT&S from November 1, 2020.
Preliminary Allocation of Purchase Price
BHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission ("FERC") and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.
The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.
The fair value of certain contracts and property, plant and equipment related to non-regulated operations, certain regulatory assets and other items included in rate base, an equity method investment and deferred income tax amounts are provisional and are subject to revision for up to 12 months following the acquisition date until the related valuations are completed. These items may be adjusted through regulatory assets or liabilities, to the extent recoverable in rates, or goodwill provided additional information is obtained about the facts and circumstances that existed as of the acquisition date. Such information includes, but is not limited to, the receipt of further information regarding the fair value of the contracts and property, plant and equipment related to non-regulated operations, the equity method investment and any associated deferred income tax amounts as well as the evolution of the rate-making process for regulated operations.
The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):
| | | | | | | | |
| | Fair Value |
| | |
Current assets, including cash and cash equivalents of $104 | | $ | 569 | |
Property, plant and equipment | | 9,254 | |
Goodwill | | 1,732 | |
Regulatory assets | | 108 | |
Deferred income taxes | | 275 | |
Other long-term assets | | 1,424 | |
Total assets | | 13,362 | |
| | |
Current liabilities, including current portion of long-term debt of $1,200 | | 1,567 | |
Long-term debt, less current portion | | 4,415 | |
Regulatory liabilities | | 661 | |
Other long-term liabilities | | 289 | |
Total liabilities | | 6,932 | |
Noncontrolling interest | | 3,916 | |
Net assets acquired | | $ | 2,514 | |
Goodwill
The excess of the purchase price paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain items, book and tax goodwill will differ. The amount of tax goodwill is approximately $0.9 billion and will be amortized over 15 years.
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of BHE and the amortization of the purchase price adjustments assuming the acquisition had taken place on January 1, 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):
| | | | | |
| Three-Month Period |
| Ended March 31, 2020 |
| |
Operating revenue | $ | 5,056 | |
| |
Net income attributable to BHE shareholders | $ | 773 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| Depreciable | | March 31, | | December 31, |
| Life | | 2021 | | 2020 |
Regulated assets: | | | | | |
Utility generation, transmission and distribution systems | 5-80 years | | $ | 87,898 | | | $ | 86,730 | |
Interstate natural gas pipeline assets | 3-80 years | | 16,712 | | | 16,667 | |
| | | 104,610 | | | 103,397 | |
Accumulated depreciation and amortization | | | (31,653) | | | (30,662) | |
Regulated assets, net | | | 72,957 | | | 72,735 | |
| | | | | |
Nonregulated assets: | | | | | |
Independent power plants | 5-30 years | | 7,034 | | | 7,012 | |
Other assets | 3-40 years | | 5,794 | | | 5,659 | |
| | | 12,828 | | | 12,671 | |
Accumulated depreciation and amortization | | | (2,337) | | | (2,586) | |
Nonregulated assets, net | | | 10,491 | | | 10,085 | |
| | | | | |
Net operating assets | | | 83,448 | | | 82,820 | |
Construction work-in-progress | | | 3,309 | | | 3,308 | |
Property, plant and equipment, net | | | $ | 86,757 | | | $ | 86,128 | |
Construction work-in-progress includes $2.9 billion as of March 31, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.
(4) Investments and Restricted Cash and Cash Equivalents and Investments
Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
Investments: | | | |
BYD Company Limited common stock | $ | 4,773 | | | $ | 5,897 | |
Rabbi trusts | 452 | | | 440 | |
Other | 288 | | | 263 | |
Total investments | 5,513 | | | 6,600 | |
| | | |
Equity method investments: | | | |
BHE Renewables tax equity investments | 5,399 | | | 5,626 | |
Iroquois Gas Transmission System, L.P. | 586 | | | 580 | |
Electric Transmission Texas, LLC | 581 | | | 594 | |
JAX LNG, LLC | 80 | | | 75 | |
Bridger Coal Company | 68 | | | 74 | |
Other | 113 | | | 118 | |
Total equity method investments | 6,827 | | | 7,067 | |
| | | |
Restricted cash and cash equivalents and investments: | | | |
Quad Cities Station nuclear decommissioning trust funds | 697 | | | 676 | |
Other restricted cash and cash equivalents | 130 | | | 155 | |
Total restricted cash and cash equivalents and investments | 827 | | | 831 | |
| | | |
Total investments and restricted cash and cash equivalents and investments | $ | 13,167 | | | $ | 14,498 | |
| | | |
Reflected as: | | | |
Current assets | $ | 157 | | | $ | 178 | |
Noncurrent assets | 13,010 | | | 14,320 | |
Total investments and restricted cash and cash equivalents and investments | $ | 13,167 | | | $ | 14,498 | |
Investments
(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Unrealized (losses) gains recognized on marketable securities still held at the reporting date | | | | | $ | (1,119) | | | $ | 25 | |
Net gains recognized on marketable securities sold during the period | | | | | 1 | | | 2 | |
(Losses) gains on marketable securities, net | | | | | $ | (1,118) | | | $ | 27 | |
Equity Method Investments
The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. 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. Certain of the Company's tax equity investments are located in Texas and have physical settlement hedge obligations that were negatively impacted due to production shortfalls during periods of extreme market pricing volatility as a result of the February 2021 polar vortex weather event. The Company recognized pre-tax equity losses of $218 million, or after-tax losses of $23 million inclusive of production tax credits ("PTCs") of $148 million and other income tax benefits of $47 million, during the three-month period ended March 31, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as amended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of March 31, 2021, the carrying value of the impacted tax equity investments totaled $2.8 billion.
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 March 31, 2021 and December 31, 2020, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 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 |
| March 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 1,276 | | | $ | 1,290 | |
Restricted cash and cash equivalents | 117 | | | 140 | |
Investments and restricted cash and cash equivalents and investments | 13 | | | 15 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 1,406 | | | $ | 1,445 | |
(5) Recent Financing Transactions
Long-Term Debt
In April 2021, Northern Natural Gas issued $550 million of 3.40% Senior Bonds due October 2051. Northern Natural Gas used the net proceeds to early redeem in April 2021 all of its $200 million, 4.25% Senior Notes originally due June 2021 and for general corporate purposes.
Credit Facilities
In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving credit facility to April 2022, by exercising a one-year extension option.
(6) Income Taxes
The effective income tax rate for the three-month period ended March 31, 2021, is 217% and results from a $535 million income tax benefit associated with a $246 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,124 million on the Company's investment in BYD Company Limited. The $535 million income tax benefit is primarily comprised of a $52 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss, a $334 million benefit (136%) from income tax credits and a $51 million benefit (21%) from state income tax benefits, net of federal income tax impacts.
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
Income tax credits | | | | | 136 | | | (46) | |
State income tax, net of federal income tax impacts | | | | | 21 | | | 0 | |
Income tax effect of foreign income | | | | | 6 | | | (3) | |
Effects of ratemaking | | | | | 10 | | | (8) | |
Equity income | | | | | 15 | | | (1) | |
Noncontrolling interest | | | | | 9 | | | 0 | |
Other, net | | | | | (1) | | | 1 | |
Effective income tax rate | | | | | 217 | % | | (36) | % |
Income tax credits relate primarily to PTCs from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. 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. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $315 million and $233 million, respectively.
The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company made 0 payments for federal income taxes to Berkshire Hathaway for the three-month period ended March 31, 2021, and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the three-month period ended March 31, 2020.
(7) Employee Benefit Plans
Domestic Operations
Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | | | | | $ | 7 | | | $ | 3 | |
Interest cost | | | | | 20 | | | 23 | |
Expected return on plan assets | | | | | (33) | | | (35) | |
Net amortization | | | | | 6 | | | 9 | |
Net periodic benefit cost | | | | | $ | 0 | | | $ | 0 | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | | | | | $ | 2 | | | $ | 1 | |
Interest cost | | | | | 5 | | | 6 | |
Expected return on plan assets | | | | | (5) | | | (9) | |
Net amortization | | | | | (1) | | | (1) | |
Net periodic benefit cost (credit) | | | | | $ | 1 | | | $ | (3) | |
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 domestic pension and other postretirement benefit plans are expected to be $13 million and $13 million, respectively, during 2021. As of March 31, 2021, $3 million and $3 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Service cost | | | | | $ | 4 | | | $ | 4 | |
Interest cost | | | | | 8 | | | 10 | |
Expected return on plan assets | | | | | (28) | | | (25) | |
| | | | | | | |
Net amortization | | | | | 14 | | | 10 | |
Net periodic benefit credit | | | | | $ | (2) | | | $ | (1) | |
Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £50 million during 2021. As of March 31, 2021, £11 million, or $15 million, of contributions had been made to the United Kingdom pension plan.
(8) Fair Value Measurements
The carrying value of the Company'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. The Company 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 Eastern Energy’sactive markets for identical assets or liabilities that the Company 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 the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.
The following table presents the Company'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 March 31, 2021 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | 1 | | | $ | 72 | | | $ | 154 | | | $ | (18) | | | $ | 209 | |
Foreign currency exchange rate derivatives | | — | | | 12 | | | — | | | — | | | 12 | |
Interest rate derivatives | | 0 | | | 33 | | | 47 | | | — | | | 80 | |
Mortgage loans held for sale | | 0 | | | 2,065 | | | 0 | | | — | | | 2,065 | |
Money market mutual funds(2) | | 807 | | | 0 | | | 0 | | | — | | | 807 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 210 | | | 0 | | | 0 | | | — | | | 210 | |
International government obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Corporate obligations | | 0 | | | 71 | | | 0 | | | — | | | 71 | |
Municipal obligations | | 0 | | | 2 | | | 0 | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Equity securities: | | | | | | | | | | |
United States companies | | 395 | | | 0 | | | 0 | | | — | | | 395 | |
International companies | | 4,780 | | | 0 | | | 0 | | | — | | | 4,780 | |
Investment funds | | 256 | | | 0 | | | 0 | | | — | | | 256 | |
| | $ | 6,449 | | | $ | 2,265 | | | $ | 201 | | | $ | (18) | | | $ | 8,897 | |
Liabilities: | | | | | | | | | | |
Commodity derivatives | | $ | 0 | | | $ | (90) | | | $ | (30) | | | $ | 39 | | | $ | (81) | |
Foreign currency exchange rate derivatives | | — | | | (1) | | | — | | | — | | | (1) | |
Interest rate derivatives | | (3) | | | (14) | | | (6) | | | — | | | (23) | |
| | $ | (3) | | | $ | (105) | | | $ | (36) | | | $ | 39 | | | $ | (105) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2020 | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | 1 | | | $ | 73 | | | $ | 135 | | | $ | (21) | | | $ | 188 | |
Foreign currency exchange rate derivatives | | — | | | 20 | | | — | | | — | | | 20 | |
Interest rate derivatives | | 0 | | | 0 | | | 62 | | | — | | | 62 | |
Mortgage loans held for sale | | 0 | | | 2,001 | | | 0 | | | — | | | 2,001 | |
Money market mutual funds(2) | | 873 | | | 0 | | | 0 | | | — | | | 873 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 200 | | | 0 | | | 0 | | | — | | | 200 | |
International government obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Corporate obligations | | 0 | | | 73 | | | 0 | | | — | | | 73 | |
Municipal obligations | | 0 | | | 2 | | | 0 | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | 0 | | | 6 | | | 0 | | | — | | | 6 | |
Equity securities: | | | | | | | | | | |
United States companies | | 381 | | | 0 | | | 0 | | | — | | | 381 | |
International companies | | 5,906 | | | 0 | | | 0 | | | — | | | 5,906 | |
Investment funds | | 201 | | | 0 | | | 0 | | | — | | | 201 | |
| | $ | 7,562 | | | $ | 2,180 | | | $ | 197 | | | $ | (21) | | | $ | 9,918 | |
Liabilities: | | | | | | | | | | |
Commodity derivatives | | $ | (1) | | | $ | (90) | | | $ | (19) | | | $ | 56 | | | $ | (54) | |
Foreign currency exchange rate derivatives | | — | | | (2) | | | — | | | — | | | (2) | |
Interest rate derivatives | | (5) | | | (60) | | | 0 | | | — | | | (65) | |
| | $ | (6) | | | $ | (152) | | | $ | (19) | | | $ | 56 | | | $ | (121) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $21 million and $35 million as of March 31, 2021 and December 31, 2020, respectively.
(2)Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments 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 the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company 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 the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company 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.
The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.
The Company's investments in money market mutual funds and debt and equity securities 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. 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.
The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | | | Interest |
| | | | | Commodity | | Rate |
| | | | | Derivatives | | Derivatives |
2021: | | | | | | | |
Beginning balance | | | | | $ | 116 | | | $ | 62 | |
Changes included in earnings(1) | | | | | (6) | | | (21) | |
Changes in fair value recognized in OCI | | | | | (1) | | | 0 | |
Changes in fair value recognized in net regulatory assets | | | | | 16 | | | 0 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Settlements | | | | | (1) | | | 0 | |
| | | | | | | |
Ending balance | | | | | $ | 124 | | | $ | 41 | |
| | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
2020: | | | | | | | |
Beginning balance | | | | | $ | 97 | | | $ | 14 | |
Changes included in earnings(1) | | | | | (3) | | | 31 | |
| | | | | | | |
Changes in fair value recognized in net regulatory assets | | | | | (40) | | | 0 | |
Purchases | | | | | 2 | | | 0 | |
| | | | | | | |
Settlements | | | | | (4) | | | 0 | |
| | | | | | | |
Ending balance | | | | | $ | 52 | | | $ | 45 | |
(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.
The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company'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 the Company'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 the Company's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 49,461 | | | $ | 55,926 | | | $ | 49,866 | | | $ | 60,633 | |
(9) Commitments and Contingencies
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company 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 wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, 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 indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing 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 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 inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. 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 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 and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
As of March 31, 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. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred 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 is expected to be available to cover at least a portion of the losses.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign 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 the Company's current and future operations. The Company 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 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 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 mainstem 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. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue 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 add 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.
Guarantees
The Company 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 the Company's consolidated financial results.
(10) Revenue from Contracts with Customers
Energy Products and Services
The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three-Month Period Ended March 31, 2021 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail electric | | $ | 1,145 | | | $ | 452 | | | $ | 511 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 2,108 | |
Retail gas | | 0 | | | 460 | | | 38 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 498 | |
Wholesale | | 36 | | | 125 | | | 15 | | | 0 | | | 17 | | | 0 | | | 0 | | | 0 | | | 193 | |
Transmission and distribution | | 25 | | | 15 | | | 21 | | | 263 | | | 0 | | | 172 | | | 0 | | | 0 | | | 496 | |
Interstate pipeline | | 0 | | | 0 | | | 0 | | | 0 | | | 815 | | | 0 | | | 0 | | | (41) | | | 774 | |
Other | | 23 | | | 0 | | | 0 | | | 0 | | | 2 | | | 0 | | | 0 | | | 0 | | | 25 | |
Total Regulated | | 1,229 | | | 1,052 | | | 585 | | | 263 | | | 834 | | | 172 | | | 0 | | | (41) | | | 4,094 | |
Nonregulated | | 0 | | | 10 | | | 0 | | | 10 | | | 237 | | | 8 | | | 166 | | | 187 | | | 618 | |
Total Customer Revenue | | 1,229 | | | 1,062 | | | 585 | | | 273 | | | 1,071 | | | 180 | | | 166 | | | 146 | | | 4,712 | |
Other revenue | | 13 | | | 5 | | | 6 | | | 27 | | | 22 | | | 0 | | | 24 | | | 40 | | | 137 | |
Total | | $ | 1,242 | | | $ | 1,067 | | | $ | 591 | | | $ | 300 | | | $ | 1,093 | | | $ | 180 | | | $ | 190 | | | $ | 186 | | | $ | 4,849 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Three-Month Period Ended March 31, 2020 |
| | PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | BHE Pipeline Group | | BHE Transmission | | BHE Renewables | | BHE and Other(1) | | Total |
Customer Revenue: | | | | | | | | | | | | | | | | | | |
Regulated: | | | | | | | | | | | | | | | | | | |
Retail electric | | $ | 1,122 | | | $ | 410 | | | $ | 529 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 2,061 | |
Retail gas | | 0 | | | 187 | | | 47 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 234 | |
Wholesale | | 0 | | | 64 | | | 14 | | | 0 | | | 0 | | | 0 | | | 0 | | | (1) | | | 77 | |
Transmission and distribution | | 22 | | | 15 | | | 23 | | | 233 | | | 0 | | | 169 | | | 0 | | | 0 | | | 462 | |
Interstate pipeline | | 0 | | | 0 | | | 0 | | | 0 | | | 400 | | | 0 | | | 0 | | | (48) | | | 352 | |
Other | | 26 | | | 0 | | | 1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | | | 27 | |
Total Regulated | | 1,170 | | | 676 | | | 614 | | | 233 | | | 400 | | | 169 | | | 0 | | | (49) | | | 3,213 | |
Nonregulated | | 0 | | | 6 | | | 1 | | | 7 | | | 0 | | | 3 | | | 159 | | | 127 | | | 303 | |
Total Customer Revenue | | 1,170 | | | 682 | | | 615 | | | 240 | | | 400 | | | 172 | | | 159 | | | 78 | | | 3,516 | |
Other revenue | | 36 | | | 4 | | | 7 | | | 26 | | | 1 | | | 0 | | | 19 | | | 25 | | | 118 | |
Total | | $ | 1,206 | | | $ | 686 | | | $ | 622 | | | $ | 266 | | | $ | 401 | | | $ | 172 | | | $ | 178 | | | $ | 103 | | | $ | 3,634 | |
(1)The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations.
Real Estate Services
The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):
| | | | | | | | | | | | | | | |
| | | | | HomeServices |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Customer Revenue: | | | | | | | |
Brokerage | | | | | $ | 1,022 | | | $ | 777 | |
Franchise | | | | | 18 | | | 16 | |
Total Customer Revenue | | | | | 1,040 | | | 793 | |
Mortgage and other revenue | | | | | 192 | | | 100 | |
Total | | | | | $ | 1,232 | | | $ | 893 | |
Remaining Performance Obligations
The following table summarizes the Company's 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 March 31, 2021, by reportable segment (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied: | | |
| Less than 12 months | | More than 12 months | | Total |
BHE Pipeline Group | $ | 2,521 | | | $ | 20,918 | | | $ | 23,439 | |
BHE Transmission | 513 | | | 0 | | | 513 | |
Total | $ | 3,034 | | | $ | 20,918 | | | $ | 23,952 | |
(11) BHE Shareholders' Equity
For the three-month period ended March 31, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.
(12) Components of Other Comprehensive Income (Loss), Net
The following table shows the change in accumulated other comprehensive income (loss) attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | Foreign | | Unrealized | | AOCI |
| | Amounts on | | Currency | | (Losses) Gains | | Attributable |
| | Retirement | | Translation | | on Cash | | To BHE |
| | Benefits | | Adjustment | | Flow Hedges | | Shareholders, Net |
| | | | | | | | |
Balance, December 31, 2019 | | $ | (417) | | | $ | (1,296) | | | $ | 7 | | | $ | (1,706) | |
| | | | | | | | |
Other comprehensive income (loss) | | 34 | | | (548) | | | (33) | | | (547) | |
Balance, March 31, 2020 | | $ | (383) | | | $ | (1,844) | | | $ | (26) | | | $ | (2,253) | |
| | | | | | | | |
Balance, December 31, 2020 | | $ | (482) | | | $ | (1,062) | | | $ | (8) | | | $ | (1,552) | |
Other comprehensive income | | 7 | | | 91 | | | 14 | | | 112 | |
Balance, March 31, 2021 | | $ | (475) | | | $ | (971) | | | $ | 6 | | | $ | (1,440) | |
(13) Segment Information
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
PacifiCorp | | | | | $ | 1,242 | | | $ | 1,206 | |
MidAmerican Funding | | | | | 1,067 | | | 686 | |
NV Energy | | | | | 591 | | | 622 | |
Northern Powergrid | | | | | 300 | | | 266 | |
BHE Pipeline Group | | | | | 1,093 | | | 401 | |
BHE Transmission | | | | | 180 | | | 172 | |
BHE Renewables | | | | | 190 | | | 178 | |
HomeServices | | | | | 1,232 | | | 893 | |
BHE and Other(1) | | | | | 186 | | | 103 | |
Total operating revenue | | | | | $ | 6,081 | | | $ | 4,527 | |
| | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
Depreciation and amortization: | | | | | | | |
PacifiCorp | | | | | $ | 264 | | | $ | 252 | |
MidAmerican Funding | | | | | 207 | | | 176 | |
NV Energy | | | | | 136 | | | 124 | |
Northern Powergrid | | | | | 71 | | | 63 | |
BHE Pipeline Group | | | | | 118 | | | 64 | |
BHE Transmission | | | | | 58 | | | 60 | |
BHE Renewables | | | | | 60 | | | 71 | |
HomeServices | | | | | 11 | | | 11 | |
BHE and Other(1) | | | | | 2 | | | 0 | |
Total depreciation and amortization | | | | | $ | 927 | | | $ | 821 | |
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating income: | | | | | | | |
PacifiCorp | | | | | $ | 234 | | | $ | 234 | |
MidAmerican Funding | | | | | 48 | | | 102 | |
NV Energy | | | | | 70 | | | 79 | |
Northern Powergrid | | | | | 151 | | | 132 | |
BHE Pipeline Group | | | | | 618 | | | 249 | |
BHE Transmission | | | | | 81 | | | 76 | |
BHE Renewables | | | | | 33 | | | 17 | |
HomeServices | | | | | 112 | | | 20 | |
BHE and Other(1) | | | | | (14) | | | 10 | |
Total operating income | | | | | 1,333 | | | 919 | |
Interest expense | | | | | (530) | | | (483) | |
Capitalized interest | | | | | 14 | | | 17 | |
Allowance for equity funds | | | | | 26 | | | 34 | |
Interest and dividend income | | | | | 21 | | | 20 | |
(Losses) gains on marketable securities, net | | | | | (1,118) | | | 27 | |
Other, net | | | | | 8 | | | (27) | |
Total (loss) income before income tax benefit and equity loss | | | | | $ | (246) | | | $ | 507 | |
| | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | | | |
Interest expense: | | | | | | | |
PacifiCorp | | | | | $ | 107 | | | $ | 102 | |
MidAmerican Funding | | | | | 78 | | | 81 | |
NV Energy | | | | | 52 | | | 58 | |
Northern Powergrid | | | | | 33 | | | 32 | |
BHE Pipeline Group | | | | | 38 | | | 14 | |
BHE Transmission | | | | | 38 | | | 38 | |
BHE Renewables | | | | | 40 | | | 42 | |
HomeServices | | | | | 1 | | | 5 | |
BHE and Other(1) | | | | | 143 | | | 111 | |
Total interest expense | | | | | $ | 530 | | | $ | 483 | |
| | | | | | | | | | | |
(Loss) earnings on common shares: | | | |
PacifiCorp | $ | 169 | | | $ | 176 | |
MidAmerican Funding | 144 | | | 150 | |
NV Energy | 34 | | | 20 | |
Northern Powergrid | 104 | | | 87 | |
BHE Pipeline Group | 383 | | | 179 | |
BHE Transmission | 59 | | | 55 | |
BHE Renewables | 16 | | | 95 | |
HomeServices | 84 | | | 10 | |
BHE and Other | (1,027) | | | (102) | |
(Loss) earnings on common shares | $ | (34) | | | $ | 670 | |
| | | |
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
Assets: | | | |
PacifiCorp | $ | 26,956 | | | $ | 26,862 | |
MidAmerican Funding | 24,098 | | | 23,530 | |
NV Energy | 14,594 | | | 14,501 | |
Northern Powergrid | 8,980 | | | 8,782 | |
BHE Pipeline Group | 19,651 | | | 19,541 | |
BHE Transmission | 9,341 | | | 9,208 | |
BHE Renewables | 11,935 | | | 12,004 | |
HomeServices | 5,186 | | | 4,955 | |
BHE and Other(1) | 6,781 | | | 7,933 | |
Total assets | $ | 127,522 | | | $ | 127,316 | |
(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue by country: | | | | | | | |
United States | | | | | $ | 5,597 | | | $ | 4,089 | |
United Kingdom | | | | | 300 | | | 266 | |
Canada | | | | | 177 | | | 171 | |
Philippines and other | | | | | 7 | | | 1 | |
Total operating revenue by country | | | | | $ | 6,081 | | | $ | 4,527 | |
| | | | | | | | | | | | | | | |
(Loss) income before income tax benefit and equity loss by country: | | | | | | | |
United States | | | | | $ | (423) | | | $ | 354 | |
United Kingdom | | | | | 132 | | | 109 | |
Canada | | | | | 39 | | | 40 | |
Philippines and other | | | | | 6 | | | 4 | |
Total (loss) income before income tax benefit and equity loss by country | | | | | $ | (246) | | | $ | 507 | |
The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2021 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | BHE Pipeline Group | | | | | | | | | | |
| PacifiCorp | | MidAmerican Funding | | NV Energy | | Northern Powergrid | | | BHE Transmission | | BHE Renewables | | HomeServices | | | | |
| | | | | | | | | | | Total |
| | | | | | | | | | | | | | | | | | | |
December 31, 2020 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 1,000 | | | $ | 1,803 | | | $ | 1,551 | | | $ | 95 | | | $ | 1,457 | | | | | $ | 11,506 | |
Acquisitions | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | | | 1 | |
Foreign currency translation | 0 | | | 0 | | | 0 | | | 6 | | | 0 | | | 21 | | | 0 | | | 0 | | | | | 27 | |
| | | | | | | | | | | | | | | | | | | |
March 31, 2021 | $ | 1,129 | | | $ | 2,102 | | | $ | 2,369 | | | $ | 1,006 | | | $ | 1,803 | | | $ | 1,572 | | | $ | 95 | | | $ | 1,458 | | | | | $ | 11,534 | |
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 the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.
Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns an LNG import, export and storage facility, in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.
Results of Operations for the First Quarter of 2021 and 2020
Overview
Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2021 | | 2020 | | Change | | | | | | |
Operating revenue: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 1,242 | | | $ | 1,206 | | | $ | 36 | | | 3 | % | | | | | | | | |
MidAmerican Funding | 1,067 | | | 686 | | | 381 | | | 56 | | | | | | | | | |
NV Energy | 591 | | | 622 | | | (31) | | | (5) | | | | | | | | | |
Northern Powergrid | 300 | | | 266 | | | 34 | | | 13 | | | | | | | | | |
BHE Pipeline Group | 1,093 | | | 401 | | | 692 | | | * | | | | | | | | |
BHE Transmission | 180 | | | 172 | | | 8 | | | 5 | | | | | | | | | |
BHE Renewables | 190 | | | 178 | | | 12 | | | 7 | | | | | | | | | |
HomeServices | 1,232 | | | 893 | | | 339 | | | 38 | | | | | | | | | |
BHE and Other | 186 | | | 103 | | | 83 | | | 81 | | | | | | | | | |
Total operating revenue | $ | 6,081 | | | $ | 4,527 | | | $ | 1,554 | | | 34 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
(Loss) earnings on common shares: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 169 | | | $ | 176 | | | $ | (7) | | | (4) | % | | | | | | | | |
MidAmerican Funding | 144 | | | 150 | | | (6) | | | (4) | | | | | | | | | |
NV Energy | 34 | | | 20 | | | 14 | | | 70 | | | | | | | | | |
Northern Powergrid | 104 | | | 87 | | | 17 | | | 20 | | | | | | | | | |
BHE Pipeline Group | 383 | | | 179 | | | 204 | | | * | | | | | | | | |
BHE Transmission | 59 | | | 55 | | | 4 | | | 7 | | | | | | | | | |
BHE Renewables(1) | 16 | | | 95 | | | (79) | | | (83) | | | | | | | | | |
HomeServices | 84 | | | 10 | | | 74 | | | * | | | | | | | | |
BHE and Other | (1,027) | | | (102) | | | (925) | | | * | | | | | | | | |
(Loss) earnings on common shares | $ | (34) | | | $ | 670 | | | $ | (704) | | | * | | | | | | | | |
(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.
* Not meaningful
Earnings on common shares decreased $704 million for the first quarter of 2021 compared to 2020. The first quarter of 2021 included a pre-tax unrealized loss of $1,124 million ($818 million after-tax) compared to a pre-tax unrealized gain in the first quarter of 2020 of $54 million ($39 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first quarter of 2021 was $784 million, an increase of $153 million, or 24%, compared to adjusted earnings on common shares in the first quarter of 2020 of $631 million.
The decrease in earnings on common shares for the first quarter of 2021 compared to 2020 was primarily due to the following:
•$204 million higher net income at BHE Pipeline Group, primarily due to $107 million of incremental net income from BHE GT&S, acquired in November 2020, higher gross margin on gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impact of the February 2021 polar vortex weather event, and the impacts of the 2020 rate case settlement at Northern Natural Gas;
•$79 million lower net income at BHE Renewables, primarily due to lower wind tax equity investment earnings from net losses on existing tax equity investments, largely due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation;
•$74 million higher net income at HomeServices, primarily due to higher earnings from mortgage services (63% increase in funded mortgage volume) and brokerage services (35% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and
•$925 higher net loss at BHE and Other due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.
Reportable Segment Results
PacifiCorp
Operating revenue increased $36 million for the first quarter of 2021 compared to 2020, primarily due to higher retail revenue of $20 million and higher wholesale and other revenue of $16 million. Retail revenue increased due to higher customer volumes of $15 million and price impacts of $5 million from changes in sales mix, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage. Wholesale and other revenue increased primarily due to higher wholesale volumes and higher average wholesale market prices.
Net income decreased $7 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense, including the impacts of a depreciation study effective in January 2021, lower allowances for equity and borrowed funds used during construction of $12 million and higher property taxes of $12 million, partially offset by higher utility margin of $29 million and favorable income tax expense from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service. Utility margin increased primarily due to the higher retail and wholesale revenue and lower purchased power costs, partially offset by higher natural gas-fueled and coal-fueled generation costs and higher net amortization of deferred net power costs in accordance with established adjustment mechanisms.
MidAmerican Funding
Operating revenue increased $381 million for the first quarter of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $303 million and higher electric operating revenue of $74 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold, primarily due to the February 2021 polar vortex weather event resulting in higher purchased gas adjustment recoveries of $304 million (offset in cost of sales). Electric operating revenue increased due to higher retail revenue of $40 million and higher wholesale and other revenue of $32 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to $32 million higher recoveries through the energy adjustment clauses (offset primarily in cost of sales), higher customer volumes of $5 million and price impacts of $5 million from changes in sales mix. Electric retail customer volumes increased 4.9% due to the favorable impact of weather and increased usage of certain industrial customers.
Net income decreased $6 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $31 million from additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense and $28 million higher operations and maintenance expenses, partially offset by a favorable income tax benefit and favorable changes in the cash surrender value of corporate-owned life insurance policies. Higher operations and maintenance expenses included increased costs associated with additional wind-powered generating facilities placed in-service as well as higher electric and natural gas distribution costs. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service, partially offset by the impacts of ratemaking. Electric utility margin increased $3 million as the higher retail and wholesale revenue was largely offset by higher generation and purchased power costs.
NV Energy
Operating revenue decreased $31 million for the first quarter of 2021 compared to 2020, primarily due to lower electric operating revenue of $22 million and lower natural gas operating revenue of $9 million. Electric operating revenue decreased primarily due to lower base tariff general rates of $14 million, lower retail customer volumes, lower fully-bundled energy rates (offset in cost of sales) of $4 million and price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, decreased 3.2%, primarily due to the impacts of COVID-19, which resulted in lower distribution only service, industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold (offset in cost of sales).
Net income increased $14 million for the first quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $22 million, primarily from lower regulatory instructed deferrals and amortizations and lower plant operations and maintenance costs, favorable changes in the cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and lower income tax expense from the impacts of ratemaking, partially offset by lower electric utility margin of $18 million and higher depreciation and amortization expense of $13 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service. Electric utility margin decreased primarily due to the lower base tariff general rates at Nevada Power, lower retail customer volumes and price impacts from changes in sales mix.
Northern Powergrid
Operating revenue increased $34 million for the first quarter of 2021 compared to 2020, primarily due to $21 million from the weaker United States dollar and higher distribution revenue of $13 million, mainly from increased tariff rates of $10 million. Net income increased $17 million for the first quarter of 2021 compared to 2020, primarily due to the higher distribution revenue and $7 million from the weaker United States dollar.
BHE Pipeline Group
Operating revenue increased $692 million for the first quarter of 2021 compared to 2020, primarily due to $559 million of incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales at Northern Natural Gas of $91 million and higher transportation revenue of $33 million at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event. Net income increased $204 million for the first quarter of 2021 compared to 2020, primarily due to $107 million of incremental net income at BHE GT&S and higher earnings of $98 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales of $75 million, higher transportation revenue and the impacts of the 2020 rate case settlement.
BHE Transmission
Operating revenue increased $8 million for the first quarter of 2021 compared to 2020, primarily due to $10 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020, partially offset by the impacts of a regulatory decision received in November 2020 at AltaLink. Net income increased $4 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada.
BHE Renewables
Operating revenue increased $12 million for the first quarter of 2021 compared to 2020, primarily due to higher hydro, geothermal and solar revenues from higher generation as well as favorable pricing at the geothermal facilities. Net income decreased $79 million for the first quarter 2021 compared to 2020, primarily due to lower wind tax equity investment earnings of $93 million, partially offset by the higher operating revenue. Wind tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $138 million, primarily due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation.
HomeServices
Operating revenue increased $339 million for the first quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $228 million from a 35% increase in closed transaction volume and higher mortgage revenue of $92 million from a 63% increase in funded mortgage volume due to an increase in refinance activity from the favorable interest rate environment. Net income increased $74 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from mortgage services of $36 million and brokerage services of $27 million largely attributable to the favorable interest rate environment.
BHE and Other
Operating revenue increased $83 million for the first quarter of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes. Net loss increased $925 million for the first quarter of 2021 compared to 2020, primarily due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2021, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | Other | | Total |
| | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 418 | | | $ | 43 | | | $ | 38 | | | $ | 103 | | | $ | 83 | | | $ | 71 | | | $ | 520 | | | $ | 1,276 | |
| | | | | | | | | | | | | | | |
Credit facilities | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 207 | | | 935 | | | 3,232 | | | 11,233 | |
Less: | | | | | | | | | | | | | | | |
Short-term debt | — | | | (95) | | | (387) | | | (55) | | | — | | | (218) | | | (1,944) | | | (2,699) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (2) | | | — | | | (590) | |
Net credit facilities | 3,500 | | | 887 | | | 752 | | | 595 | | | 207 | | | 715 | | | 1,288 | | | 7,944 | |
| | | | | | | | | | | | | | | |
Total net liquidity | $ | 3,918 | | | $ | 930 | | | $ | 790 | | | $ | 698 | | | $ | 290 | | | $ | 786 | | | $ | 1,808 | | | $ | 9,220 | |
Credit facilities: | | | | | | | | | | | | | | | |
Maturity dates | 2022 | | 2022 | | 2021, 2022 | | 2022 | | 2023 | | 2021, 2024 | | 2021, 2022 | | |
| | | | | | | | | | | | | | | |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $1.5 billion and $1.2 billion, respectively. The increase was primarily due to improved operating results and favorable income tax cash flows, partially offset by changes in working capital.
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(1.4) billion and $(1.5) billion, respectively. The change was primarily due to lower funding of tax equity investments and lower capital expenditures of $61 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2021 was $(191) million. Sources of cash totaled $409 million and consisted of net proceeds from short-term debt. Uses of cash totaled $600 million and consisted mainly of repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $115 million and repayments of subsidiary debt totaling $26 million.
For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Net cash flows from financing activities for the three-month period ended March 31, 2020 was $1.4 billion. Sources of cash totaled $4.3 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and subsidiary debt issuances totaling $1.1 billion. Uses of cash totaled $3.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.3 billion, net repayments of short-term debt totaling $1.1 billion, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.
The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Future Uses of Cash
The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.
Capital Expenditures
The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.
The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2020 | | 2021 | | 2021 |
Capital expenditures by business: | | | | | |
PacifiCorp | $ | 366 | | | $ | 439 | | | $ | 1,897 | |
MidAmerican Funding | 472 | | | 298 | | | 2,200 | |
NV Energy | 163 | | | 167 | | | 854 | |
Northern Powergrid | 159 | | | 179 | | | 732 | |
BHE Pipeline Group | 120 | | | 102 | | | 1,204 | |
BHE Transmission | 56 | | | 77 | | | 279 | |
BHE Renewables | 12 | | | 18 | | | 95 | |
HomeServices | 7 | | | 8 | | | 39 | |
BHE and Other(1) | 1 | | | 7 | | | 78 | |
Total | $ | 1,356 | | | $ | 1,295 | | | $ | 7,378 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
Capital expenditures by type: | | | | | |
Wind generation | $ | 273 | | | $ | 97 | | | $ | 1,158 | |
Electric distribution | 365 | | | 427 | | | 1,849 | |
Electric transmission | 185 | | | 157 | | | 1,006 | |
Natural gas transmission and storage | 49 | | | 85 | | | 1,032 | |
Solar generation | — | | | 4 | | | 295 | |
Other | 484 | | | 525 | | | 2,038 | |
Total | $ | 1,356 | | | $ | 1,295 | | | $ | 7,378 | |
(1)BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation expenditures include the following:
◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $154 million for the three-month period ended March 31, 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $24 million and $6 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $379 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively, and includes the 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.
◦Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and 2020 and the remaining repowering projects are expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.
◦Acquisition and repowering of wind-powered generating facilities at PacifiCorp totaling $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas New Lisbon Expansion and Twin Cities Area Expansion projects. Operating expenditures include, among other items, asset modernization and pipeline integrity projects.
•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by the end of 2023.
•Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.
Other Renewable Investments
The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made no contributions for the three-month period ended March 31, 2021, and has commitments as of March 31, 2021, subject to satisfaction of certain specified conditions, to provide equity contributions of $616 million for the remainder of 2021 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
Contractual Obligations
As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 other than the recent financing transactions and renewable tax equity investments previously discussed.
Quad Cities Generating Station Operating Status
Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.
On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.
Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020 and new regulatory matters occurring in 2021.
PacifiCorp
Utah
In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The UPSC approved the request in February 2021 for rates effective March 1, 2021.
Oregon
In February 2020, PacifiCorp filed a general rate case, and in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind facilities, new wind facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings will be made to include these investments in rates concurrent when they are placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind facility and the Pryor Mountain new wind facility to rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.
Wyoming
In September 2018, PacifiCorp filed an application for depreciation rate changes with the WPSC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and removal of Cholla Unit 4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application is scheduled to occur in July 2021.
In March 2020, PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. The WPSC decision is pending. PacifiCorp has requested a rate effective date of July 1, 2021.
In April 2021, PacifiCorp filed its annual ECAM and RRA application with the WPSC requesting to refund $15 million of deferred net power costs and RECs to customers for the period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the 2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp has requested an interim rate effective date of July 1, 2021.
Idaho
In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, RECs, and a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. This reflects a 1.1% decrease compared to current rates.
California
California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021.
FERC Show Cause Order
On April 15, 2021, the FERC issued an order to show cause and notice of proposed penalty related to allegations made by FERC Office of Enforcement staff that PacifiCorp failed to comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with facility ratings on PacifiCorp's bulk electric system. The order directs PacifiCorp to show cause as to why it should not be assessed a civil penalty of $42 million as a result of the alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. PacifiCorp will file a response to the allegations with the FERC.
MidAmerican Energy
Natural Gas Purchased for Resale
In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the three-month period ended March 31, 2021.
NV Energy (Nevada Power and Sierra Pacific)
Price Stability Tariff
In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option that is based on renewable resources. The CPST provides for an energy rate that would replace the Base Tariff Energy Rate and DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and an updated CPST tariff with the PUCN. An order is expected in the second quarter of 2021.
Natural Disaster Protection Plan
The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a petition for judicial review with the District Court in November 2020. In December 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and an order is expected in the second quarter of 2021. In March 2021, the Nevada Utilities filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial natural disaster protection plan that was ordered by the PUCN and filed their first amendment to the 2020 natural disaster protection plan.
Northern Powergrid Distribution Companies
In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution networks in Great Britain. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023. Regarding allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the Competition and Markets Authority against Ofgem's determination for the cost of equity.
In December 2020, in respect of electricity distribution, GEMA published its decision on the methodology it will use to set the ED2 price control and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution.
GEMA published a separate decision in March 2021, confirming that the financial aspects in respect of electricity distribution would broadly follow the transmission and gas distribution methodology, setting a working assumption for a cost of equity at 4.65% (plus CPIH), ahead of the final determinations in late 2022. When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, the working assumption for ED2 is approximately 150 basis points lower than the current cost of equity.
BHE Pipeline Group
BHE GT&S
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April.
BHE Transmission
AltaLink
Tariff Refund Application
In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation. The future income tax refund would be evenly distributed over the two-year period, 2021 to 2022, with C$75 million included in each year. The accumulated depreciation surplus would be refunded over the three-year period, 2021 to 2023, with C$60 million included in 2021 and 2022, and C$80 million in 2023. If approved by the AUC, these tariff relief measures would have saved customers an estimated C$317 million over the three-year period, 2021 to 2023.
In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta ratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed in AltaLink's 2022-2023 GTA.
2019-2021 General Tariff Application
In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide a further tariff reduction over the three year period by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.
In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the three year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.
In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.
In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership.
The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs continuing to transition to the AUC-approved salvage recovery method, continuing the use of the flow-through income tax method, and adding only a 1% increase to operations and maintenance expense, with the exception of salaries and wages and other expenses. In addition, similar to the itemsC$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariff of C$824 million and C$847 million for 2022 and 2023, respectively.
2022 Generic Cost of Capital Proceeding
In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding will consider the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the existing uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the commission has requested participants to submit comments that address the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.
In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there is insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.
In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta ratepayers.
In April 2021, the Utilities Consumer Advocate filed an application with the Court of Appeal of Alberta requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleges that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness.
2019 Deferral Accounts Reconciliation Application
In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.
In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128.0 million of the C$128.5 million of gross capital project additions, disallowing C$0.5 million of capital costs. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in April 2021.
Environmental Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2020, and new environmental matters occurring in 2021.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.
Clean Air Act Regulations
The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the nation's air quality and controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and policies to be followed. SIPs vary by state and are subject to public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the EPA. The major Clean Air Act programs most directly affecting the Registrants' operations as described below.
GHG Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.
National Ambient Air Quality Standards
Under the authority of the Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.
In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.
The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.
The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power plants in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the state of Utah moved to intervene in the litigation, which has been stayed pending the Biden administration's review of the rule.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.
PacifiCorp and its subsidiaries
Consolidated Financial Section
PART I
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 March 31, 2021, the related consolidated statements of operations, changes in shareholders' equity and cash flowsfor the three-month periods ended March 31, 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 PacifiCorp as of December 31, 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 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 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
April 30, 2021
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | |
| | As of |
| | March 31, | | December 31, |
| | 2021 | | 2020 |
ASSETS |
Current assets: | | | | |
Cash and cash equivalents | | $ | 43 | | | $ | 13 | |
Trade receivables, net | | 650 | | | 703 | |
Other receivables, net | | 48 | | | 48 | |
Inventories | | 475 | | | 482 | |
| | | | |
Regulatory assets | | 107 | | | 116 | |
Prepaid expenses | | 73 | | | 79 | |
Other current assets | | 109 | | | 82 | |
Total current assets | | 1,505 | | | 1,523 | |
| | | | |
Property, plant and equipment, net | | 22,535 | | | 22,430 | |
Regulatory assets | | 1,279 | | | 1,279 | |
Other assets | | 479 | | | 470 | |
| | | | |
Total assets | | $ | 25,798 | | | $ | 25,702 | |
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 |
| | March 31, | | December 31, |
| | 2021 | | 2020 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
Current liabilities: | | | | |
Accounts payable | | $ | 615 | | | $ | 772 | |
Accrued interest | | 114 | | | 127 | |
Accrued property, income and other taxes | | 118 | | | 80 | |
| | | | |
Accrued employee expenses | | 112 | | | 84 | |
Short-term debt | | 95 | | | 93 | |
Current portion of long-term debt | | 879 | | | 420 | |
Regulatory liabilities | | 111 | | | 115 | |
Other current liabilities | | 178 | | | 174 | |
Total current liabilities | | 2,222 | | | 1,865 | |
| | | | |
Long-term debt | | 7,734 | | | 8,192 | |
Regulatory liabilities | | 2,728 | | | 2,727 | |
Deferred income taxes | | 2,666 | | | 2,627 | |
Other long-term liabilities | | 1,106 | | | 1,118 | |
Total liabilities | | 16,456 | | | 16,529 | |
| | | | |
Commitments and contingencies (Note 8) | | 0 | | 0 |
| | | | |
Shareholders' equity: | | | | |
Preferred stock | | 2 | | | 2 | |
Common stock - 750 shares authorized, 0 par value, 357 shares issued and outstanding | | 0 | | | 0 | |
Additional paid-in capital | | 4,479 | | | 4,479 | |
Retained earnings | | 4,880 | | | 4,711 | |
Accumulated other comprehensive loss, net | | (19) | | | (19) | |
Total shareholders' equity | | 9,342 | | | 9,173 | |
| | | | |
Total liabilities and shareholders' equity | | $ | 25,798 | | | $ | 25,702 | |
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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Operating revenue | | | | | $ | 1,242 | | | $ | 1,206 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 424 | | | 417 | |
Operations and maintenance | | | | | 259 | | | 254 | |
Depreciation and amortization | | | | | 264 | | | 252 | |
Property and other taxes | | | | | 61 | | | 49 | |
Total operating expenses | | | | | 1,008 | | | 972 | |
| | | | | | | |
Operating income | | | | | 234 | | | 234 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (107) | | | (102) | |
Allowance for borrowed funds | | | | | 6 | | | 10 | |
Allowance for equity funds | | | | | 13 | | | 21 | |
Interest and dividend income | | | | | 6 | | | 3 | |
Other, net | | | | | 6 | | | (4) | |
Total other income (expense) | | | | | (76) | | | (72) | |
| | | | | | | |
Income before income tax benefit | | | | | 158 | | | 162 | |
Income tax benefit | | | | | (11) | | | (14) | |
Net income | | | | | $ | 169 | | | $ | 176 | |
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, December 31, 2019 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 3,972 | | | $ | (16) | | | $ | 8,437 | |
Net income | | — | | | — | | | — | | | 176 | | | — | | | 176 | |
Other comprehensive income | | — | | | — | | | — | | | 0 | | | 1 | | | 1 | |
| | | | | | | | | | | | |
Balance, March 31, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,148 | | | $ | (15) | | | $ | 8,614 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | |
Net income | | — | | | — | | | — | | | 169 | | | — | | | 169 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | $ | 2 | | | $ | 0 | | | $ | 4,479 | | | $ | 4,880 | | | $ | (19) | | | $ | 9,342 | |
The accompanying notes are an integral part of these consolidated financial statements.
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 169 | | | $ | 176 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 264 | | | 252 | |
Allowance for equity funds | (13) | | | (21) | |
Changes in regulatory assets and liabilities | (4) | | | (16) | |
Deferred income taxes and amortization of investment tax credits | 13 | | | (30) | |
Other, net | (2) | | | 6 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables, other receivables and other assets | 61 | | | 85 | |
Inventories | 7 | | | (26) | |
Derivative collateral, net | 7 | | | (1) | |
Prepaid expenses | 6 | | | (3) | |
Accrued property, income and other taxes, net | 12 | | | 18 | |
Accounts payable and other liabilities | (51) | | | (3) | |
Net cash flows from operating activities | 469 | | | 437 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (439) | | | (366) | |
Other, net | (1) | | | 27 | |
Net cash flows from investing activities | (440) | | | (339) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
Net proceeds from (repayments of) short-term debt | 2 | | | (74) | |
| | | |
| | | |
Other, net | (1) | | | 0 | |
Net cash flows from financing activities | 1 | | | (74) | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 30 | | | 24 | |
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 | $ | 49 | | | $ | 60 | |
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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 2021 and 2020 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, 2020 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 three-month period ended March 31, 2021.
(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 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 March 31, 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 |
| March 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 43 | | | $ | 13 | |
Restricted cash included in other current assets | 3 | | | 4 | |
Restricted cash included in other assets | 3 | | | 2 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 49 | | | $ | 19 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| | | March 31, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,355 | | | $ | 12,861 | |
Transmission | 60 - 90 years | | 7,686 | | | 7,632 | |
Distribution | 20 - 75 years | | 7,725 | | | 7,660 | |
Intangible plant(1) | 5 - 75 years | | 1,069 | | | 1,054 | |
Other | 5 - 60 years | | 1,513 | | | 1,510 | |
Utility plant in service | | | 31,348 | | | 30,717 | |
Accumulated depreciation and amortization | | | (9,980) | | | (9,838) | |
Utility plant in service, net | | | 21,368 | | | 20,879 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 9 | | | 9 | |
Plant, net | | | 21,377 | | | 20,888 | |
Construction work-in-progress | | | 1,158 | | | 1,542 | |
Property, plant and equipment, net | | | $ | 22,535 | | | $ | 22,430 | |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
Effective 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 $37 million for the three-month period ended March 31, 2021 compared to the three-month period ended March 31, 2020 based on historical property, plant and equipment balances and including depreciation of certain coal-fueled generating units in Washington over accelerated periods.
(4) 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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | | | | | 3 | | | 3 | |
Federal income tax credits | | | | | (20) | | | (11) | |
Effects of ratemaking | | | | | (13) | | | (22) | |
| | | | | | | |
Other | | | | | 2 | | | 0 | |
Effective income tax rate | | | | | (7) | % | | (9) | % |
Income tax credits relate primarily to production tax credits ("PTCs") 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.
Effects of ratemaking for the three-month periods ended March 31, 2021 and 2020 is primarily attributable to the amortization of excess deferred income taxes, including the use of excess deferred income taxes of $3 million and $30 million, respectively, to accelerate depreciation of certain retired wind equipment and to amortize certain regulatory asset balances in accordance with regulatory orders issued in Oregon and Wyoming.
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 three-month periods ended March 31, 2021 and 2020, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $1 million and $26 million, respectively.
(5) Employee Benefit Plans
Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | | | | | $ | 0 | | | $ | 0 | |
Interest cost | | | | | 7 | | | 9 | |
Expected return on plan assets | | | | | (13) | | | (14) | |
Net amortization | | | | | 5 | | | 5 | |
Net periodic benefit credit | | | | | $ | (1) | | | $ | 0 | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | | | | | $ | 0 | | | $ | 0 | |
Interest cost | | | | | 2 | | | 3 | |
Expected return on plan assets | | | | | (2) | | | (4) | |
Net amortization | | | | | 0 | | | 0 | |
Net periodic benefit credit | | | | | $ | 0 | | | $ | (1) | |
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 2021. As of March 31, 2021, $1 million of contributions had been made to the pension plans.
(6) 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 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, 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 7 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 March 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 45 | | | $ | 6 | | | $ | 2 | | | $ | 0 | | | $ | 53 | |
Commodity liabilities | (2) | | | 0 | | | (27) | | | (24) | | | (53) | |
Total | 43 | | | 6 | | | (25) | | | (24) | | | 0 | |
| | | | | | | | | |
Total derivatives | 43 | | | 6 | | | (25) | | | (24) | | | 0 | |
Cash collateral receivable | 0 | | | 0 | | | 13 | | | 4�� | | | 17 | |
Total derivatives - net basis | $ | 43 | | | $ | 6 | | | $ | (12) | | | $ | (20) | | | $ | 17 | |
| | | | | | | | | |
As of December 31, 2020 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 29 | | | $ | 6 | | | $ | 1 | | | $ | 0 | | | $ | 36 | |
Commodity liabilities | (2) | | | 0 | | | (23) | | | (28) | | | (53) | |
Total | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
| | | | | | | | | |
Total derivatives | 27 | | | 6 | | | (22) | | | (28) | | | (17) | |
Cash collateral receivable | 0 | | | 0 | | | 15 | | | 9 | | | 24 | |
Total derivatives - net basis | $ | 27 | | | $ | 6 | | | $ | (7) | | | $ | (19) | | | $ | 7 | |
(1)PacifiCorp's commodity derivatives are generally included in rates and as of March 31, 2021 and December 31, 2020, a regulatory asset of $— million and $17 million, respectively, was recorded related to the net derivative liability of $— million and $17 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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Beginning balance | | | | | $ | 17 | | | $ | 62 | |
Changes in fair value | | | | | (17) | | | 34 | |
Net gains reclassified to operating revenue | | | | | 0 | | | 8 | |
Net losses reclassified to cost of fuel and energy | | | | | 0 | | | (20) | |
Ending balance | | | | | $ | 0 | | | $ | 84 | |
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 | | March 31, | | December 31, |
| Measure | | 2021 | | 2020 |
| | | | | |
Electricity sales, net | Megawatt hours | | 0 | | | (1) | |
Natural gas purchases | Decatherms | | 114 | | | 100 | |
| | | | | |
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 recognized credit rating agencies. These agreements 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" if there is a material adverse change in PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2021, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from 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 $52 million and $51 million as of March 31, 2021 and December 31, 2020, respectively, for which PacifiCorp had posted collateral of $17 million and $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 March 31, 2021 and December 31, 2020, PacifiCorp would have been required to post $30 million and $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.
(7) 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 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 March 31, 2021 | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 53 | | | $ | 0 | | | $ | (4) | | | $ | 49 | |
Money market mutual funds(2) | 36 | | | 0 | | | 0 | | | — | | | 36 | |
Investment funds | 30 | | | 0 | | | 0 | | | — | | | 30 | |
| $ | 66 | | | $ | 53 | | | $ | 0 | | | $ | (4) | | | $ | 115 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | 0 | | | $ | (53) | | | $ | 0 | | | $ | 21 | | | $ | (32) | |
| | | | | | | | | |
As of December 31, 2020 | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 36 | | | $ | 0 | | | $ | (3) | | | $ | 33 | |
Money market mutual funds(2) | 6 | | | 0 | | | 0 | | | — | | | 6 | |
Investment funds | 25 | | | 0 | | | 0 | | | — | | | 25 | |
| $ | 31 | | | $ | 36 | | | $ | 0 | | | $ | (3) | | | $ | 64 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | 0 | | | $ | (53) | | | $ | 0 | | | $ | 27 | | | $ | (26) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $17 million and $24 million as of March 31, 2021 and December 31, 2020, 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 6 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 March 31, 2021 | | As of December 31, 2020 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 8,613 | | | $ | 10,198 | | | $ | 8,612 | | | $ | 10,995 | |
(8) 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 wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, 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 indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing 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 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 inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. 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 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 and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
As of March 31, 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. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred 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 is expected to be available to cover at least a portion of the losses.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding 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 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 mainstem 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. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue 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 add 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.
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.
(9) Revenue from Contracts with Customers
The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):
| | | | | | | | | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | | | | | $ | 483 | | | $ | 460 | |
Commercial | | | | | 359 | | | 358 | |
Industrial | | | | | 271 | | | 277 | |
Other retail | | | | | 32 | | | 27 | |
Total retail | | | | | 1,145 | | | 1,122 | |
Wholesale (1) | | | | | 36 | | | 0 | |
Transmission | | | | | 25 | | | 22 | |
Other Customer Revenue | | | | | 23 | | | 26 | |
Total Customer Revenue | | | | | 1,229 | | | 1,170 | |
Other revenue | | | | | 13 | | | 36 | |
Total operating revenue | | | | | $ | 1,242 | | | $ | 1,206 | |
(1)Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.
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 First Quarter of 2021 and 2020
Overview
Net income for the first three months of 2021 was $169 million, a decrease of $7 million compared to 2020. Net income decreased primarily due to lower allowances for equity and borrowed funds used during construction of $12 million, higher property taxes of $12 million, higher depreciation and amortization expense of $12 million, including the impacts of the depreciation study that was effective January 1, 2021, higher operations and maintenance expense of $5 million and higher interest expense of $5 million, partially offset by higher utility margin of $29 million and increased cash surrender value of corporate-owned life insurance policies. Utility margin increased primarily due to higher retail and wholesale revenue and lower purchased electricity costs, partially offset by higher natural gas-fueled generation costs, higher net amortization of deferred net power costs in accordance with established adjustment mechanisms, and higher coal-fueled generation costs. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers across the service territory and favorable impact of weather, partially offset by lower customer usage. Energy generated increased 8% for the first three months 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 24% and purchased electricity volumes decreased 11%.
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 generally 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2021 | | 2020 | | Change | | | | | | |
Utility margin: | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,242 | | | $ | 1,206 | | | $ | 36 | | | 3 | % | | | | | | | | |
Cost of fuel and energy | 424 | | | 417 | | | 7 | | | 2 | | | | | | | | | |
Utility margin | 818 | | | 789 | | | 29 | | | 4 | | | | | | | | | |
Operations and maintenance | 259 | | | 254 | | | 5 | | | 2 | | | | | | | | | |
Depreciation and amortization | 264 | | | 252 | | | 12 | | | 5 | | | | | | | | | |
Property and other taxes | 61 | | | 49 | | | 12 | | | 24 | | | | | | | | | |
Operating income | $ | 234 | | | $ | 234 | | | $ | — | | | — | % | | | | | | | | |
Utility Margin
A comparison of key operating results related to utility margin is as follows for the quarters ended March 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | | | | | | | |
| 2021 | | 2020 | | Change | | | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,242 | | | $ | 1,206 | | | $ | 36 | | | 3 | % | | | | | | | | |
Cost of fuel and energy | 424 | | | 417 | | | 7 | | | 2 | | | | | | | | | |
Utility margin | $ | 818 | | | $ | 789 | | | $ | 29 | | | 4 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 4,632 | | | 4,421 | | | 211 | | | 5 | % | | | | | | | | |
Commercial | 4,470 | | | 4,410 | | | 60 | | | 1 | | | | | | | | | |
Industrial, irrigation and other | 4,474 | | | 4,702 | | | (228) | | | (5) | | | | | | | | | |
Total retail | 13,576 | | | 13,533 | | | 43 | | | — | | | | | | | | | |
Wholesale | 1,591 | | | 1,281 | | | 310 | | | 24 | | | | | | | | | |
Total sales | 15,167 | | | 14,814 | | | 353 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 1,989 | | | 1,955 | | | 34 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 84.15 | | | $ | 82.97 | | | $ | 1.18 | | | 1 | % | | | | | | | | |
Wholesale | $ | 30.89 | | | $ | 26.35 | | | $ | 4.54 | | | 17 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Heating degree days | 4,687 | | | 4,605 | | | 82 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 7,644 | | | 7,228 | | | 416 | | | 6 | % | | | | | | | | |
Natural gas | 3,065 | | | 3,041 | | | 24 | | | 1 | | | | | | | | | |
Hydroelectric(2) | 923 | | | 1,046 | | | (123) | | | (12) | | | | | | | | | |
Wind and other(2) | 1,803 | | | 1,112 | | | 691 | | | 62 | | | | | | | | | |
Total energy generated | 13,435 | | | 12,427 | | | 1,008 | | | 8 | | | | | | | | | |
Energy purchased | 3,028 | | | 3,391 | | | (363) | | | (11) | | | | | | | | | |
Total | 16,463 | | | 15,818 | | | 645 | | | 4 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 17.66 | | | $ | 17.80 | | | $ | (0.14) | | | (1) | % | | | | | | | | |
Energy purchased | $ | 47.13 | | | $ | 47.41 | | | $ | (0.28) | | | (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 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.
Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020
Utility margin increased $29 million, or 4%, for the first quarter of 2021 compared to 2020 primarily due to:
•$20 million increase in retail revenue primarily due to higher customer volumes and higher average rates from sales mix, partially offset by lower prices due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers across the service territory and favorable impact of weather, partially offset by lower customer usage;
•$18 million of lower purchased electricity costs from lower market prices and lower purchased volumes, partially due to higher wind generation from new Energy Vision 2020 ("EV 2020") generation and repowered facilities; and
•$15 million of higher wholesale revenue due to higher wholesale volumes and higher average wholesale market prices.
The increases above were partially offset by:
•$12 million of higher natural gas-fueled generation costs primarily due to higher average prices;
•$8 million primarily from higher net amortization of deferred net power costs in accordance with established adjustment mechanisms; and
•$6 million of higher coal-fueled generation costs primarily due to higher volumes, partially offset by lower average prices.
Operations and maintenance increased $5 million, or 2%, for the first quarter of 2021 compared to 2020 primarily due to higher vegetation management costs of $14 million, partially offset by cost savings from the retirement of Cholla unit 4 in December 2020 and decreased bad debt expense.
Depreciation and amortization increased $12 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to the impacts of a new depreciation study effective January 1, 2021 of approximately $37 million, including accelerated depreciation on coal-fueled units in Washington and an increase in assets placed in service, partially offset by a $44 million decrease resulting from lower accelerated depreciation for Oregon's share of certain retired wind equipment due to repowering ($3 million in the current quarter (fully offset in other revenue) compared to $47 million in the first quarter of 2020 ($7 million offset in other revenue and $40 million offset in income tax expense)).
Property and other taxes increased$12 million, or 24%, for the first quarter of 2021 compared to 2020 primarily due to higher property taxes from higher assessed property values.
Interest expense increased$5 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to a higher average long-term debt balance.
Allowance for borrowed and equity funds decreased $12 million, or 39%, for the first quarter of 2021 compared to 2020 primarily due to lower qualified construction work-in-progress balances due to large EV 2020 projects being placed in service.
Other, net increased $10 million from a loss of $4 million for the first quarter of 2020 to income of $6 million for the first quarter of 2021, primarily due to market movements related to corporate-owned life insurance policies.
Income tax benefit decreased $3 million, or 21%, for the first quarter of 2021 compared to the first quarter of 2020. The effective tax rate was (7)% for 2021 and (9)% for 2020. The effective tax rate increased primarily as a result of lower amortization of excess deferred income taxes in the current year, partially offset by increased PTCs from PacifiCorp's new wind-powered generating facilities. For the first quarter of 2021, $3 million of excess deferred income taxes was amortized pursuant to regulatory orders for Wyoming, whereby portions of excess deferred income taxes were used to offset certain regulatory balances for Wyoming. For the first quarter of 2020, $30 million of excess deferred income taxes was amortized pursuant to the Oregon RAC settlement, whereby a portion of excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment.
Liquidity and Capital Resources
As of March 31, 2021, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 43 | |
| | |
Credit facilities | | 1,200 | |
Less: | | |
Short-term debt | | (95) | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | 887 | |
| | |
Total net liquidity | | $ | 930 | |
| | |
Credit facilities: | | |
Maturity dates | | 2022 | |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $469 million and $437 million, respectively. The change was primarily due to lower cash paid for income taxes, lower purchased power prices and volumes and lower fuel expense payments due to timing, partially offset by higher operating expense payments due to timing and higher cash paid for interest.
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 three-month periods ended March 31, 2021 and 2020 were $(440) million and $(339) million, respectively. The change is primarily due to an increase in capital expenditures of $73 million and 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 three-month period ended March 31, 2021 was $1 million. Sources of cash consisted of $2 million from the borrowing of short-term debt.
Net cash flows from financing activities for the three-month period ended March 31, 2020 was $(74) million. Uses of cash consisted of $74 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 March 31, 2021, PacifiCorp had $95 million of short-term debt outstanding at a weighted average interest rate of 0.16%. As of December 31, 2020, PacifiCorp had $93 million of short-term debt outstanding at a weighted average interest rate of 0.16%.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $3 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.
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 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):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Wind generation | $ | 106 | | | $ | 33 | | | $ | 193 | |
Electric distribution | 99 | | | 195 | | | 730 | |
Electric transmission | 92 | | | 60 | | | 426 | |
Other | 69 | | | 151 | | | 548 | |
Total | $ | 366 | | | $ | 439 | | | $ | 1,897 | |
PacifiCorp's 2019 IRP identified a significant increase in renewable resource generation and associated transmission. PacifiCorp has included an estimate of the 2019 IRP resources in its forecast capital expenditures for 2021 through 2023. These estimates are likely to 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 $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively. Construction includes 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production 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. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $100 million for 2021.
◦Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. Certain repowering projects were placed in service in 2019 and 2020 with the remaining repowering projects expected to be placed in-service in 2021. The energy production from such 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 additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.
◦Acquisition and repowering of wind-powered generating facilities totals $1 million for the three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes planned spend on wildfire mitigation, wildfire damage restoration and storm damage repairs. Expenditures for these items totaled $83 million and $4 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with these activities will total an additional $145 million in 2021. Remaining investments relate to expenditures for new connections and distribution.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment through 2020 primarily reflects costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020. Planned spending for the additional Energy Gateway Transmission segments totals $182 million in 2021 and are expected to be placed in service in 2023 - 2024.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $13 million and $10 million for the three-month periods ended March 31, 2021 and 2020, respectively. PacifiCorp anticipates costs associated with information technology will total an additional $118 million for 2021. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
Requests for Proposals
PacifiCorp issues individual 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.
PacifiCorp issued the 2020 All Source RFP to the market in July 2020. The 2020 All Source RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. An initial shortlist was identified in October 2020. The final shortlist of winning bids will be identified by June 2021.
Contractual Obligations
As of March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2020.
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 various federal, state and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that 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.
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, 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, 2020. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2020.
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
PART I
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 March 31, 2021, the related statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 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 balance sheet of MidAmerican Energy as of December 31, 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 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, 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
April 30, 2021
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 37 | | | $ | 38 | |
Trade receivables, net | 521 | | | 234 | |
Income tax receivable | 293 | | | 0 | |
Inventories | 231 | | | 278 | |
Other current assets | 103 | | | 73 | |
Total current assets | 1,185 | | | 623 | |
| | | |
Property, plant and equipment, net | 19,223 | | | 19,279 | |
Regulatory assets | 439 | | | 392 | |
Investments and restricted investments | 938 | | | 911 | |
Other assets | 215 | | | 232 | |
| | | |
Total assets | $ | 22,000 | | | $ | 21,437 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 292 | | | $ | 408 | |
Accrued interest | 86 | | | 78 | |
Accrued property, income and other taxes | 124 | | | 161 | |
Short-term debt | 387 | | | 0 | |
| | | |
Other current liabilities | 186 | | | 183 | |
Total current liabilities | 1,075 | | | 830 | |
| | | |
Long-term debt | 7,224 | | | 7,210 | |
Regulatory liabilities | 1,257 | | | 1,111 | |
Deferred income taxes | 3,107 | | | 3,054 | |
Asset retirement obligations | 711 | | | 709 | |
Other long-term liabilities | 414 | | | 458 | |
Total liabilities | 13,788 | | | 13,372 | |
| | | |
Commitments and contingencies (Note 8) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, 0 par value, 71 shares issued and outstanding | 0 | | | 0 | |
Additional paid-in capital | 561 | | | 561 | |
Retained earnings | 7,651 | | | 7,504 | |
| | | |
Total shareholder's equity | 8,212 | | | 8,065 | |
| | | |
Total liabilities and shareholder's equity | $ | 22,000 | | | $ | 21,437 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 545 | | | $ | 471 | |
Regulated natural gas and other | | | | | 522 | | | 210 | |
Total operating revenue | | | | | 1,067 | | | 681 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 151 | | | 80 | |
Cost of natural gas purchased for resale and other | | | | | 432 | | | 128 | |
Operations and maintenance | | | | | 193 | | | 165 | |
Depreciation and amortization | | | | | 207 | | | 176 | |
Property and other taxes | | | | | 36 | | | 34 | |
Total operating expenses | | | | | 1,019 | | | 583 | |
| | | | | | | |
Operating income | | | | | 48 | | | 98 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (74) | | | (76) | |
Allowance for borrowed funds | | | | | 2 | | | 3 | |
Allowance for equity funds | | | | | 6 | | | 8 | |
Other, net | | | | | 11 | | | (5) | |
Total other income (expense) | | | | | (55) | | | (70) | |
| | | | | | | |
(Loss) income before income tax benefit | | | | | (7) | | | 28 | |
Income tax benefit | | | | | (154) | | | (123) | |
| | | | | | | |
Net income | | | | | $ | 147 | | | $ | 151 | |
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, December 31, 2019 | $ | 0 | | | $ | 561 | | | $ | 6,679 | | | $ | 7,240 | |
Net income | — | | | — | | | 151 | | | 151 | |
| | | | | | | |
Balance, March 31, 2020 | $ | 0 | | | $ | 561 | | | $ | 6,830 | | | $ | 7,391 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Balance, December 31, 2020 | $ | 0 | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | |
Net income | — | | | — | | | 147 | | | 147 | |
| | | | | | | |
Balance, March 31, 2021 | $ | 0 | | | $ | 561 | | | $ | 7,651 | | | $ | 8,212 | |
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 147 | | | $ | 151 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 207 | | | 176 | |
Amortization of utility plant to other operating expenses | 8 | | | 9 | |
Allowance for equity funds | (6) | | | (8) | |
Deferred income taxes and amortization of investment tax credits | 154 | | | 91 | |
Settlements of asset retirement obligations | (4) | | | (2) | |
Other, net | (4) | | | 14 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (299) | | | 15 | |
Inventories | 46 | | | (6) | |
Derivative collateral, net | (14) | | | 1 | |
Pension and other postretirement benefit plans | 1 | | | (6) | |
Accrued property, income and other taxes, net | (331) | | | (286) | |
Accounts payable and other liabilities | 10 | | | 70 | |
Net cash flows from operating activities | (85) | | | 219 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (298) | | | (472) | |
Purchases of marketable securities | (52) | | | (127) | |
Proceeds from sales of marketable securities | 47 | | | 124 | |
Other, net | 0 | | | 5 | |
Net cash flows from investing activities | (303) | | | (470) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
| | | |
Net proceeds from short-term debt | 387 | | | 50 | |
Other, net | 0 | | | (1) | |
Net cash flows from financing activities | 387 | | | 49 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (1) | | | (202) | |
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 | $ | 44 | | | $ | 128 | |
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 March 31, 2021, and for the three-month periods ended March 31, 2021 and 2020. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month period ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 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, 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 three-month period ended March 31, 2021.
(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 March 31, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2020, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents reported within Eastern Energy’s Consolidatedas of March 31, 2021 and December 31, 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 |
| March 31, | | December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 37 | | | $ | 38 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 44 | | | $ | 45 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| | | March 31, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility plant in service, net: | | | | | |
Generation | 20-70 years | | $ | 17,083 | | | $ | 16,980 | |
Transmission | 52-75 years | | 2,372 | | | 2,365 | |
Electric distribution | 20-75 years | | 4,433 | | | 4,369 | |
Natural gas distribution | 29-75 years | | 1,970 | | | 1,955 | |
Utility plant in service | | | 25,858 | | | 25,669 | |
Accumulated depreciation and amortization | | | (7,061) | | | (6,902) | |
Utility plant in service, net | | | 18,797 | | | 18,767 | |
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 | | | 7 | |
Accumulated depreciation and amortization | | | (1) | | | (1) | |
Nonregulated property, net | | | 6 | | | 6 | |
| | | 18,803 | | | 18,773 | |
Construction work-in-progress | | | 420 | | | 506 | |
Property, plant and equipment, net | | | $ | 19,223 | | | $ | 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 customers, the Iowa Utilities Board ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during three-month period ended March 31, 2021.
(5) Income Taxes
The effective income tax rate for the three-month period ended March 31, 2021, is 2,200% and results from a $154 million income tax benefit associated with a $7 million pre-tax loss. The $154 million income tax benefit is primarily comprised of a $2 million benefit (21%) from the application of the statutory income tax rate to the correspondingpre-tax loss and a $168 million benefit (2,400%) from income tax credits, partially offset by a $13 million expense (186%) from the effects of ratemaking.
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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
Income tax credits | | | | | 2,400 | | | (430) | |
State income tax, net of federal income tax impacts | | | | | (29) | | | (28) | |
Effects of ratemaking | | | | | (186) | | | (3) | |
Other, net | | | | | (6) | | | 1 | |
Effective income tax rate | | | | | 2,200 | % | | (439) | % |
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 March 31, 2021 and 2020 totaled $151 million and $120 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. MidAmerican Energy made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021, and made net cash payments for income tax to BHE totaling $46 million for the three-month period ended March 31, 2020.
(6) 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 cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Pension: | | | | | | | |
Service cost | | | | | $ | 5 | | | $ | 1 | |
Interest cost | | | | | 6 | | | 6 | |
Expected return on plan assets | | | | | (9) | | | (10) | |
| | | | | | | |
Net periodic benefit cost (credit) | | | | | $ | 2 | | | $ | (3) | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | | | | | $ | 2 | | | $ | 1 | |
Interest cost | | | | | 2 | | | 2 | |
Expected return on plan assets | | | | | (2) | | | (3) | |
Net amortization | | | | | (1) | | | (1) | |
Net periodic benefit cost (credit) | | | | | $ | 1 | | | $ | (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 $12 million, respectively, during 2021. As of March 31, 2021, $2 million and $3 million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(7) 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 March 31, 2021: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | 3 | | | $ | 2 | | | $ | (2) | | | $ | 3 | |
Money market mutual funds(2) | | 38 | | | 0 | | | 0 | | | — | | | 38 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 210 | | | 0 | | | 0 | | | — | | | 210 | |
International government obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Corporate obligations | | 0 | | | 71 | | | 0 | | | — | | | 71 | |
Municipal obligations | | 0 | | | 2 | | | 0 | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Equity securities: | | | | | | | | | | |
United States companies | | 395 | | | 0 | | | 0 | | | — | | | 395 | |
International companies | | 8 | | | 0 | | | 0 | | | — | | | 8 | |
Investment funds | | 24 | | | 0 | | | 0 | | | — | | | 24 | |
| | $ | 675 | | | $ | 86 | | | $ | 2 | | | $ | (2) | | | $ | 761 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | 0 | | | $ | (1) | | | $ | (1) | | | $ | 2 | | | $ | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2020: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | 0 | | | $ | 4 | | | $ | 5 | | | $ | (5) | | | $ | 4 | |
Money market mutual funds(2) | | 41 | | | 0 | | | 0 | | | — | | | 41 | |
Debt securities: | | | | | | | | | | |
United States government obligations | | 200 | | | 0 | | | 0 | | | — | | | 200 | |
International government obligations | | 0 | | | 5 | | | 0 | | | — | | | 5 | |
Corporate obligations | | 0 | | | 73 | | | 0 | | | — | | | 73 | |
Municipal obligations | | 0 | | | 2 | | | 0 | | | — | | | 2 | |
Agency, asset and mortgage-backed obligations | | 0 | | | 6 | | | 0 | | | — | | | 6 | |
Equity securities: | | | | | | | | | | |
United States companies | | 381 | | | 0 | | | 0 | | | — | | | 381 | |
International companies | | 9 | | | 0 | | | 0 | | | — | | | 9 | |
Investment funds | | 17 | | | 0 | | | 0 | | | — | | | 17 | |
| | $ | 648 | | | $ | 90 | | | $ | 5 | | | $ | (5) | | | $ | 738 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | 0 | | | $ | (4) | | | $ | (3) | | | $ | 5 | | | $ | (2) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million as of March 31, 2021 and December 31, 2020, 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.
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 March 31, 2021 | | As of December 31, 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,224 | | | $ | 8,305 | | | $ | 7,210 | | | $ | 9,130 | |
(8) Commitments and Contingencies
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 Federal 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 March 31, 2021, has accrued a $10 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.
(9) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 10, (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Three-Month Period Ended March 31, 2021 |
| | | | | | | | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | | | | | | | | | $ | 161 | | | $ | 308 | | | $ | — | | | $ | 469 | |
Commercial | | | | | | | | | 71 | | | 129 | | | — | | | 200 | |
Industrial | | | | | | | | | 190 | | | 12 | | | — | | | 202 | |
Natural gas transportation services | | | | | | | | | — | | | 10 | | | — | | | 10 | |
Other retail(1) | | | | | | | | | 30 | | | 1 | | | — | | | 31 | |
Total retail | | | | | | | | | 452 | | | 460 | | | — | | | 912 | |
Wholesale | | | | | | | | | 74 | | | 51 | | | — | | | 125 | |
Multi-value transmission projects | | | | | | | | | 15 | | | — | | | — | | | 15 | |
Other Customer Revenue | | | | | | | | | — | | | — | | | 10 | | | 10 | |
Total Customer Revenue | | | | | | | | | 541 | | | 511 | | | 10 | | | 1,062 | |
Other revenue | | | | | | | | | 4 | | | 1 | | | 0 | | | 5 | |
Total operating revenue | | | | | | | | | $ | 545 | | | $ | 512 | | | $ | 10 | | | $ | 1,067 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Three-Month Period Ended March 31, 2020 |
| | | | | | | | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | | | | | | | | | $ | 148 | | | $ | 128 | | | $ | — | | | $ | 276 | |
Commercial | | | | | | | | | 70 | | | 43 | | | — | | | 113 | |
Industrial | | | | | | | | | 163 | | | 4 | | | — | | | 167 | |
Natural gas transportation services | | | | | | | | | — | | | 11 | | | — | | | 11 | |
Other retail(1) | | | | | | | | | 29 | | | 0 | | | — | | | 29 | |
Total retail | | | | | | | | | 410 | | | 186 | | | — | | | 596 | |
Wholesale | | | | | | | | | 42 | | | 22 | | | — | | | 64 | |
Multi-value transmission projects | | | | | | | | | 16 | | | — | | | — | | | 16 | |
Other Customer Revenue | | | | | | | | | — | | | — | | | 1 | | | 1 | |
Total Customer Revenue | | | | | | | | | 468 | | | 208 | | | 1 | | | 677 | |
Other revenue | | | | | | | | | 3 | | | 1 | | | 0 | | | 4 | |
Total operating revenue | | | | | | | | | $ | 471 | | | $ | 209 | | | $ | 1 | | | $ | 681 | |
(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.
(10) Segment Information
MidAmerican Energy has identified 2 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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 545 | | | $ | 471 | |
Regulated natural gas | | | | | 512 | | | 209 | |
Other | | | | | 10 | | | 1 | |
Total operating revenue | | | | | $ | 1,067 | | | $ | 681 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | | | | | $ | 9 | | | $ | 59 | |
Regulated natural gas | | | | | 39 | | | 39 | |
| | | | | | | |
Total operating income | | | | | 48 | | | 98 | |
Interest expense | | | | | (74) | | | (76) | |
Allowance for borrowed funds | | | | | 2 | | | 3 | |
Allowance for equity funds | | | | | 6 | | | 8 | |
Other, net | | | | | 11 | | | (5) | |
(Loss) income before income tax benefit | | | | | $ | (7) | | | $ | 28 | |
| | | | | | | | | | | |
| As of |
| March 31, 2021 | | December 31, 2020 |
Assets: | | | |
Regulated electric | $ | 20,272 | | | $ | 19,892 | |
Regulated natural gas | 1,725 | | | 1,544 | |
Other | 3 | | | 1 | |
Total assets | $ | 22,000 | | | $ | 21,437 | |
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 March 31, 2021, the related consolidated statements of operations, changes in member's equity, and cash flows for the three-month periods ended March 31, 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) 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, 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 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 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
April 30, 2021
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 38 | | | $ | 39 | |
Trade receivables, net | 521 | | | 234 | |
Income tax receivable | 295 | | | 0 | |
Inventories | 231 | | | 278 | |
Other current assets | 102 | | | 74 | |
Total current assets | 1,187 | | | 625 | |
| | | |
Property, plant and equipment, net | 19,223 | | | 19,279 | |
Goodwill | 1,270 | | | 1,270 | |
Regulatory assets | 439 | | | 392 | |
Investments and restricted investments | 940 | | | 913 | |
Other assets | 215 | | | 232 | |
| | | |
Total assets | $ | 23,274 | | | $ | 22,711 | |
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 |
| March 31, | | December 31, |
| 2021 | | 2020 |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 292 | | | $ | 408 | |
Accrued interest | 87 | | | 83 | |
Accrued property, income and other taxes | 124 | | | 161 | |
Note payable to affiliate | 184 | | | 177 | |
Short-term debt | 387 | | | — | |
| | | |
Other current liabilities | 187 | | | 183 | |
Total current liabilities | 1,261 | | | 1,012 | |
| | | |
Long-term debt | 7,464 | | | 7,450 | |
Regulatory liabilities | 1,257 | | | 1,111 | |
Deferred income taxes | 3,104 | | | 3,052 | |
Asset retirement obligations | 711 | | | 709 | |
Other long-term liabilities | 414 | | | 458 | |
Total liabilities | 14,211 | | | 13,792 | |
| | | |
Commitments and contingencies (Note 8) | 0 | | 0 |
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 | | | 1,679 | |
Retained earnings | 7,384 | | | 7,240 | |
| | | |
Total member's equity | 9,063 | | | 8,919 | |
| | | |
Total liabilities and member's equity | $ | 23,274 | | | $ | 22,711 | |
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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 545 | | | $ | 471 | |
Regulated natural gas and other | | | | | 522 | | | 215 | |
Total operating revenue | | | | | 1,067 | | | 686 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 151 | | | 80 | |
Cost of natural gas purchased for resale and other | | | | | 432 | | | 129 | |
Operations and maintenance | | | | | 193 | | | 165 | |
Depreciation and amortization | | | | | 207 | | | 176 | |
Property and other taxes | | | | | 36 | | | 34 | |
Total operating expenses | | | | | 1,019 | | | 584 | |
| | | | | | | |
Operating income | | | | | 48 | | | 102 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (78) | | | (81) | |
Allowance for borrowed funds | | | | | 2 | | | 3 | |
Allowance for equity funds | | | | | 6 | | | 8 | |
Other, net | | | | | 10 | | | (6) | |
Total other income (expense) | | | | | (60) | | | (76) | |
| | | | | | | |
(Loss) income before income tax benefit | | | | | (12) | | | 26 | |
Income tax benefit | | | | | (156) | | | (124) | |
| | | | | | | |
Net income | | | | | $ | 144 | | | $ | 150 | |
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, December 31, 2019 | $ | 1,679 | | | $ | 6,422 | | | $ | 8,101 | |
Net income | — | | | 150 | | | 150 | |
| | | | | |
Balance, March 31, 2020 | $ | 1,679 | | | $ | 6,572 | | | $ | 8,251 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Balance, December 31, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | |
Net income | — | | | 144 | | | 144 | |
| | | | | |
Balance, March 31, 2021 | $ | 1,679 | | | $ | 7,384 | | | $ | 9,063 | |
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)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 144 | | | $ | 150 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 207 | | | 176 | |
Amortization of utility plant to other operating expenses | 8 | | | 9 | |
Allowance for equity funds | (6) | | | (8) | |
Deferred income taxes and amortization of investment tax credits | 153 | | | 93 | |
| | | |
Settlements of asset retirement obligations | (4) | | | (2) | |
Other, net | (3) | | | 15 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (298) | | | 16 | |
Inventories | 46 | | | (6) | |
Derivative collateral, net | (14) | | | 1 | |
Pension and other postretirement benefit plans | 1 | | | (6) | |
Accrued property, income and other taxes, net | (332) | | | (290) | |
Accounts payable and other liabilities | 6 | | | 66 | |
Net cash flows from operating activities | (92) | | | 214 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (298) | | | (472) | |
Purchases of marketable securities | (52) | | | (127) | |
Proceeds from sales of marketable securities | 47 | | | 124 | |
| | | |
Other, net | 0 | | | 6 | |
Net cash flows from investing activities | (303) | | | (469) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
| | | |
Net change in note payable to affiliate | 7 | | | 3 | |
Net proceeds from short-term debt | 387 | | | 50 | |
Other, net | 0 | | | (1) | |
Net cash flows from financing activities | 394 | | | 52 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (1) | | | (203) | |
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 | $ | 45 | | | $ | 128 | |
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 March 31, 2021, and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month period ended March 31, 2021 and 2020. The results of operations for the three-month periods ended March 31, 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 withinamounts 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, 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 three-month period ended March 31, 2021.
(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 March 31, 2021 and December 31, 2020, consist substantially of funds restricted for wildlife preservation and, as of December 31, 2020, the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows
foris outlined below and disaggregated by the
nine months ended September 30, 2020 and 2019: | | Cash, Restricted Cash and Equivalents at End of Period | | | Cash, Restricted Cash and Equivalents at Beginning of Period | |
| | September 30, 2020 | | | September 30, 2019 | | | December 31, 2019 | | | December 31, 2018 | |
(millions) | | | | | | | | | | | | | | | | |
Cash and cash equivalents(1) | | $ | 40 | | | $ | 74 | | | $ | 27 | | | $ | 108 | |
Restricted cash and equivalents(2) | | | 16 | | | | 12 | | | | 12 | | | | 90 | |
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows | | $ | 56 | | | $ | 86 | | | $ | 39 | | | $ | 198 | |
(1)
| At September 30, 2019 and December 31, 2018,$10 million and $9 million of cash and cash equivalents were included in current assets of discontinued operations, respectively.
|
(2) Restricted cash and equivalent balances are presented within other current assetsline items in which they appear on the Consolidated Balance Sheets.
Sheets (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
| | | |
Cash and cash equivalents | $ | 38 | | | $ | 39 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 45 | | | $ | 46 | |
(3) Property, Plant and Equipment,
In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) Regulatory Matters
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
(5) Income Taxes
The effective income tax rate for the Supply Header Project. Asthree-month period ended March 31, 2021, is 1,300% and results from a $156 million income tax benefit associated with a $12 million pre-tax loss. The $156 million income tax benefit is primarily comprised of a $3 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $168 million benefit (1,400%) from income tax credits, partially offset by a $13 million expense (108%) from the effects of ratemaking.
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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
Income tax credits | | | | | 1,400 | | | (463) | |
State income tax, net of federal income tax impacts | | | | | (8) | | | (31) | |
Effects of ratemaking | | | | | (108) | | | (3) | |
Other, net | | | | | (5) | | | (1) | |
Effective income tax rate | | | | | 1,300 | % | | (477) | % |
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 Funding 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 March 31, 2021 and 2020 totaled $151 million and $120 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. MidAmerican Funding made 0 cash payments for income tax to BHE for the three-month period ended March 31, 2021, and made net cash payments for income tax to BHE totaling $47 million for the three-month period ended March 31, 2020.
(6) Employee Benefit Plans
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) Fair Value Measurements
Refer to Note 7 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 March 31, 2021 | | As of December 31, 2020 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,464 | | | $ | 8,622 | | | $ | 7,450 | | | $ | 9,466 | |
(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 8 of MidAmerican Energy's Notes to Financial Statements.
(9) Revenue from Contracts with Customers
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $— million and $5 million for the three-month periods ended March 31, 2021 and 2020, respectively.
(10) Segment Information
MidAmerican Funding has identified 2 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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 545 | | | $ | 471 | |
Regulated natural gas | | | | | 512 | | | 209 | |
Other | | | | | 10 | | | 6 | |
Total operating revenue | | | | | $ | 1,067 | | | $ | 686 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | | | | | $ | 9 | | | $ | 59 | |
Regulated natural gas | | | | | 39 | | | 39 | |
Other | | | | | 0 | | | 4 | |
Total operating income | | | | | 48 | | | 102 | |
Interest expense | | | | | (78) | | | (81) | |
Allowance for borrowed funds | | | | | 2 | | | 3 | |
Allowance for equity funds | | | | | 6 | | | 8 | |
Other, net | | | | | 10 | | | (6) | |
(Loss) income before income tax benefit | | | | | $ | (12) | | | $ | 26 | |
| | | | | | | | | | | |
| As of |
| March 31, 2021 | | December 31, 2020 |
Assets(1): | | | |
Regulated electric | $ | 21,463 | | | $ | 21,083 | |
Regulated natural gas | 1,804 | | | 1,623 | |
Other | 7 | | | 5 | |
Total assets | $ | 23,274 | | | $ | 22,711 | |
| | | | | |
(1) | Assets by reportable segment reflect the assignment of goodwill to applicable reporting units. |
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 First Quarter of 2021 and 2020
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the first quarter of 2021 was $147 million, a decrease of $4 million, or 3%, compared to 2020 primarily due to higher depreciation and amortization expense of $31 million from additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense, and higher operations and maintenance expenses of $28 million, partially offset by a greater income tax benefit of $31 million from higher PTCs recognized, higher investment earnings of $19 million and higher company-retained margins of $9 million on natural gas wholesale sales. PTCs recognized increased due to higher wind-powered generation driven primarily by new wind projects placed in-service.
MidAmerican Funding -
MidAmerican Funding's net income for the first quarter of 2021 was $144 million, a decrease of $6 million, or 4%, compared to 2020. The decrease was 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | First Quarter |
| | | | | | | | 2021 | | 2020 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 545 | | | $ | 471 | | | $ | 74 | | 16 | % |
Cost of fuel and energy | | | | | | | | | 151 | | | 80 | | | 71 | | 89 | |
Electric utility margin | | | | | | | | | 394 | | | 391 | | | 3 | | 1 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | 512 | | | 209 | | | 303 | | 145 | % |
Natural gas purchased for resale | | | | | | | | | 432 | | | 128 | | | 304 | | 238 | |
Natural gas utility margin | | | | | | | | | 80 | | | 81 | | | (1) | | (1) | % |
| | | | | | | | | | | | | | |
Utility margin | | | | | | | | | 474 | | | 472 | | | 2 | | — | % |
| | | | | | | | | | | | | | |
Other operating revenue | | | | | | | | | 10 | | | 1 | | | 9 | | * |
| | | | | | | | | | | | | | |
Operations and maintenance | | | | | | | | | 193 | | | 165 | | | 28 | | 17 | |
Depreciation and amortization | | | | | | | | | 207 | | | 176 | | | 31 | | 18 | |
Property and other taxes | | | | | | | | | 36 | | | 34 | | | 2 | | 6 | |
| | | | | | | | | | | | | | |
Operating income | | | | | | | | | $ | 48 | | | $ | 98 | | | $ | (50) | | (51) | % |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the quarters ended March 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First Quarter |
| | | | | | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 545 | | | $ | 471 | | | $ | 74 | | | 16 | % |
Cost of fuel and energy | | | | | | | | | 151 | | | 80 | | | 71 | | | 89 | |
Utility margin | | | | | | | | | $ | 394 | | | $ | 391 | | | $ | 3 | | | 1 | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | | | | | | | | | 1,738 | | | 1,668 | | | 70 | | | 4 | % |
Commercial | | | | | | | | | 938 | | | 969 | | | (31) | | | (3) | |
Industrial | | | | | | | | | 3,819 | | | 3,524 | | | 295 | | | 8 | |
Other | | | | | | | | | 370 | | | 385 | | | (15) | | | (4) | |
Total retail | | | | | | | | | 6,865 | | | 6,546 | | | 319 | | | 5 | |
Wholesale | | | | | | | | | 4,051 | | | 2,434 | | | 1,617 | | | 66 | |
Total sales | | | | | | | | | 10,916 | | | 8,980 | | | 1,936 | | | 22 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | | | | | | | | 801 | | 792 | | 9 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | | | | | | | | | $ | 65.82 | | | $ | 62.75 | | | $ | 3.07 | | | 5 | % |
Wholesale | | | | | | | | | $ | 16.64 | | | $ | 15.71 | | | $ | 0.93 | | | 6 | % |
| | | | | | | | | | | | | | | |
Heating degree days | | | | | | | | | 3,211 | | | 2,952 | | | 259 | | | 9 | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | | | | | | | | | 6,122 | | | 4,846 | | | 1,276 | | | 26 | % |
Coal | | | | | | | | | 2,902 | | | 1,573 | | | 1,329 | | | 84 | |
Nuclear | | | | | | | | | 895 | | | 993 | | | (98) | | | (10) | |
Natural gas | | | | | | | | | 143 | | | 116 | | | 27 | | | 23 | |
Total energy generated | | | | | | | | | 10,062 | | | 7,528 | | | 2,534 | | | 34 | |
Energy purchased | | | | | | | | | 1,018 | | | 1,643 | | | (625) | | | (38) | |
Total | | | | | | | | | 11,080 | | | 9,171 | | | 1,909 | | | 21 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | | | | | | | | | $ | 6.15 | | | $ | 5.00 | | | $ | 1.15 | | | 23 | % |
Energy purchased | | | | | | | | | $ | 87.45 | | | $ | 25.59 | | | $ | 61.86 | | | * |
* Not meaningful.
(1) GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the cancellation of the Atlantic Coast Pipeline Project,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 second quarterform of 2020 Eastern Energy recorded a chargeRECs or other environmental commodities.
(3) The average cost per MWh of $482 million ($359 million after-tax) in impairmentenergy generated includes only the cost of assets and other charges (benefits) in its Consolidated Statements of Incomefuel associated with the probable abandonmentgenerating facilities.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows for the quarters ended March 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First Quarter |
| | | | | | | 2021 | | 2020 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 512 | | | $ | 209 | | | $ | 303 | | | * |
Natural gas purchased for resale | | | | | | | | | 432 | | | 128 | | | 304 | | | * |
Utility margin | | | | | | | | | $ | 80 | | | $ | 81 | | | $ | (1) | | | (1) | % |
| | | | | | | | | | | | | | | |
Throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | | | | | | | | | 25,282 | | | 23,910 | | | 1,372 | | | 6 | % |
Commercial | | | | | | | | | 11,733 | | | 10,951 | | | 782 | | | 7 | |
Industrial | | | | | | | | | 1,437 | | | 1,512 | | | (75) | | | (5) | |
Other | | | | | | | | | 37 | | | 35 | | | 2 | | | 6 | |
Total retail sales | | | | | | | | | 38,489 | | | 36,408 | | | 2,081 | | | 6 | |
Wholesale sales | | | | | | | | | 10,773 | | | 12,910 | | | (2,137) | | | (17) | |
Total sales | | | | | | | | | 49,262 | | | 49,318 | | | (56) | | | — | |
Natural gas transportation service | | | | | | | | | 29,640 | | | 34,954 | | | (5,314) | | | (15) | |
Total throughput | | | | | | | | | 78,902 | | | 84,272 | | | (5,370) | | | (6) | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | | | | | | | | 777 | | | 770 | | | 7 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | | | | | | | | $ | 11.70 | | | $ | 4.85 | | | $ | 6.85 | | | * |
| | | | | | | | | | | | | | | |
Heating degree days | | | | | | | | | 3,301 | | | 3,067 | | | 234 | | | 8 | % |
| | | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | | | | | | | | $ | 9.87 | | | $ | 2.91 | | | $ | 6.96 | | | * |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | | | | | | | | | $ | 8.76 | | | $ | 2.60 | | | $ | 6.16 | | | * |
* Not meaningful.
Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020
MidAmerican Energy -
Electric utility margin increased $3 million for the first quarter of 2021 compared to 2020, due to:
•a $15 million increase in retail utility margin due to an increase of $6 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); an increase of $6 million from the favorable impact of weather; and an increase of $4 million due to price impacts from changes in sales mix and other rate and usage variances, including increased usage for certain industrial customers; partially offset by
•a $12 million decrease in wholesale utility margin due to lower margins per unit, reflecting higher energy costs, partially offset by higher sales volumes of 66.4%.
Natural gas utility margin decreased $1 million for the first quarter of 2021 compared to 2020 primarily due to:
•a $7 million decrease from higher rider refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit); partially offset by
•$3 million from higher natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
•$2 million from the favorable impact of weather.
Operations and maintenance increased $28 million for the first quarter of 2021 compared to 2020 primarily due to higher generation operations and maintenance expenses of $6 million due to additional wind turbines and easements, higher electric and natural gas distribution costs of $6 million, higher energy efficiency program expense of $5 million (offset in operating revenue) and higher employee-related expenses of $5 million.
Depreciation and amortization for the first quarter of 2021 increased $31 million compared to 2020 primarily due to wind-powered generating facilities and other plant placed in-service and $13 million from the expiration of a regulatory mechanism deferring certain depreciation expense.
Interest expense decreased $2 million for the first quarter of 2021 compared to 2020 due to lower average interest rates on variable rate long-term debt.
Allowance for borrowed and equity funds decreased $3 million for the first quarter of 2021 compared to 2020 primarily due to lower construction work-in-progress balances related to wind-powered generation.
Other, net increased $16 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender values of corporate-owned life insurance policies.
Income tax benefit increased $31 million for the first quarter of 2021 compared to 2020, and the effective tax rate was 2,200% for 2021 and (439)% for 2020. The change in the effective tax rates for 2021 compared to 2020 was due to the higher PTCs and a lower pretax income, partially offset by the effects of ratemaking and state income tax impacts.
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 projectequipment was replaced, commonly referred to as wellrepowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the first quarter of 2021 and 2020 totaled $151 million and $120 million, respectively.
MidAmerican Funding -
Income tax benefit increased $32 million for the first quarter of 2021 compared to 2020, and the effective tax rate was 1,300% for 2021 and (477)% for 2020. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of March 31, 2021, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
| | | | | | | | |
MidAmerican Energy: | | |
Cash and cash equivalents | | $ | 37 | |
| | |
Credit facilities, maturing 2021 and 2022 | | 1,505 | |
Less: | | |
Short-term debt outstanding | | (387) | |
Tax-exempt bond support | | (370) | |
Net credit facilities | | 748 | |
| | |
MidAmerican Energy total net liquidity | | $ | 785 | |
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 785 | |
Cash and cash equivalents | | 1 | |
MHC, Inc. credit facility, maturing 2021 | | 4 | |
MidAmerican Funding total net liquidity | | $ | 790 | |
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020, were $(85) million and $219 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020, were $(92) million and $214 million, respectively. Cash flows from operating activities reflect lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses, including delayed recovery of higher natural gas costs in February 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 sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during three-month period ended March 31, 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 three-month periods ended March 31, 2021 and 2020, were $(303) million and $(470) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020, were $(303) million and $(469) 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 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.
Financing Activities
MidAmerican Energy's net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $387 million and $49 million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020, were $394 million and $52 million, respectively. Through its commercial paper program, MidAmerican Energy received $387 million in 2021 and $50 million in 2020. MidAmerican Funding received $7 million and $3 million in 2021 and 2020, 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 unsecured credit facility expiring in June 2022. 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, following MidAmerican Energy's exercise of an option to extend the facility, expires in August 2021, 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 registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021. Additionally, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2021, 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 and preferred stock up to an aggregate of $500 million and from the ICC to issue long-term debt securities up to an aggregate of $850 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):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Wind generation | $ | 166 | | | $ | 32 | | | $ | 865 | |
Electric distribution | 51 | | | 46 | | | 298 | |
Electric transmission | 38 | | | 23 | | | 197 | |
Solar generation | — | | | 3 | | | 245 | |
Other | 217 | | | 194 | | | 595 | |
Total | $ | 472 | | | $ | 298 | | | $ | 2,200 | |
MidAmerican Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction and acquisition of wind-powered generating facilities totaled $154 million for 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.
◦Repowering of wind-powered generating facilities totaled $24 million for 2021 and $6 million for 2020. Planned spending for repowering generating facilities totals $379 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.
•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 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021.
•Remaining expenditures primarily relate to routine expenditures for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.
Contractual Obligations
As of March 31, 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, 2020.
Quad Cities Generating Station Operating Status
Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.
On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.
Exelon Generation is currently working with the PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from the PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.
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, 2020. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2020.
Nevada Power Company and its subsidiaries
Consolidated Financial Section
PART I
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 March 31, 2021, the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2021 and 2020, and the related notes (collectively referred to as the establishment"interim financial information"). Based on our reviews, we are not aware of a $75 million ARO. Inany material modifications that should be made to the third quarteraccompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of 2020, Eastern Energy recorded an additional charge of $10 million ($7 million after-tax) associatedAmerica.
We have previously audited, in accordance with the probable abandonment of a significant portionstandards of the projectPublic Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2020, and a $29 million ($20 million after-tax) benefit from a revisionthe 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 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 previously established ARO, bothconsolidated 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 were recordedis 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
April 30, 2021
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in impairmentmillions, except share data)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 92 | | | $ | 25 | |
Trade receivables, net | 180 | | | 234 | |
Inventories | 65 | | | 69 | |
Derivative contracts | 48 | | | 26 | |
Regulatory assets | 22 | | | 48 | |
Prepayments | 45 | | | 38 | |
| | | |
Other current assets | 37 | | | 26 | |
Total current assets | 489 | | | 466 | |
| | | |
Property, plant and equipment, net | 6,751 | | | 6,701 | |
Finance lease right of use assets, net | 348 | | | 351 | |
Regulatory assets | 741 | | | 746 | |
Other assets | 71 | | | 72 | |
| | | |
Total assets | $ | 8,400 | | | $ | 8,336 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 189 | | | $ | 181 | |
Accrued interest | 38 | | | 32 | |
Accrued property, income and other taxes | 38 | | | 25 | |
| | | |
| | | |
Current portion of finance lease obligations | 30 | | | 27 | |
Regulatory liabilities | 63 | | | 50 | |
Customer deposits | 42 | | | 47 | |
Asset retirement obligation | 18 | | | 25 | |
| | | |
Other current liabilities | 38 | | | 22 | |
Total current liabilities | 456 | | | 409 | |
| | | |
Long-term debt | 2,497 | | | 2,496 | |
Finance lease obligations | 328 | | | 334 | |
Regulatory liabilities | 1,171 | | | 1,163 | |
Deferred income taxes | 740 | | | 738 | |
Other long-term liabilities | 267 | | | 257 | |
Total liabilities | 5,459 | | | 5,397 | |
| | | |
Commitments and contingencies (Note 6) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | 0 | | | 0 | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 636 | | | 634 | |
Accumulated other comprehensive loss, net | (3) | | | (3) | |
Total shareholder's equity | 2,941 | | | 2,939 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,400 | | | $ | 8,336 | |
| | | |
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 |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | | | |
Operating revenue | | | | | $ | 370 | | | $ | 389 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 165 | | | 170 | |
Operations and maintenance | | | | | 63 | | | 82 | |
Depreciation and amortization | | | | | 101 | | | 90 | |
Property and other taxes | | | | | 12 | | | 12 | |
Total operating expenses | | | | | 341 | | | 354 | |
| | | | | | | |
Operating income | | | | | 29 | | | 35 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (38) | | | (42) | |
Allowance for borrowed funds | | | | | 1 | | | 1 | |
Allowance for equity funds | | | | | 1 | | | 2 | |
Other, net | | | | | 9 | | | (1) | |
Total other income (expense) | | | | | (27) | | | (40) | |
| | | | | | | |
Income (loss) before income tax benefit | | | | | 2 | | | (5) | |
Income tax benefit | | | | | 0 | | | (1) | |
Net income (loss) | | | | | $ | 2 | | | $ | (4) | |
| | | | | | | |
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, December 31, 2019 | | 1,000 | | | $ | 0 | | | $ | 2,308 | | | $ | 493 | | | $ | (4) | | | $ | 2,797 | |
Net loss | | — | | | — | | | — | | | (4) | | | — | | | (4) | |
| | | | | | | | | | | | |
Other equity transactions | | — | | | — | | | — | | | 1 | | | — | | | 1 | |
Balance, March 31, 2020 | | 1,000 | | | $ | 0 | | | $ | 2,308 | | | $ | 490 | | | $ | (4) | | | $ | 2,794 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | $ | 0 | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | |
Net income | | — | | | — | | | — | | | 2 | | | — | | | 2 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | 1,000 | | | $ | 0 | | | $ | 2,308 | | | $ | 636 | | | $ | (3) | | | $ | 2,941 | |
| | | | | | | | | | | | |
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)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income (loss) | $ | 2 | | | $ | (4) | |
Adjustments to reconcile net income (loss) to net cash flows from operating activities: | | | |
| | | |
| | | |
Depreciation and amortization | 101 | | | 90 | |
Allowance for equity funds | (1) | | | (2) | |
Changes in regulatory assets and liabilities | (15) | | | 3 | |
Deferred income taxes and amortization of investment tax credits | (10) | | | (4) | |
Deferred energy | 41 | | | 4 | |
| | | |
Other, net | (1) | | | 8 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 41 | | | 32 | |
Inventories | 4 | | | (1) | |
Accrued property, income and other taxes | 3 | | | (6) | |
Accounts payable and other liabilities | 14 | | | (41) | |
Net cash flows from operating activities | 179 | | | 79 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (106) | | | (111) | |
| | | |
| | | |
| | | |
Net cash flows from investing activities | (106) | | | (111) | |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | 0 | | | 719 | |
Repayments of long-term debt | 0 | | | (575) | |
| | | |
| | | |
| | | |
| | | |
Other, net | (5) | | | (4) | |
Net cash flows from financing activities | (5) | | | 140 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 68 | | | 108 | |
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 | $ | 104 | | | $ | 133 | |
| | | |
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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 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 Nevada Power's 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 Nevada Power's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.
(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 charges (benefits)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 March 31, 2021 and December 31, 2020, consist of funds restricted by the Public 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 March 31, 2021 and December 31, 2020, as presented in Eastern Energy’sthe Consolidated Statements of Income. As DETI evaluates its future use, approximately $40 million remains within property,Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 92 | | | $ | 25 | |
Restricted cash and cash equivalents included in other current assets | 12 | | | 11 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 104 | | | $ | 36 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| Depreciable Life | | March 31, | | December 31, |
| | 2021 | | 2020 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,691 | | | $ | 3,690 | |
Transmission | 45 - 70 years | | 1,465 | | | 1,468 | |
Distribution | 20 - 65 years | | 3,803 | | | 3,771 | |
General and intangible plant | 5 - 65 years | | 798 | | | 791 | |
Utility plant | | | 9,757 | | | 9,720 | |
Accumulated depreciation and amortization | | | (3,224) | | | (3,162) | |
Utility plant, net | | | 6,533 | | | 6,558 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,534 | | | 6,559 | |
Construction work-in-progress | | | 217 | | | 142 | |
Property, plant and equipment, net | | | $ | 6,751 | | | $ | 6,701 | |
(4) 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
a potential modified project. Goodwill
Easterneligible employees. The NV Energy has evaluated goodwill annually asComprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of April 1 and whenever an event occursNevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or circumstances change in the interimcase 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 receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
Qualified Pension Plan: | | | |
Other non-current assets | $ | 9 | | | $ | 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 | |
| | | |
| | | |
(5) 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 more-likely-than-not reduceuse 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 March 31, 2021 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 0 | | | $ | 48 | | | $ | 48 | |
Money market mutual funds(1) | 86 | | | 0 | | | 0 | | | 86 | |
Investment funds | 2 | | | 0 | | | 0 | | | 2 | |
| $ | 88 | | | $ | 0 | | | $ | 48 | | | $ | 136 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | 0 | | | $ | 0 | | | $ | (21) | | | $ | (21) | |
| | | | | | | |
As of December 31, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 0 | | | $ | 26 | | | $ | 26 | |
Money market mutual funds(1) | 21 | | | 0 | | | 0 | | | 21 | |
Investment funds | 2 | | | 0 | | | 0 | | | 2 | |
| $ | 23 | | | $ | 0 | | | $ | 26 | | | $ | 49 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | 0 | | | $ | 0 | | | $ | (11) | | | $ | (11) | |
(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 reporting unitbuyer 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 March 31, 2021 and December 31, 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 | | |
| Ended March 31, | | |
| 2021 | | 2020 | | | | |
| | | | | | | |
Beginning balance | $ | 15 | | | $ | (8) | | | | | |
Changes in fair value recognized in regulatory assets | 11 | | | (31) | | | | | |
| | | | | | | |
Settlements | 1 | | | 1 | | | | | |
Ending balance | $ | 27 | | | $ | (38) | | | | | |
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 March 31, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,497 | | | $ | 2,991 | | | $ | 2,496 | | | $ | 3,245 | |
(6) 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.
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.
(7) Revenue from Contracts with Customers
The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Periods | | |
| Ended March 31, | | |
| 2021 | | 2020 | | | | |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 196 | | | $ | 193 | | | | | |
Commercial | 84 | | | 94 | | | | | |
Industrial | 63 | | | 70 | | | | | |
Other | 3 | | | 3 | | | | | |
Total fully bundled | 346 | | | 360 | | | | | |
Distribution only service | 5 | | | 7 | | | | | |
Total retail | 351 | | | 367 | | | | | |
Wholesale, transmission and other | 14 | | | 16 | | | | | |
Total Customer Revenue | 365 | | | 383 | | | | | |
Other revenue | 5 | | | 6 | | | | | |
Total revenue | $ | 370 | | | $ | 389 | | | | | |
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 First Quarter of 2021 and 2020
Overview
Net income for the first quarter of 2021 was $2 million, an increase of $6 million, compared to 2020 primarily due to $19 million of lower operations and maintenance expenses, primarily due to lower net regulatory instructed deferrals and amortizations of $11 million, lower plant operations and maintenance costs and a reduction to the accrual for earning sharing, $10 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies of $7 million and lower pension expense, and lower interest expense of $4 million. This increase is offset by $14 million of lower utility margin. primarily due to lower retail rates from the 2020 regulatory rate review with new rates effective January 2021, and $11 million of higher depreciation and amortization, mainly due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | First Quarter | | |
| | 2021 | | 2020 | | Change | | | | | | |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 370 | | | $ | 389 | | | $ | (19) | | (5) | % | | | | | | | |
Cost of fuel and energy | | 165 | | | 170 | | | (5) | | (3) | | | | | | | | |
Utility margin | | 205 | | | 219 | | | (14) | | (6) | | | | | | | | |
Operations and maintenance | | 63 | | | 82 | | | (19) | | (23) | | | | | | | | |
Depreciation and amortization | | 101 | | | 90 | | | 11 | | 12 | | | | | | | | |
Property and other taxes | | 12 | | | 12 | | | — | | — | | | | | | | | |
Operating income | | $ | 29 | | | $ | 35 | | | $ | (6) | | (17) | % | | | | | | | |
Utility Margin
A comparison of key operating results related to utility margin is as follows for the quarters ended March 31:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | First Quarter | | |
| | 2021 | | 2020 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 370 | | | $ | 389 | | | $ | (19) | | (5) | % | | | | | | | |
Cost of fuel and energy | | 165 | | | 170 | | | (5) | | (3) | | | | | | | | |
Utility margin | | $ | 205 | | | $ | 219 | | | $ | (14) | | (6) | % | | | | | | | |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 1,587 | | | 1,544 | | | 43 | | 3 | % | | | | | | | |
Commercial | | 954 | | | 1,011 | | | (57) | | (6) | | | | | | | | |
Industrial | | 1,057 | | | 1,151 | | | (94) | | (8) | | | | | | | | |
Other | | 47 | | | 48 | | | (1) | | (2) | | | | | | | | |
Total fully bundled(1) | | 3,645 | | | 3,754 | | | (109) | | (3) | | | | | | | | |
Distribution only service | | 516 | | | 611 | | | (95) | | (16) | | | | | | | | |
Total retail | | 4,161 | | | 4,365 | | | (204) | | (5) | | | | | | | | |
Wholesale | | 84 | | | 153 | | | (69) | | (45) | | | | | | | | |
Total GWhs sold | | 4,245 | | | 4,518 | | | (273) | | (6) | % | | | | | | | |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 978 | | | 961 | | | 17 | | 2 | % | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 95.01 | | | $ | 96.01 | | | $ | (1.00) | | (1) | % | | | | | | | |
| | | | | | | | | | | | | | |
Wholesale | | $ | 49.42 | | | $ | 31.58 | | | $ | 17.84 | | 56 | % | | | | | | | |
| | | | | | | | | | | | | | |
Heating degree days | | 994 | | | 942 | | | 52 | | 6 | % | | | | | | | |
Cooling degree days | | 6 | | | 2 | | | 4 | | * | | | | | | | |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 2,534 | | | 2,622 | | | (88) | | (3) | % | | | | | | | |
| | | | | | | | | | | | | | |
Renewables | | 16 | | | 16 | | | — | | — | | | | | | | | |
Total energy generated | | 2,550 | | | 2,638 | | | (88) | | (3) | | | | | | | | |
Energy purchased | | 1,355 | | | 1,240 | | | 115 | | 9 | | | | | | | | |
Total | | 3,905 | | | 3,878 | | | 27 | | 1 | % | | | | | | | |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(4): | | | | | | | | | | | | | | |
Energy generated | | $ | 14.96 | | | $ | 21.95 | | | $ | (6.99) | | (32) | % | | | | | | | |
Energy purchased | | $ | 93.84 | | | $ | 90.56 | | | $ | 3.28 | | 4 | % | | | | | | | |
* 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 683 GWhs and 710 GWhs of gas generated energy that is purchased at cost by related parties for the first quarter 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 March 31, 2021 Compared to Quarter Ended March 31, 2020
Utility margin decreased $14 million, or 6%, for the first quarter of 2021 compared to 2020 primarily due to:
•$9 million of lower retail rates due to the 2020 regulatory rate review with new rates effective January 2021,
•$2 million due to lower energy efficiency program rates (offset in operations and maintenance expense),
•$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 4.7% primarily due to the impacts of COVID-19, which resulted in lower industrial, commercial and distribution only service customer usage and higher residential customer usage, offset by the favorable impacts of weather and
•$1 million of lower other revenue due to a regulatory amortization of impact fee that ended December 2020.
Operations and maintenance decreased $19 million, or 23%, for the first quarter of 2021 compared to 2020 primarily due to lower net regulatory instructed deferrals and amortizations of $11 million, mainly relating to deferrals in 2020 of the non-labor cost savings from the Navajo generating station retirement which was approved for amortization in the 2020 regulatory rate review with new rates effective January 2021, and timing of the regulatory impacts for the ON Line lease cost reallocation, lower plant operations and maintenance costs, a reduction to the accrual for earning sharing and lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $11 million, or 12%, for the first quarter of 2021 compared to 2020 primarily due to regulatory amortizations approved in the 2020 regulatory rate review effective January 2021 and higher plant placed in service.
Interest expense decreased $4 million, or 10%, for the first quarter of 2021 compared to 2020 primarily due to lower interest expense on long-term debt.
Other, net increased $10 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies of $7 million, lower pension expense and higher interest income, mainly from carrying charges on regulatory items.
Income tax benefit decreased $1 million, for the first quarter of 2021 compared to 2020. Nevada Power did not incur tax expense in 2021 primarily due to the recognition of amortization of excess deferred income taxes following regulatory approval effective January 2021. The effective tax rate was 20% in 2020.
Liquidity and Capital Resources
As of March 31, 2021, Nevada Power's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 92 | |
Credit facility | | 400 | |
| | |
| | |
| | |
| | |
Total net liquidity | | $ | 492 | |
Credit facility: | | |
Maturity date | | 2022 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $179 million and $79 million, respectively. The change was primarily due to lower payments for fuel and energy costs, the timing of payments for operating costs and lower inventory purchases, partially offset by lower collections from customers.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(106) million and $(111) million, respectively. The change was primarily due to decreased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $(5) million and $140 million, respectively. The change was primarily due to lower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt.
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):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2020 | | 2021 | | 2021 |
| | | | | |
Electric distribution | $ | 64 | | | $ | 41 | | | $ | 167 | |
Electric transmission | 8 | | | 13 | | | 77 | |
Solar generation | — | | | 1 | | | 32 | |
Other | 39 | | | 51 | | | 181 | |
Total | $ | 111 | | | $ | 106 | | | $ | 457 | |
Nevada Power's Fourth Amendment to the 2018 Joint IRP proposed 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 are likely to change as a result of the RFP process and some are still pending PUCN approval. Nevada Power's historical and forecast capital expenditures include the 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 primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has 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 has been approved by the PUCN with the exception of the Northwest substation to Harry Allen substation segment for which approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission 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 March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2020.
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, 2020. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2020.
Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
PART I
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 March 31, 2021, the related consolidated statements of operations, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 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 balance sheet of Sierra Pacific as of December 31, 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 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, 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 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
April 30, 2021
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 8 | | | $ | 19 | |
Trade receivables, net | 93 | | | 97 | |
| | | |
Inventories | 74 | | | 77 | |
Derivative contracts | 16 | | | 9 | |
Regulatory assets | 91 | | | 67 | |
| | | |
Other current assets | 38 | | | 36 | |
Total current assets | 320 | | | 305 | |
| | | |
Property, plant and equipment, net | 3,188 | | | 3,164 | |
| | | |
Regulatory assets | 270 | | | 267 | |
Other assets | 185 | | | 183 | |
| | | |
Total assets | $ | 3,963 | | | $ | 3,919 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 103 | | | $ | 108 | |
Accrued interest | 11 | | | 14 | |
Accrued property, income and other taxes | 16 | | | 14 | |
Short-term debt | 55 | | | 45 | |
| | | |
| | | |
Regulatory liabilities | 28 | | | 34 | |
Customer deposits | 14 | | | 15 | |
Other current liabilities | 33 | | | 25 | |
Total current liabilities | 260 | | | 255 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
Finance lease obligations | 119 | | | 121 | |
Regulatory liabilities | 466 | | | 463 | |
Deferred income taxes | 382 | | | 374 | |
Other long-term liabilities | 133 | | | 131 | |
Total liabilities | 2,524 | | | 2,508 | |
| | | |
Commitments and contingencies (Note 7) | 0 | | 0 |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | 0 | | | 0 | |
Additional paid-in capital | 1,111 | | | 1,111 | |
Retained earnings | 329 | | | 301 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,439 | | | 1,411 | |
| | | |
Total liabilities and shareholder's equity | $ | 3,963 | | | $ | 3,919 | |
| | | |
The accompanying notes are an integral part of the consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2021 | | 2020 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 181 | | | $ | 184 | |
Regulated natural gas | | | | | 39 | | | 48 | |
Total operating revenue | | | | | 220 | | | 232 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 82 | | | 80 | |
Cost of natural gas purchased for resale | | | | | 21 | | | 30 | |
Operations and maintenance | | | | | 36 | | | 42 | |
Depreciation and amortization | | | | | 36 | | | 34 | |
Property and other taxes | | | | | 6 | | | 6 | |
Total operating expenses | | | | | 181 | | | 192 | |
| | | | | | | |
Operating income | | | | | 39 | | | 40 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (14) | | | (14) | |
| | | | | | | |
Allowance for equity funds | | | | | 1 | | | 1 | |
Other, net | | | | | 6 | | | 1 | |
Total other income (expense) | | | | | (7) | | | (12) | |
| | | | | | | |
Income before income tax expense | | | | | 32 | | | 28 | |
Income tax expense | | | | | 4 | | | 3 | |
Net income | | | | | $ | 28 | | | $ | 25 | |
| | | | | | | |
The accompanying notes are an integral part of these consolidated 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, December 31, 2019 | | 1,000 | | | $ | 0 | | | $ | 1,111 | | | $ | 210 | | | $ | (1) | | | $ | 1,320 | |
Net income | | — | | | — | | | — | | | 25 | | | — | | | 25 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2020 | | 1,000 | | | $ | 0 | | | $ | 1,111 | | | $ | 235 | | | $ | (1) | | | $ | 1,345 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2020 | | 1,000 | | | $ | 0 | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | |
Net income | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | 1,000 | | | $ | 0 | | | $ | 1,111 | | | $ | 329 | | | $ | (1) | | | $ | 1,439 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements. |
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 28 | | | $ | 25 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
Depreciation and amortization | 36 | | | 34 | |
Allowance for equity funds | (1) | | | (1) | |
Changes in regulatory assets and liabilities | (13) | | | (10) | |
Deferred income taxes and amortization of investment tax credits | 4 | | | (3) | |
Deferred energy | (18) | | | 14 | |
Amortization of deferred energy | (3) | | | 4 | |
Other, net | 0 | | | 1 | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 8 | | | 1 | |
Inventories | 3 | | | (3) | |
Accrued property, income and other taxes | (3) | | | 4 | |
Accounts payable and other liabilities | 1 | | | (12) | |
Net cash flows from operating activities | 42 | | | 54 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (61) | | | (52) | |
| | | |
| | | |
Net cash flows from investing activities | (61) | | | (52) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Net proceeds from short-term debt | 10 | | | 0 | |
| | | |
| | | |
Other, net | (2) | | | (1) | |
Net cash flows from financing activities | 8 | | | (1) | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (11) | | | 1 | |
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 | $ | 15 | | | $ | 33 | |
| | | |
The accompanying notes are an integral part of these consolidated 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 March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 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 Sierra Pacific's 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 Sierra Pacific's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2021.
(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 March 31, 2021 and December 31, 2020, consist of funds restricted by the Public 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 March 31, 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 |
| March 31, | | December 31, |
| 2021 | | 2020 |
Cash and cash equivalents | $ | 8 | | | $ | 19 | |
Restricted cash and cash equivalents included in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 15 | | | $ | 26 | |
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
| | | | | | | | | | | | | | | | | |
| | | As of |
| Depreciable Life | | March 31, | | December 31, |
| | 2021 | | 2020 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,131 | | | $ | 1,130 | |
Electric transmission | 50 - 100 years | | 917 | | | 908 | |
Electric distribution | 20 - 100 years | | 1,763 | | | 1,754 | |
Electric general and intangible plant | 5 - 70 years | | 193 | | | 189 | |
Natural gas distribution | 35 - 70 years | | 431 | | | 429 | |
Natural gas general and intangible plant | 5 - 70 years | | 15 | | | 15 | |
Common general | 5 - 70 years | | 357 | | | 355 | |
Utility plant | | | 4,807 | | | 4,780 | |
Accumulated depreciation and amortization | | | (1,783) | | | (1,755) | |
Utility plant, net | | | 3,024 | | | 3,025 | |
Other non-regulated, net of accumulated depreciation and amortization | 70 years | | 2 | | | 2 | |
Plant, net | | | 3,026 | | | 3,027 | |
Construction work-in-progress | | | 162 | | | 137 | |
Property, plant and equipment, net | | | $ | 3,188 | | | $ | 3,164 | |
(4)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 | | |
| Ended March 31, | | |
| 2021 | | 2020 | | | | |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | | | |
| | | | | | | |
| | | | | | | |
Effects of ratemaking | (10) | | | (8) | | | | | |
| | | | | | | |
| | | | | | | |
Other | 2 | | | (2) | | | | | |
Effective income tax rate | 13 | % | | 11 | % | | | | |
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.
(5) 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. 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 receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2021 | | 2020 |
Qualified Pension Plan: | | | |
| | | |
Other non-current assets | $ | 27 | | | $ | 26 | |
| | | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
| | | |
| | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (8) | |
| | | |
Other Postretirement Plans: | | | |
| | | |
| | | |
| | | |
Other long-term liabilities | (14) | | | (13) | |
(6) 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):
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| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of March 31, 2021 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 0 | | | $ | 16 | | | $ | 16 | |
Money market mutual funds(1) | 5 | | | 0 | | | 0 | | | 5 | |
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| $ | 5 | | | $ | 0 | | | $ | 16 | | | $ | 21 | |
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Liabilities - commodity derivatives | $ | 0 | | | $ | 0 | | | $ | (4) | | | $ | (4) | |
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As of December 31, 2020 | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | 0 | | | $ | 0 | | | $ | 9 | | | $ | 9 | |
Money market mutual funds(1) | 17 | | | 0 | | | 0 | | | 17 | |
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| $ | 17 | | | $ | 0 | | | $ | 9 | | | $ | 26 | |
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Liabilities - commodity derivatives | $ | 0 | | | $ | 0 | | | $ | (2) | | | $ | (2) | |
(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.
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 amount. 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):
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| As of March 31, 2021 | | As of December 31, 2020 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
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Long-term debt | $ | 1,164 | | | $ | 1,312 | | | $ | 1,164 | | | $ | 1,358 | |
(7) 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.
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.
(8) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 9 (in millions):
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| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: | | | | | | | | | | | |
Retail: | | | | | | | | | | | |
Residential | $ | 71 | | | $ | 25 | | | $ | 96 | | | $ | 69 | | | $ | 30 | | | $ | 99 | |
Commercial | 54 | | | 10 | | | 64 | | | 57 | | | 13 | | | 70 | |
Industrial | 39 | | | 3 | | | 42 | | | 41 | | | 4 | | | 45 | |
Other | 1 | | | 0 | | | 1 | | | 1 | | | 0 | | | 1 | |
Total fully bundled | 165 | | | 38 | | | 203 | | | 168 | | | 47 | | | 215 | |
Distribution only service | 1 | | | 0 | | | 1 | | | 1 | | | 0 | | | 1 | |
Total retail | 166 | | | 38 | | | 204 | | | 169 | | | 47 | | | 216 | |
Wholesale, transmission and other | 15 | | | 0 | | | 15 | | | 14 | | | 0 | | | 14 | |
Total Customer Revenue | 181 | | | 38 | | | 219 | | | 183 | | | 47 | | | 230 | |
Other revenue | 0 | | | 1 | | | 1 | | | 1 | | | 1 | | | 2 | |
Total revenue | $ | 181 | | | $ | 39 | | | $ | 220 | | | $ | 184 | | | $ | 48 | | | $ | 232 | |
(9)Segment Information
Sierra Pacific has identified 2 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):
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| Three-Month Periods | | |
| Ended March 31, | | |
| 2021 | | 2020 | | | | |
Operating revenue: | | | | | | | |
Regulated electric | $ | 181 | | | $ | 184 | | | | | |
Regulated natural gas | 39 | | | 48 | | | | | |
Total operating revenue | $ | 220 | | | $ | 232 | | | | | |
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Operating income: | | | | | | | |
Regulated electric | $ | 31 | | | $ | 33 | | | | | |
Regulated natural gas | 8 | | | 7 | | | | | |
Total operating income | 39 | | | 40 | | | | | |
Interest expense | (14) | | | (14) | | | | | |
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Allowance for equity funds | 1 | | | 1 | | | | | |
Other, net | 6 | | | 1 | | | | | |
Income before income tax expense | $ | 32 | | | $ | 28 | | | | | |
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| | | As of |
| | | | | March 31, | | December 31, |
| | | | | 2021 | | 2020 |
Assets: | | | | | | | |
Regulated electric | | | | | $ | 3,589 | | | $ | 3,540 | |
Regulated natural gas | | | | | 348 | | | 342 | |
Other(1) | | | | | 26 | | | 37 | |
Total assets | | | | | $ | 3,963 | | | $ | 3,919 | |
(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 First Quarterof 2021 and 2020
Overview
Net income for the first quarter of 2021 was $28 million, an increase of $3 million, or 12%, compared to 2020 primarily due to $6 million of lower operations and maintenance expenses, mainly due to lower plant operations and maintenance expenses and a reduction to the accrual for earning sharing, and $5 million of higher other, net, mainly due to higher cash surrender value of corporate-owned life insurance policies and lower pension costs, partially offset by $5 million of lower electric utility margin, mainly from lower revenue recognized due to a favorable regulatory decision.
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):
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| | First Quarter | | |
| | 2021 | | 2020 | | Change | | | | | | |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 181 | | | $ | 184 | | | $ | (3) | | (2) | % | | | | | | | |
Cost of fuel and energy | | 82 | | | 80 | | | 2 | | 3 | | | | | | | | |
Electric utility margin | | 99 | | | 104 | | | (5) | | (5) | | | | | | | | |
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Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 39 | | | 48 | | | (9) | | (19) | % | | | | | | | |
Natural gas purchased for resale | | 21 | | | 30 | | | (9) | | (30) | | | | | | | | |
Natural gas utility margin | | 18 | | | 18 | | | — | | — | | | | | | | | |
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Utility margin | | 117 | | | 122 | | | (5) | | (4) | % | | | | | | | |
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Operations and maintenance | | 36 | | | 42 | | | (6) | | (14) | % | | | | | | | |
Depreciation and amortization | | 36 | | | 34 | | | 2 | | 6 | | | | | | | | |
Property and other taxes | | 6 | | | 6 | | | — | | — | | | | | | | | |
Operating income | | $ | 39 | | | $ | 40 | | | $ | (1) | | (3) | % | | | | | | | |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the quarters ended March 31:
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| | First Quarter | | |
| | 2021 | | 2020 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 181 | | | $ | 184 | | | $ | (3) | | (2) | % | | | | | | | |
Cost of fuel and energy | | 82 | | | 80 | | | 2 | | 3 | | | | | | | | |
Utility margin | | $ | 99 | | | $ | 104 | | | $ | (5) | | (5) | % | | | | | | | |
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Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 671 | | | 635 | | | 36 | | 6 | % | | | | | | | |
Commercial | | 677 | | | 701 | | | (24) | | (3) | | | | | | | | |
Industrial | | 897 | | | 909 | | | (12) | | (1) | | | | | | | | |
Other | | 4 | | | 4 | | | — | | — | | | | | | | | |
Total fully bundled(1) | | 2,249 | | | 2,249 | | | — | | — | | | | | | | | |
Distribution only service | | 397 | | | 412 | | | (15) | | (4) | | | | | | | | |
Total retail | | 2,646 | | | 2,661 | | | (15) | | (1) | | | | | | | | |
Wholesale | | 175 | | | 193 | | | (18) | | (9) | | | | | | | | |
Total GWhs sold | | 2,821 | | | 2,854 | | | (33) | | (1) | % | | | | | | | |
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Average number of retail customers (in thousands) | | 363 | | | 356 | | | 7 | | 2 | % | | | | | | | |
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Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 73.17 | | | $ | 74.76 | | | $ | (1.59) | | (2) | % | | | | | | | |
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Wholesale | | $ | 60.18 | | | $ | 49.05 | | | $ | 11.13 | | 23 | % | | | | | | | |
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Heating degree days | | 2,198 | | 2,066 | | 132 | | 6 | % | | | | | | | |
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Sources of energy (GWhs)(2): | | | | | | | | | | | | | | |
Natural gas | | 1,082 | | | 1,215 | | | (133) | | (11) | % | | | | | | | |
Coal | | 29 | | | 66 | | | (37) | | (56) | | | | | | | | |
Renewables(3) | | 6 | | | 6 | | | — | | — | | | | | | | | |
Total energy generated | | 1,117 | | | 1,287 | | | (170) | | (13) | | | | | | | | |
Energy purchased | | 1,373 | | | 1,325 | | | 48 | | 4 | | | | | | | | |
Total | | 2,490 | | | 2,612 | | | (122) | | (5) | % | | | | | | | |
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Average cost of energy per MWh(4): | | | | | | | | | | | | | | |
Energy generated | | $ | 25.23 | | | $ | 26.53 | | | $ | (1.30) | | (5) | % | | | | | | | |
Energy purchased | | $ | 38.93 | | | $ | 34.96 | | | $ | 3.97 | | 11 | % | | | | | | | |
(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2) GWh amounts are net of energy used by the related generating facilities.
(3) Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.
(4) The average 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 for the quarters ended March 31:
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| | First Quarter | | |
| | 2021 | | 2020 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 39 | | | $ | 48 | | | $ | (9) | | (19) | % | | | | | | | |
Natural gas purchased for resale | | 21 | | | 30 | | | (9) | | (30) | | | | | | | | |
Utility margin | | $ | 18 | | | $ | 18 | | | $ | — | | — | % | | | | | | | |
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Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 4,658 | | | 4,386 | | | 272 | | 6 | % | | | | | | | |
Commercial | | 2,304 | | | 2,167 | | | 137 | | 6 | | | | | | | | |
Industrial | | 745 | | | 653 | | | 92 | | 14 | | | | | | | | |
Total retail | | 7,707 | | | 7,206 | | | 501 | | 7 | % | | | | | | | |
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Average number of retail customers (in thousands) | | 176 | | | 173 | | | 3 | | 2 | % | | | | | | | |
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Average revenue per retail Dth sold | | $ | 5.03 | | | $ | 6.58 | | | $ | (1.55) | | (24) | % | | | | | | | |
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Heating degree days | | 2,198 | | | 2,066 | | | 132 | | 6 | % | | | | | | | |
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Average cost of natural gas per retail Dth sold | | $ | 2.73 | | | $ | 4.22 | | | $ | (1.49) | | (35) | % | | | | | | | |
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Quarter Ended March 31, 2021 Compared to Quarter Ended March 31, 2020
Electric utility margin decreased$5 million, or 5%, for the first quarter of 2021 compared to 2020 primarily due to:
•$3 million in lower revenue recognized due to a favorable regulatory decision and
•$1 million due to price impacts from changes in sales mix. Retail customer volumes, including distribution only service customers, decreased 0.6% primarily due to the impacts of COVID-19, which resulted in lower distribution only service, commercial and industrial customer usage and higher residential customer usage, offset by the favorable impacts of weather.
Operations and maintenance decreased $6 million, or 14%, for the first quarter of 2021 compared to 2020 primarily due to lower plant operations and maintenance expenses, a reduction to the accrual for earning sharing and lower regulatory amortizations.
Depreciation and amortization increased $2 million, or 6%, for the first quarter of 2021 compared to 2020 primarily due to regulatory amortizations and higher plant in service.
Other, net increased $5 million for the first quarter of 2021 compared to 2020 primarily due to higher cash surrender value of corporate-owned life insurance policies and lower pension costs.
Income tax expense increased $1 million, or 33%, for the first quarter of 2021 compared to 2020. The effective tax rate was 13% in 2021 and 11% in 2020 and increased primarily due to higher pre-tax income.
Liquidity and Capital Resources
As of March 31, 2021, Sierra Pacific's total net liquidity was as follows (in millions):
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Cash and cash equivalents | | $ | 8 | |
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Credit facility | | 250 | |
Less - | | |
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Short-term debt | | (55) | |
Net credit facility | | 195 | |
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Total net liquidity | | $ | 203 | |
Credit facility: | | |
Maturity date | | 2022 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $42 million and $54 million, respectively. The change was primarily due to higher payments for fuel and energy costs and lower collections from customers partially offset by lower inventory purchases, the timing of payments for operating costs and increased collections of customer advances.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(61) million and $(52) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month periods ended March 31, 2021 and 2020 were $8 million and $(1) million, respectively. The change was primarily due to higher proceeds from short-term debt.
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):
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| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2020 | | 2021 | | 2021 |
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Electric distribution | $ | 37 | | | $ | 20 | | | $ | 126 | |
Electric transmission | 8 | | | 16 | | | 124 | |
Solar generation | — | | | — | | | 18 | |
Other | 7 | | | 25 | | | 129 | |
Total | $ | 52 | | | $ | 61 | | | $ | 397 | |
Sierra Pacific's Fourth Amendment to the 2018 Joint IRP proposed an increase in electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2021. These estimates are likely to change as a result of the RFP process and some are still pending PUCN approval. Sierra Pacific's historical and forecast capital expenditures include the 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 primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has 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. Construction of the project has been approved by the PUCN with the exception of the Ft. Churchill substation to the Robinson Summit substation segment for which conditional approval was limited to design, permitting and land acquisition only. Operating expenditures consist of routine expenditures for transmission 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 March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2020.
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, 2020. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2020.
Eastern Energy
evaluated goodwill on April 1, 2020Gas Holdings, LLC and
intends to evaluate goodwill annually on October 31, effective October 31, 2020, to align with BHE’s policy.Note 3. Acquisitions and Dispositions
Acquisitionits 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
by BHEGas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of March 31, 2021, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 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
April 30, 2021
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, 2021 | | December 31, 2020 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 106 | | | $ | 35 | |
Restricted cash and cash equivalents | 9 | | | 13 | |
Trade receivables, net | 158 | | | 177 | |
Receivables from affiliates | 263 | | | 139 | |
Other receivables | 44 | | | 51 | |
Inventories | 120 | | | 119 | |
| | | |
Other current assets | 145 | | | 122 | |
Total current assets | 845 | | | 656 | |
| | | |
Property, plant and equipment, net | 10,099 | | | 10,144 | |
Goodwill | 1,286 | | | 1,286 | |
| | | |
Investments | 262 | | | 244 | |
| | | |
Other assets | 240 | | | 291 | |
| | | |
Total assets | $ | 12,732 | | | $ | 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 |
| March 31, 2021 | | December 31, 2020 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 59 | | | $ | 71 | |
Accounts payable to affiliates | 57 | | | 39 | |
Accrued interest | 54 | | | 19 | |
Accrued property, income and other taxes | 60 | | | 29 | |
| | | |
Notes payable | 0 | | | 9 | |
| | | |
| | | |
Current portion of long-term debt | 500 | | | 500 | |
Other current liabilities | 127 | | | 147 | |
Total current liabilities | 857 | | | 814 | |
| | | |
Long-term debt | 3,914 | | | 3,925 | |
| | | |
| | | |
Regulatory liabilities | 668 | | | 669 | |
| | | |
Other long-term liabilities | 215 | | | 218 | |
Total liabilities | 5,654 | | | 5,626 | |
| | | |
Commitments and contingencies (Note 8) | 0 | | 0 |
| | | |
Equity: | | | |
Member's equity: | | | |
| | | |
Membership interests | 3,035 | | | 2,957 | |
| | | |
| | | |
Accumulated other comprehensive loss, net | (45) | | | (53) | |
Total member's equity | 2,990 | | | 2,904 | |
Noncontrolling interests | 4,088 | | | 4,091 | |
Total equity | 7,078 | | | 6,995 | |
| | | |
Total liabilities and equity | $ | 12,732 | | | $ | 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 |
| Ended March 31, |
| 2021 | | 2020 |
| | | |
| | | |
| | | |
| | | |
Operating revenue | $ | 486 | | | $ | 556 | |
| | | |
Operating expenses: | | | |
| | | |
Cost of gas | 0 | | | 8 | |
Operations and maintenance | 124 | | | 168 | |
Depreciation and amortization | 80 | | | 93 | |
Property and other taxes | 39 | | | 39 | |
| | | |
Total operating expenses | 243 | | | 308 | |
| | | |
Operating income | 243 | | | 248 | |
| | | |
Other income (expense): | | | |
Interest expense | (44) | | | (58) | |
| | | |
Allowance for equity funds | 2 | | | 5 | |
Interest and dividend income | 0 | | | 30 | |
| | | |
Other, net | 1 | | | 14 | |
Total other income (expense) | (41) | | | (9) | |
| | | |
Income before income tax expense and equity income | 202 | | | 239 | |
Income tax expense | 27 | | | 52 | |
Equity income | 16 | | | 15 | |
| | | |
| | | |
Net income | 191 | | | 202 | |
Net income attributable to noncontrolling interests | 102 | | | 33 | |
Net income attributable to Eastern Energy Gas | $ | 89 | | | $ | 169 | |
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 |
| Ended March 31, |
| 2021 | | 2020 |
| | | |
Net income | $ | 191 | | | $ | 202 | |
| | | |
Other comprehensive income (loss), net of tax: | | | |
Unrecognized amounts on retirement benefits, net of tax of $0 and $1 | 2 | | | 1 | |
| | | |
| | | |
Unrealized gains (losses) on cash flow hedges, net of tax of $3 and $(30) | 10 | | | (85) | |
Total other comprehensive income (loss), net of tax | 12 | | | (84) | |
| | | |
Comprehensive income | 203 | | | 118 | |
Comprehensive income attributable to noncontrolling interests | 106 | | | 33 | |
Comprehensive income attributable to Eastern Energy Gas | $ | 97 | | | $ | 85 | |
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, December 31, 2019 | | | | | | | | | $ | 9,031 | | | $ | (187) | | | $ | 1,385 | | | $ | 10,229 | |
Net income | | | | | | | | | 169 | | | — | | | 33 | | | 202 | |
Other comprehensive loss | | | | | | | | | — | | | (84) | | | — | | | (84) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Distributions | | | | | | | | | (232) | | | — | | | (37) | | | (269) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, March 31, 2020 | | | | | | | | | $ | 8,968 | | | $ | (271) | | | $ | 1,381 | | | $ | 10,078 | |
| | | | | | | | | | | | | | | |
Balance, December 31, 2020 | | | | | | | | | $ | 2,957 | | | $ | (53) | | | $ | 4,091 | | | $ | 6,995 | |
Net income | | | | | | | | | 89 | | | — | | | 102 | | | 191 | |
Other comprehensive income | | | | | | | | | — | | | 8 | | | 4 | | | 12 | |
Contributions | | | | | | | | | 11 | | | — | | | — | | | 11 | |
Distributions | | | | | | | | | (22) | | | — | | | (109) | | | (131) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, March 31, 2021 | | | | | | | | | $ | 3,035 | | | $ | (45) | | | $ | 4,088 | | | $ | 7,078 | |
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)
| | | | | | | | | | | |
| Three-Month Periods |
| Ended March 31, |
| 2021 | | 2020 |
Cash flows from operating activities: | | | |
Net income | $ | 191 | | | $ | 202 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
| | | |
Depreciation and amortization | 80 | | | 93 | |
Allowance for equity funds | (2) | | | (5) | |
Equity income, net of distributions | (5) | | | (1) | |
Changes in regulatory assets and liabilities | 6 | | | 7 | |
Deferred income taxes | 30 | | | 15 | |
Other, net | 0 | | | (1) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | (56) | | | 357 | |
Derivative collateral, net | 2 | | | 9 | |
Pension and other postretirement benefit plans | 0 | | | (18) | |
Accrued property, income and other taxes | (25) | | | (17) | |
Accounts payable and other liabilities | 20 | | | 26 | |
Net cash flows from operating activities | 241 | | | 667 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (55) | | | (76) | |
| | | |
| | | |
| | | |
Loans to affiliates | 0 | | | (262) | |
| | | |
Other, net | (1) | | | (4) | |
Net cash flows from investing activities | (56) | | | (342) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
Net repayments of short-term debt | 0 | | | (32) | |
Repayment of notes payable, net | (9) | | | (5) | |
| | | |
| | | |
| | | |
Distributions | (109) | | | (269) | |
| | | |
| | | |
Net cash flows from financing activities | (118) | | | (306) | |
| | | |
| | | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 67 | | | 19 | |
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 | $ | 115 | | | $ | 58 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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
BHE.Berkshire Hathaway Energy Company ("BHE"). Approval of the transaction under the
Hart-Scott RodinoHart-Scott-Rodino Act was not obtained within 75 days and
Dominion EnergyDEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the
GTacquisition of substantially all of the natural gas transmission and storage business of DEI and Dominion Energy Questar Corporation, exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S
TransactionTransaction") and the
Q-Pipe Transaction. A separateproposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement
was entered into
between Dominion Energy and BHE inon October
5, 2020
for the("Q-Pipe Transaction"). The Q-Pipe Transaction
which is currently anticipated to close in
earlythe first half of 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions.
In November 2020,Prior to the completion of the GT&S Transaction, Eastern Energy
Gas finalized a restructuring whereby Eastern Energy
disposed of Dominion EnergyGas distributed the Questar Pipeline
Group and a 50% noncontrolling interest in Cove Point to
Dominion Energy.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.
12
In On November 1, 2020, BHE completed the GT&S Transaction. As a result of the GT&S Transaction, was completed and Eastern Energy with the exception of Dominion Energy Questar Pipeline as discussed above,Gas became an indirect wholly-ownedwholly owned subsidiary of BHE. Dominion Energy retainedBHE is a 50% noncontrolling interestholding company based in Cove Point as well asDes Moines, Iowa that owns subsidiaries principally engaged in the assetsenergy 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
obligationsthe 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
pension and other postretirement employee benefit plans associated withdisclosures required by GAAP for annual financial statements. Management believes the
operations sold and relating to services provided before closing. See Notes 5 and 8 for more information on the GT&S Transaction.Based on the recorded balances at September 30, 2020, Eastern Energy expects to record a distributionunaudited Consolidated Financial Statements contain all adjustments (consisting only of net assets of approximately $700 million, including goodwill of approximately $185 million,normal recurring adjustments) considered necessary for the distributionfair presentation of Dominion Energy Questar Pipeline to Dominion Energythe unaudited Consolidated Financial Statements as of March 31, 2021 and a distributionfor the three-month periods ended March 31, 2021 and 2020. The results of net assetsoperations for the three-month periods ended March 31, 2021 are not necessarily indicative of approximately $900 million related to the pension and other postretirement employee benefit plans retained by Dominion Energy. Additionally, Eastern Energy expects to record an approximately $2.7 billion increase in noncontrolling interests for Dominion Energy’s retained 50% noncontrolling interest in Cove Point. These equity transactions will be recorded in the Consolidated Balance Sheets in the fourth quarter of 2020.
Dominion Energy Gas Restructuring
The Dominion Energy Gas Restructuring was consideredresults to be a reorganizationexpected for the full year.
The preparation of
entities under common control. As a result, Eastern Energy’s basisthe unaudited Consolidated Financial Statements in
DCPconformity with GAAP requires management to make estimates and
DMLPHCII, which includedassumptions that affect the
general partnerreported amounts of
Dominion Energy Midstream, a controlling 75% interest in Cove Point, DECG, Dominion Energy Questar Pipeline, a 50% noncontrolling interest in White River Hub and a 25.93% noncontrolling interest in Iroquois, is equal to Dominion Energy’s cost basis in the assets and liabilities
of such entities sinceat the
applicable inception dates of common control. In November 2019, following completiondate of the
Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Eastern Energy and therefore are consolidated by Eastern Energy. The accompanyingunaudited 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
of Eastern Energy have been retrospectively adjusted to
include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by Dominion Energy, and subsequently sold to Brookfield in December 2019, and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest.The Dominion Energy Gas Restructuring includes the disposition of East Ohio and DGP by Eastern Energy in November 2019. This restructuring represented a strategic shift in the operations of Eastern Energy as Eastern Energy’s operations consist of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes ofincluded in Eastern Energy have been retrospectively adjusted to include the historical results and financial position of East Ohio and DGP as discontinued operations until November 2019. As the Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control, Eastern Energy has reflected the disposition as an equity transaction. The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Eastern Energy’s Consolidated Statements of Income:
| | Three Months Ended September 30, 2019 | | | Nine Months Ended September 30, 2019 | |
(millions) | | | | | | | | |
Operating revenue | | $ | 155 | | | $ | 538 | |
Depreciation and amortization | | | 23 | | | | 66 | |
Other operating expenses | | | 90 | | | | 364 | |
Other income | | | 20 | | | | 55 | |
Interest and related charges | | | 11 | | | | 30 | |
Income tax expense | | | 8 | | | | 25 | |
Net income from discontinued operations | | $ | 43 | | | $ | 108 | |
Capital expenditures and significant noncash items relating to East Ohio included the following:
| | Nine Months Ended September 30, 2019 | |
(millions) | | | | |
Capital expenditures | | $ | 267 | |
Significant noncash items | | | | |
Charge related to a voluntary retirement program | | | 20 | |
Accrued capital expenditures | | | 10 | |
13
The following table represents selected information regarding the results of operations of DGP, which are reported as discontinued operations in Eastern Energy’s Consolidated Statements of Income:
| | Three Months Ended September 30, 2019 | | | Nine Months Ended September 30, 2019 | |
(millions) | | | | | | | | |
Operating revenue | | $ | 31 | | | $ | 110 | |
Depreciation and amortization | | | 1 | | | | 4 | |
Other operating expenses | | | 27 | | | | 83 | |
Income tax expense | | | 1 | | | | 6 | |
Net income from discontinued operations | | $ | 2 | | | $ | 17 | |
Capital expenditures and significant noncash items of DGP included the following:
| | Nine Months Ended September 30, 2019 | |
(millions) | | | | |
Capital expenditures | | $ | 10 | |
14
Note 4. Operating Revenue
Eastern Energy’s operating revenue consists of the following:
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2020 | | | 2019 | | | 2020 | | | 2019 | |
(millions) | | | | | | | | | | | | | | | | |
Regulated gas transportation and storage(1) | | $ | 311 | | | $ | 306 | | | $ | 957 | | | $ | 952 | |
Nonregulated gas transportation and storage | | | 175 | | | | 153 | | | | 525 | | | | 501 | |
Management service revenue(1) | | | 16 | | | | 37 | | | | 76 | | | | 126 | |
Regulated gas sales - wholesale | | | 25 | | | | 0 | | | | 27 | | | | 2 | |
Nonregulated gas sales(1) | | | 1 | | | | 1 | | | | 2 | | | | 4 | |
Other regulated revenues(2) | | | 1 | | | | 3 | | | | 4 | | | | 8 | |
Other nonregulated revenues(1)(2) | | | 1 | | | | 1 | | | | 3 | | | | 2 | |
Total operating revenue from contracts with customers | | | 530 | | | | 501 | | | | 1,594 | | | | 1,595 | |
Other revenues(1) | | | 1 | | | | 1 | | | | 3 | | | | 3 | |
Total operating revenue | | $ | 531 | | | $ | 502 | | | $ | 1,597 | | | $ | 1,598 | |
(1) See Note 16 for amounts attributable to related parties and affiliates.
(2)
| Amounts above include sales which are considered to be goods transferred at a point in time. Such amounts included $1 million for both the three months ended September 30, 2020 and 2019, and $2 million and $4 million for the nine months ended September 30, 2020 and 2019, respectively, primarily consisting of natural gas liquid sales.
|
The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when Eastern Energy expects to recognize this revenue. These revenues relate to contracts containing fixed prices where Eastern Energy will earn the associated revenue over time as its stands ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which Eastern Energy elects to recognize revenue in the amount it has a right to invoice.
Revenue expected to be recognized on multi-year contracts in place at September 30, 2020 | | 2020 | | | 2021 | | | 2022 | | | 2023 | | | 2024 | | | Thereafter | | | Total | |
(millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | $ | 468 | | | $ | 1,790 | | | $ | 1,669 | | | $ | 1,476 | | | $ | 1,304 | | | $ | 13,412 | | | $ | 20,119 | |
Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. Eastern Energy’s contract asset balances were $32 million and $40 million at September 30, 2020 and December 31, 2019, respectively. Eastern Energy’s contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At both September 30, 2020 and December 31, 2019, Eastern Energy’s contract liability balances were $20 million. Eastern Energy’s contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.
Eastern Energy recognizes revenue as it fulfills its obligations to provide service to its customers. During the nine months ended September 30, 2020 and 2019, Eastern Energy recognized $1 million and $30 million, respectively, from the beginning contract liability balance.
15
Note 5. Income Taxes
For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Eastern Energy’s effective income tax rate as follows:
| | | | |
Nine Months Ended September 30, | | 2020 | | | 2019 | | |
U.S. statutory rate | | | 21.0 | % | | | 21.0 | % | |
Increases (reductions) resulting from: | | | | | | | | | |
State taxes, net of federal benefit | | | (10.4 | ) | | | 3.6 | | |
Reversal of excess deferred income taxes | | | (4.4 | ) | | | (0.9 | ) | |
Write-off of regulatory assets | | | 8.2 | | | | 0 | | |
Changes in tax status | | | (20.9 | ) | | | 0 | | |
AFUDC - equity | | | (1.7 | ) | | | (0.5 | ) | |
Absence of tax on noncontrolling interest | | | (17.9 | ) | | | (3.7 | ) | |
Other, net | | | (8.9 | ) | | | 0.2 | | |
Effective tax rate | | | (35.0 | )% | | | 19.7 | % | |
For Eastern Energy’s rate-regulated subsidiaries, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. Eastern Energy’s rate regulated subsidiaries have recorded an estimate of excess deferred income tax amortization in 2020. The reversal of these excess deferred income taxes will impact the effective tax rate and rates charged to customers. See Note 13 to the Consolidated Financial Statements in Eastern Energy’sGas' Annual Report on Form 10-K for the year ended December 31, 2019 for more information.
For2020 describes the nine months ended September 30, 2020, Eastern Energy’s effective tax rate is primarily a functionmost significant accounting policies used in the preparation of the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project as discussed in Note 2. In addition, the effective tax rate reflects an income tax benefit of $24 million associated with finalizing the effects of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring.
In March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act. The CARES Act provisions are intended to improve cash flow and liquidity by, among other things, providing a temporary five-year carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily loosening the business interest limitation to 50% of adjusted taxable income for certain businesses. While Eastern Energy intends to utilize the income tax provisions of the CARES Act where applicable, they are not expected to provide a material benefit.
In July 2020, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses and issued proposed regulations on the application of these rules to certain pass-through entities and partners in those entities under the 2017 Tax Reform Act as modified by the CARES Act. Eastern Energy is currently assessing the impact of these regulations, but expects interest expense to be deductible in 2020.
As of September 30, 2020, thereunaudited Consolidated Financial Statements. There have been no materialsignificant changes in unrecognized tax benefits. DominionEastern Energy will retain Eastern Energy’s existing unrecognized tax benefits in connection withGas' assumptions regarding significant accounting estimates and policies during the GT&S Transaction. See Note 5three-month period ended March 31, 2021.
(2) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions): | | | | | | | | | | | | | | | | | |
| | | As of |
| | | March 31, | | December 31, |
| Depreciable Life | | 2021 | | 2020 |
Utility Plant: | | | | | |
| | | | | |
Interstate natural gas pipeline assets | 24 - 43 years | | $ | 8,385 | | | $ | 8,382 | |
Intangible plant | 5 - 10 years | | 114 | | | 115 | |
Utility plant in service | | | 8,499 | | | 8,497 | |
Accumulated depreciation and amortization | | | (2,792) | | | (2,759) | |
Utility plant in service, net | | | 5,707 | | | 5,738 | |
| | | | | |
Nonutility Plant: | | | | | |
| | | | | |
LNG facility | 40 years | | 4,460 | | | 4,454 | |
Intangible plant | 14 years | | 25 | | | 25 | |
Nonutility plant in service | | | 4,485 | | | 4,479 | |
Accumulated depreciation and amortization | | | (320) | | | (283) | |
Nonutility plant in service, net | | | 4,165 | | | 4,196 | |
| | | | | |
Plant, net | | | 9,872 | | | 9,934 | |
Construction work- in-progress | | | 227 | | | 210 | |
Property, plant and equipment, net | | | $ | 10,099 | | | $ | 10,144 | |
Construction work-in-progress includes $211 million and $196 million as of March 31, 2021 and December 31, 2020, respectively, related to the
Consolidated Financial Statements in Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019, for a discussionconstruction of
these unrecognized tax benefits.16
utility plant.
Note 6. Accumulated Other Comprehensive Income
The following table presents Eastern Energy’s changes in AOCI by component, net of tax:
| | Deferred gains and losses on derivatives- hedging activities | | | Unrecognized pension costs | | | Total | |
(millions) | | | | | | | | | | | | |
Three Months Ended September 30, 2020 | | | | | | | | | | | | |
Beginning balance | | $ | (168 | ) | | $ | (103 | ) | | $ | (271 | ) |
Other comprehensive income before reclassifications: gains (losses) | | | 12 | | | | (4 | ) | | | 8 | |
Amounts reclassified from AOCI: (gains) losses(1) | | | 99 | | | | 0 | | | | 99 | |
Net current period other comprehensive income (loss) | | | 111 | | | | (4 | ) | | | 107 | |
Ending balance | | $ | (57 | ) | | $ | (107 | ) | | $ | (164 | ) |
Three Months Ended September 30, 2019 | | | | | | | | | | | | |
Beginning balance | | $ | (74 | ) | | $ | (112 | ) | | $ | (186 | ) |
Other comprehensive income before reclassifications: gains (losses) | | | (36 | ) | | | (1 | ) | | | (37 | ) |
Amounts reclassified from AOCI: (gains) losses(1) | | | 9 | | | | 1 | | | | 10 | |
Net current period other comprehensive income (loss) | | | (27 | ) | | | — | | | | (27 | ) |
Ending balance | | $ | (101 | ) | | $ | (112 | ) | | $ | (213 | ) |
Nine Months Ended September 30, 2020 | | | | | | | | | | | | |
Beginning balance | | $ | (81 | ) | | $ | (106 | ) | | $ | (187 | ) |
Other comprehensive income before reclassifications: gains (losses) | | | (79 | ) | | | (4 | ) | | | (83 | ) |
Amounts reclassified from AOCI: (gains) losses(1) | | | 103 | | | | 3 | | | | 106 | |
Net current period other comprehensive income (loss) | | | 24 | | | | (1 | ) | | | 23 | |
Ending balance | | $ | (57 | ) | | $ | (107 | ) | | $ | (164 | ) |
Nine Months Ended September 30, 2019 | | | | | | | | | | | | |
Beginning balance | | $ | (25 | ) | | $ | (144 | ) | | $ | (169 | ) |
Other comprehensive income before reclassifications: gains (losses) | | | (87 | ) | | | 28 | | | | (59 | ) |
Amounts reclassified from AOCI: (gains) losses(1) | | | 10 | | | | 4 | | | | 14 | |
Net current period other comprehensive income (loss) | | | (77 | ) | | | 32 | | | | (45 | ) |
Less other comprehensive income (loss) attributable to noncontrolling interest | | | (1 | ) | | | 0 | | | | (1 | ) |
Ending balance | | $ | (101 | ) | | $ | (112 | ) | | $ | (213 | ) |
(1)
| See table below for details about these reclassifications.
|
17
The following table presents Eastern Energy’s reclassifications out of AOCI by component:
Details about AOCI components | | Amounts reclassified from AOCI | | | Affected line item in the Consolidated Statements of Income |
(millions) | | | | | | |
Three Months Ended September 30, 2020 | | | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | | | |
Interest rate contracts | | $ | 145 | | | Interest and related charges |
Foreign currency contracts | | | (12 | ) | | Other income |
Total | | | 133 | | | |
Tax | | | (34 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 99 | | | |
Unrecognized pension and other postretirement benefit costs: | | | | | | |
Actuarial losses | | $ | 1 | | | Other income |
Total | | | 1 | | | |
Tax | | | (1 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 0 | | | |
Three Months Ended September 30, 2019 | | | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | | | |
Commodity contracts | | $ | (2 | ) | | Net income from discontinued operations |
Interest rate contracts | | | 2 | | | Interest and related charges |
Foreign currency contracts | | | 12 | | | Other income |
Total | | | 12 | | | |
Tax | | | (3 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 9 | | | |
Unrecognized pension and other postretirement benefit costs: | | | | | | |
Actuarial losses | | $ | 1 | | | Other income |
Total | | | 1 | | | |
Tax | | | 0 | | | Income tax expense (benefit) |
Total, net of tax | | $ | 1 | | | |
Nine Months Ended September 30, 2020 | | | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | | | |
Interest rate contracts | | $ | 151 | | | Interest and related charges |
Foreign currency contracts | | | (12 | ) | | Other income |
Total | | | 139 | | | |
Tax | | | (36 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 103 | | | |
Unrecognized pension and other postretirement benefit costs: | | | | | | |
Actuarial losses | | $ | 5 | | | Other income |
Total | | | 5 | | | |
Tax | | | (2 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 3 | | | |
Nine Months Ended September 30, 2019 | | | | | | |
Deferred (gains) and losses on derivatives-hedging activities: | | | | | | |
Commodity contracts | | $ | (4 | ) | | Net income from discontinued operations |
Interest rate contracts | | | 3 | | | Interest and related charges |
Foreign currency contracts | | | 14 | | | Other income |
Total | | | 13 | | | |
Tax | | | (3 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 10 | | | |
Unrecognized pension and other postretirement benefit costs: | | | | | | |
Actuarial losses | | $ | 5 | | | Other income |
Total | | | 5 | | | |
Tax | | | (1 | ) | | Income tax expense (benefit) |
Total, net of tax | | $ | 4 | | | |
18
Note 7. Fair Value Measurements
Eastern Energy’s fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in Eastern Energy’s Annual Report on Form 10-K for the year ended December 31, 2019. See Note 8 in this report for further information about Eastern Energy’s derivatives(3) Investments and hedge accounting activities. All of Eastern Energy’s derivatives are considered Level 2 in the fair value hierarchy.
Fair Value of Financial Instruments
Substantially all of Eastern Energy’s financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market informationRestricted Cash and valuation methodologies considered appropriate by management. The carrying amount of cash,Cash Equivalents