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 U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns a liquefied natural gas ("LNG") export, import and storage facility, in the U.S., an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the U.S. and one of the largest residential real estate brokerage franchise networks in the U.S. 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, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
Results of Operations for the First Quarter of 2022 and 2021
Overview
Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2022 | | 2021 | | Change | | | | | | |
Operating revenue: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 1,297 | | | $ | 1,242 | | | $ | 55 | | | 4 | % | | | | | | | | |
MidAmerican Funding | 1,005 | | | 1,067 | | | (62) | | | (6) | | | | | | | | | |
NV Energy | 693 | | | 591 | | | 102 | | | 17 | | | | | | | | | |
Northern Powergrid | 315 | | | 300 | | | 15 | | | 5 | | | | | | | | | |
BHE Pipeline Group | 1,035 | | | 1,093 | | | (58) | | | (5) | | | | | | | | | |
BHE Transmission | 183 | | | 180 | | | 3 | | | 2 | | | | | | | | | |
BHE Renewables | 167 | | | 190 | | | (23) | | | (12) | | | | | | | | | |
HomeServices | 1,207 | | | 1,232 | | | (25) | | | (2) | | | | | | | | | |
BHE and Other | 128 | | | 186 | | | (58) | | | (31) | | | | | | | | | |
Total operating revenue | $ | 6,030 | | | $ | 6,081 | | | $ | (51) | | | (1) | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Loss on common shares: | | | | | | | | | | | | | | | |
PacifiCorp | $ | 130 | | | $ | 169 | | | $ | (39) | | | (23) | % | | | | | | | | |
MidAmerican Funding | 241 | | | 144 | | | 97 | | | 67 | | | | | | | | | |
NV Energy | 29 | | | 34 | | | (5) | | | (15) | | | | | | | | | |
Northern Powergrid | 111 | | | 104 | | | 7 | | | 7 | | | | | | | | |
BHE Pipeline Group | 322 | | | 383 | | | (61) | | | (16) | | | | | | | | | |
BHE Transmission | 62 | | | 59 | | | 3 | | | 5 | | | | | | | | | |
BHE Renewables(1) | 104 | | | 16 | | | 88 | | | * | | | | | | | | |
HomeServices | 21 | | | 84 | | | (63) | | | (75) | | | | | | | | | |
BHE and Other | (1,165) | | | (1,027) | | | (138) | | | (13) | | | | | | | | | |
Total loss on common shares | $ | (145) | | | $ | (34) | | | $ | (111) | | | * | | | | | | | | |
(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 $111 million for the first quarter of 2022 compared to 2021. The first quarter of 2022 included a pre-tax unrealized loss of $1,247 million ($985 million after-tax) compared to a pre-tax unrealized loss in the first quarter of 2021 of $1,124 million ($818 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 2022 was $840 million, an increase of $56 million, or 7%, compared to adjusted earnings on common shares in the first quarter of 2021 of $784 million.
The decrease in earnings on common shares for the first quarter of 2022 compared to 2021 was primarily due to the following:
•The Utilities' earnings increased $53 million for the first quarter of 2022 compared to 2021, reflecting higher electric utility margin and favorable income tax expense from higher PTCs recognized, partially offset by higher depreciation and amortization expense and higher operations and maintenance expense. Electric retail customer volumes increased 3.4% for the first quarter of 2022 compared to 2021, primarily due to higher customer usage, an increase in the average number of customers and the favorable impact of weather;
•BHE Pipeline Group's earnings decreased $61 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings of $70 million at Northern Natural Gas from higher gross margin on gas sales and higher transportation revenue recognized in the first quarter of 2021 from the February 2021 polar vortex weather event, partially offset by favorable recurring transportation revenue due to higher volumes and rates;
•BHE Renewables' earnings increased $88 million for the first quarter of 2022 compared to 2021, primarily due to higher earnings on tax equity investments of $96 million as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event;
•HomeServices' earnings decreased $63 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings from mortgage services of $48 million, from a decrease in funded volume, and lower earnings from brokerage and settlement services of $16 million, largely attributable to a decrease in closed units at existing companies; and
•BHE and Other's earnings decreased $138 million for the first quarter of 2022 compared to 2021, mainly due to the $167 million unfavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited, partially offset by $21 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
Reportable Segment Results
PacifiCorp
Operating revenue increased $55 million for the first quarter of 2022 compared to 2021, primarily due to higher retail revenue of $40 million and higher wholesale and other revenue of $15 million. Retail revenue increased primarily due to higher retail volumes of $25 million and price impacts of $15 million from higher tariffs. Retail customer volumes increased 1.9%, primarily due to an increase in the average number of customers, the favorable impact of weather and higher customer usage. Wholesale and other revenue increased primarily due to higher average wholesale prices and higher wheeling revenue.
Earnings decreased $39 million for the first quarter of 2022 compared to 2021, primarily due to higher operations and maintenance expense of $18 million, higher depreciation and amortization expense of $16 million, from additional assets placed in-service, and increased income tax expense, partially offset by higher utility margin of $14 million. Operations and maintenance expense increased mainly due to higher thermal plant maintenance and higher costs associated with additional wind-powered generating facilities placed in-service. Utility margin increased primarily due to the higher retail, wholesale and other revenues and higher deferred net power costs in accordance with established adjustment mechanisms, partially offset by higher purchased power and thermal generation costs.
MidAmerican Funding
Operating revenue decreased $62 million for the first quarter of 2022 compared to 2021, primarily due to lower natural gas operating revenue of $116 million, partially offset by higher electric operating revenue of $63 million. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $134 million (fully offset in cost of sales), partially offset by the impacts of tax reform of $8 million, the impacts of certain regulatory recovery mechanisms of $7 million and the favorable impacts of weather of $4 million. Electric operating revenue increased due to higher wholesale and other revenue of $43 million and higher retail revenue of $20 million. Electric wholesale and other revenue increased mainly due to higher wholesale volumes of $24 million and higher average wholesale per-unit prices of $19 million. Electric retail revenue increased primarily due to higher customer volumes of $18 million and higher recoveries through adjustment clauses of $4 million (fully offset in expense, primarily cost of sales), partially offset by price impacts from changes in sales mix of $2 million. Electric retail customer volumes increased 5.6% due to higher customer usage and the favorable impact of weather.
Earnings increased $97 million for the first quarter of 2022 compared to 2021, primarily due to higher electric utility margin of $89 million, a favorable income tax benefit and higher natural gas utility margin of $18 million, partially offset by higher depreciation and amortization expense of $43 million and lower nonregulated utility margin of $9 million. Electric utility margin increased primarily due to the higher retail and wholesale revenues as well as lower purchased power costs. The favorable income tax benefit was largely due to higher PTCs recognized of $52 million, from new wind-powered generating facilities placed in-service, and the effects of ratemaking. Depreciation and amortization expense increased primarily from the impacts of certain regulatory mechanisms and additional assets placed in-service.
NV Energy
Operating revenue increased $102 million for the first quarter of 2022 compared to 2021, primarily due to higher electric operating revenue of $90 million and higher natural gas operating revenue of $13 million. Electric operating revenue increased primarily due to higher fully-bundled energy rates (fully offset in cost of sales) of $88 million, higher retail customer volumes of $4 million and higher transmission and wholesale revenue of $4 million, partially offset by lower regulatory-related revenue deferrals. Electric retail customer volumes increased 4.0%, primarily due to an increase in the average number of customers and higher customer usage, partially offset by the unfavorable impact of weather. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold (fully offset in cost of sales).
Earnings decreased $5 million for the first quarter of 2022 compared to 2021, mainly due to higher operations and maintenance expense of $6 million largely from increased plant operations and maintenance expenses and an unfavorable change in earnings sharing at the Nevada Utilities.
Northern Powergrid
Operating revenue increased $15 million for the first quarter of 2022 compared to 2021, primarily due to higher distribution revenue of $10 million, revenue from a gas project reaching commercial operation in March 2022 totaling $10 million and higher smart metering revenue of $6 million, partially offset by $9 million from the stronger U.S. dollar. Distribution revenue increased from higher tariff rates of $14 million, partially offset by a 2.6% decline in units distributed of $3 million.
Earnings increased $7 million for the first quarter of 2022 compared to 2021, primarily due to the higher distribution revenue, partially offset by $3 million from the stronger U.S. dollar.
BHE Pipeline Group
Operating revenue decreased $58 million for the first quarter of 2022 compared to 2021, primarily due to lower gas sales of $41 million related to system balancing activities at Northern Natural Gas, lower transportation revenue of $20 million at Northern Natural Gas and lower gas sales of $17 million at EGTS used for operational and system balancing purposes, partially offset by higher LNG variable revenue of $13 million at BHE GT&S and higher non-regulated revenue of $11 million at BHE GT&S. The variances in gas sales and transportation revenue at Northern Natural Gas included favorable impacts recognized in the first quarter of 2021 of $77 million and $49 million, respectively, from the February 2021 polar vortex weather event. Excluding this item, gas sales increased $36 million (largely offset in cost of sales) and transportation revenue increased $29 million due to higher volumes and rates.
Earnings decreased $61 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings of $70 million at Northern Natural Gas as the higher gross margin on gas sales and higher transportation revenue recognized in the first quarter of 2021 from the February 2021 polar vortex weather event were partially offset by the favorable transportation revenue due to higher volumes and rates.
BHE Transmission
Operating revenue increased $3 million for the first quarter of 2022 compared to 2021, mainly due to higher revenue at AltaLink from recovery of higher costs and from additional assets placed in-service.
Earnings increased $3 million for the first quarter of 2022 compared to 2021, mainly due to the additional assets placed in-service at AltaLink and improved equity earnings at Electric Transmission Texas, LLC.
BHE Renewables
Operating revenue decreased $23 million for the first quarter of 2022 compared to 2021, primarily due to unfavorable changes in the valuation of certain derivative contracts totaling $43 million and lower hydro revenues of $8 million due to the transfer of the Casecnan generating facility to the National Irrigation Administration in December 2021, partially offset by higher wind, solar and geothermal revenues of $27 million from higher generation and pricing.
Earnings increased $88 million for the first quarter 2022 compared to 2021, primarily due to higher wind earnings of $92 million and higher solar earnings of $6 million, largely due to the higher operating revenue, partially offset by lower hydro earnings of $10 million due to the Casecnan generating facility transfer. Wind earnings increased primarily due to higher earnings on tax equity investments of $96 million as a result of the unfavorable impacts recognized in the first quarter of 2021 from the February 2021 polar vortex weather event.
HomeServices
Operating revenue decreased $25 million for the first quarter of 2022 compared to 2021, primarily due to lower mortgage revenue of $97 million from a 41% decrease in funded volume due to lower refinance activity, partially offset by higher brokerage revenue of $78 million from a 9% increase in closed transaction volume. The increase in brokerage volume was due to acquisitions and an 11% increase in average sales price at existing companies offset by 12% fewer closed units at existing companies.
Earnings decreased $63 million for the first quarter of 2022 compared to 2021, primarily due to lower earnings from mortgage services of $48 million, from the decrease in funded volume, and lower earnings from brokerage and settlement services of $16 million, largely attributable to the decrease in closed units at existing companies.
BHE and Other
Operating revenue decreased $58 million for the first quarter of 2022 compared to 2021, primarily due to lower electricity sales revenue at MidAmerican Energy Services, LLC, from unfavorable pricing.
Earnings decreased $138 million for the first quarter of 2022 compared to 2021, primarily due to the $167 million unfavorable comparative change in the after-tax unrealized position of the Company's investment in BYD Company Limited and $54 million of lower federal income tax credits recognized on a consolidated basis, partially offset by higher earnings of $41 million at MidAmerican Energy Services, LLC, mainly due to favorable changes in unrealized positions on derivative contracts, lower corporate costs and $21 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway.
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, 2021 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2022, the Company's total net liquidity was as follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | BHE Pipeline | | |
| | | | | MidAmerican | | NV | | Northern | | BHE | | | | Group and | | |
| BHE | | PacifiCorp | | Funding | | Energy | | Powergrid | | Canada | | HomeServices | | Other | | Total |
| | | | | | | | | | | | | | | | | |
Cash and cash equivalents | $ | 163 | | | $ | 335 | | | $ | 132 | | | $ | 40 | | | $ | 75 | | | $ | 60 | | | $ | 363 | | | $ | 264 | | | $ | 1,432 | |
| | | | | | | | | | | | | | | | | |
Credit facilities | 3,500 | | | 1,200 | | | 1,509 | | | 650 | | | 263 | | | 860 | | | 3,300 | | | — | | | 11,282 | |
Less: | | | | | | | | | | | | | | | | | |
Short-term debt | (110) | | | — | | | — | | | (161) | | | — | | | (375) | | | (1,203) | | | — | | | (1,849) | |
Tax-exempt bond support and letters of credit | — | | | (218) | | | (370) | | | — | | | — | | | (1) | | | — | | | — | | | (589) | |
Net credit facilities | 3,390 | | | 982 | | | 1,139 | | | 489 | | | 263 | | | 484 | | | 2,097 | | | — | | | 8,844 | |
| | | | | | | | | | | | | | | | | |
Total net liquidity(1) | $ | 3,553 | | | $ | 1,317 | | | $ | 1,271 | | | $ | 529 | | | $ | 338 | | | $ | 544 | | | $ | 2,460 | | | $ | 264 | | | $ | 10,276 | |
Credit facilities: | | | | | | | | | | | | | | | | | |
Maturity dates | 2024 | | 2024 | | 2022, 2024 | | 2024 | | 2024 | | 2022, 2026 | | 2022, 2023, 2026 | | | | |
(1) Excludes $100 million of available liquidity under a delayed draw term loan at Nevada Power.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021 were $2.2 billion and $1.5 billion, respectively. The increase was primarily due to 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 selected and assumptions made for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021 were $(1.6) billion and $(1.4) billion, respectively. The change was primarily due to higher capital expenditures of $258 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2022 was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 million.
For a discussion of recent financing transactions, refer to Note 4 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, 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.
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.
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 |
| 2021 | | 2022 | | 2022 |
Capital expenditures by business: | | | | | |
PacifiCorp | $ | 439 | | | $ | 374 | | | $ | 2,359 | |
MidAmerican Funding | 298 | | | 459 | | | 2,013 | |
NV Energy | 167 | | | 272 | | | 1,282 | |
Northern Powergrid | 179 | | | 169 | | | 652 | |
BHE Pipeline Group | 102 | | | 205 | | | 1,243 | |
BHE Transmission | 77 | | | 47 | | | 191 | |
BHE Renewables | 18 | | | 19 | | | 184 | |
HomeServices | 8 | | | 12 | | | 60 | |
BHE and Other(1) | 7 | | | (4) | | | 13 | |
Total | $ | 1,295 | | | $ | 1,553 | | | $ | 7,997 | |
| | | | | | | | | | | | | | | | | |
| | | |
| | | |
| | | | | |
Capital expenditures by type: | | | | | |
Wind generation | $ | 97 | | | $ | 155 | | | $ | 990 | |
Electric distribution | 427 | | | 392 | | | 1,737 | |
Electric transmission | 157 | | | 258 | | | 1,820 | |
Natural gas transmission and storage | 85 | | | 103 | | | 982 | |
Solar generation | 4 | | | 51 | | | 220 | |
Other | 525 | | | 594 | | | 2,248 | |
Total | $ | 1,295 | | | $ | 1,553 | | | $ | 7,997 | |
(1)BHE and Other represents amounts related principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.
The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $3 million for the three-month period ended March 31, 2022. Planned spending for the construction of additional wind-powered generating facilities totals $142 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $120 million and $24 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $386 million for the remainder of 2022. 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 812 MWs of current repowering projects not in-service as of March 31, 2022, 511 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
◦Construction of wind-powered generating facilities at PacifiCorp totaling $3 million and $27 million for the three-month periods ended March 31, 2022 and 2021, respectively. Construction includes 516 MWs of new wind-powered generating facilities that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $109 million for the remainder of 2022. The energy production from the new wind-powered generating facilities placed in-service by the end of 2024 is expected to qualify for 60% of the federal PTCs available for 10 years once the equipment is placed in-service.
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $3 million and $1 million for the three-month periods ended March 31, 2022 and 2021, respectively. The repowered facilities are expected to be placed in-service in 2023 and 2024. Planned spending for acquiring and repowering generating facilities totals $18 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for repowering generating facilities totals $64 million for the remainder of 2022.
•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.
•Electric transmission includes both growth and operating expenditures. Growth expenditures include spending for the following:
◦PacifiCorp's transmission investment primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $95 million and $16 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $814 million for the remainder of 2022.
◦Nevada Utilities' Greenlink Nevada transmission expansion program. In this project, the company has received approval from the PUCN 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; 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 Robinson Summit substations. Expenditures for the expansion program and other growth projects totaled $30 million and $19 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026-2028 and other growth projects totals $166 million for the remainder of 2022.
◦Operating expenditures include spending for system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.
•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, spending for the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for asset modernization, pipeline integrity projects and natural gas transmission, storage and liquefied natural gas terminalling infrastructure needs to serve existing and expected demand.
•Solar generation includes growth expenditures, including spending for the following:
◦Construction of solar-powered generating facilities at MidAmerican Energy totaling 141 MWs of small- and utility-scale solar generation, with total spend of $44 million and $3 million for the three-month periods ended March 31, 2022 and 2021, respectively and planned spending of $96 million for the remainder of 2022.
◦Construction of a solar-powered generating facility at Nevada Power totaling $7 million for the three-month period ended March 31, 2022 and planned spending of $74 million for the remainder of 2022. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other capital expenditures includes both growth and operating expenditures, including spending for routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.
Other Renewable Investments
The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made no contributions for the three-month period ended March 31, 2022, and has commitments as of March 31, 2022, subject to satisfaction of certain specified conditions, to provide equity contributions of $356 million for the remainder of 2022 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. However, the Company expects to assign its rights and obligations under these equity capital contribution agreements, including any related funding commitments, to an entity affiliated through common ownership. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2021 other than the recent financing transactions previously discussed.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), 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 ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Regulatory Matters
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2021 and new regulatory matters occurring in 2022.
PacifiCorp
Oregon
In March 2022, PacifiCorp filed a general rate case requesting an overall rate change of $82 million, or 6.6%, to become effective January 1, 2023. A hearing in the rate case will be held in September 2022 with an order expected in December 2022.
Washington
In June 2021, PacifiCorp filed a power cost only rate case to update baseline net power costs for 2022. The proposed $13 million, or 3.7%, rate increase has a requested effective date of January 1, 2022. In November 2021, PacifiCorp reached a proposed settlement with most of the parties, which includes an agreement to adjust the PTC rate in base rates and apply a production factor and to include a net power cost update as part of the compliance filing. A hearing was held in January 2022 and the WUTC issued an order approving the settlement in March 2022. A compliance filing, reflecting a $43 million, or 12.2%, increase was filed in April 2022 with rates effective May 1, 2022.
NV Energy (Nevada Power and Sierra Pacific)
Senate Bill 448 ("SB 448")
SB 448 was signed into law on June 10, 2021. The legislation is intended to accelerate transmission development, renewable energy and storage, and accelerate transportation electrification within the state of Nevada. In September 2021, the Nevada Utilities filed an amendment to the 2021 Joint IRP for the approval of their Transmission Infrastructure for a Clean Energy Economy Plan that sets forth a plan for the construction of high-voltage transmission infrastructure, Greenlink North among others, that will be placed into service no later than December 31, 2028, and requires the IRP to include at least one scenario that uses sources of supply that will achieve certain reductions in carbon dioxide emissions. In September 2021, the Nevada Utilities filed an application for the approval of their Economic Recovery Transportation Electrification Plan to accelerate transportation electrification in the state of Nevada. The plan establishes requirements for the contents of the transportation electrification investment as well as requirements for review, cost recovery and monitoring. The plan covers an initial period beginning January 1, 2022 and ending on December 31, 2024. In November 2021, the PUCN issued an order granting the application and accepting the Economic Recovery Transportation Electrification Plan with some modifications. The PUCN opened rulemakings to address other regulations that resulted from SB 448. In February 2022, the PUCN adopted regulations regarding the Economic Development Electric Rate Rider Program to revise the discounted electric rates to ease the economic burden on small businesses who take advantage of the discounted rates under the tariff. The remaining two SB 448 rulemakings are ongoing.
ON Line Temporary Rider ("ONTR")
In October 2021, Sierra Pacific filed an application with the PUCN for approval of the ONTR with corresponding updates to its electric rate tariffs to authorize recovery of the One Nevada Transmission Line ("ON Line") regulatory asset being accumulated as a result of the ON Line cost reallocation as well as the related on-going reallocated revenue requirement. Sierra Pacific's application would have, if approved by the PUCN as filed, resulted in a one-time rate increase of $28 million to be collected over a nine-month period starting on April 1, 2022. In March 2022, the PUCN issued an order directing Sierra Pacific to recover $14 million of the ON Line regulatory asset as a one-time rate increase collectable over a nine-month period effective April 1, 2022, with the expected remaining balance at December 31, 2022 to be included in rate base in the 2022 regulatory rate review for inclusion in the rates set in that case.
Merger Application
In March 2022, the Nevada Utilities filed a joint application with the PUCN for authorization to merge Sierra Pacific with and into Nevada Power, with Nevada Power being the surviving entity. If approved by the PUCN as filed, Nevada Power will have two distinct electric service territories in northern and southern Nevada each with their own rates and one natural gas service territory in the Reno and Sparks area. An order is expected in 2022.
BHE Pipeline Group
BHE GT&S
In September 2021, EGTS filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.
BHE Transmission
AltaLink
2022-2023 General Tariff Application
In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs by continuing to transition to the AUC-approved salvage recovery method and continuing the use of the flow-through income tax method, with an overall year-over-year increase of approximately 2% in 2022 and 2023 revenue requirements. In addition, similar to the refund of previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariffs of C$824 million and C$847 million for 2022 and 2023, respectively.
In September 2021, AltaLink provided responses to information requests from the AUC and filed an amended application to reflect certain adjustments and forecast updates. The amended application requested the approval of transmission tariffs of C$820 million and C$843 million for 2022 and 2023, respectively. In November 2021, the AUC approved the 2022 interim refundable transmission tariff at C$57 million per month effective January 2022.
In January 2022, the AUC issued its decision with respect to AltaLink's 2022-2023 GTA. The AUC approved a two-year total revenue requirement of C$1.7 billion as compared to AltaLink's requested revenue requirement of C$1.8 billion. AltaLink's 2022-2023 GTA reflected its continued commitment to provide rate stability to customers by maintaining flat tariffs and providing additional tariff relief measures, including a proposed tariff refund of C$60 million of accumulated depreciation in each of 2022 and 2023. The AUC did not approve AltaLink's proposed refund due to an anticipated improvement in general economic conditions in Alberta.
In March 2022, AltaLink filed a review and variance application with the AUC. The application requested the AUC to review and vary its decision to deny AltaLink's proposed C$120 million refund of accumulated depreciation surplus, given material changes in circumstances since the decision was issued in January 2022. The existing pressures on Albertans and Alberta businesses that resulted from the COVID-19 pandemic have been compounded by cost increases due to higher inflation and global supply chain disruptions.
2023 Generic Cost of Capital Proceeding
In January 2022, the AUC initiated the 2023 generic cost of capital proceeding. The proceeding will be conducted in two stages. The first stage will determine the cost of capital parameters for 2023 and the second stage will consider returning to a formula-based approach to establish cost of capital adjustments, commencing in 2024. In March 2022, the AUC issued its decision with respect to the first stage of the 2023 GCOC proceeding by approving the extension of the 2022 return on equity of 8.5% and deemed equity ratio of 37% for 2023, recognizing lingering uncertainty and continued volatility of financial markets due to the COVID-19 pandemic. With respect to the second stage, the AUC plans to commence the 2024 GCOC proceeding to establish a formula-based approach in the third quarter of 2022 and to conclude in the second quarter of 2023.
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 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, 2021, and new environmental matters occurring in 2022.
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 are described below.
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.
On June 4, 2018, the EPA published final ozone designations for much of the U.S. Relevant to the Registrants, these designations include classifying Yuma County, Arizona; Clark County, Nevada; and the Northern Wasatch Front, Southern Wasatch Front and Duchesne and Uintah counties in Utah as nonattainment-marginal with the 2015 ozone standard. These areas were required to meet the 2015 standard three years from the August 3, 2018, effective date. All other areas relevant to the Registrants were designated attainment/unclassifiable with this same action. However, on January 29, 2021, the D.C. Circuit vacated several provisions of the 2018 implementing rules for the 2015 ozone standards for contravening the Clean Air Act. The EPA and environmental groups finalized a consent decree in January 2022 that sets deadlines for the agency to approve or disapprove the "good neighbor" provisions of interstate ozone plans of dozens of states. Relevant to the Registrants, the EPA must, by April 30, 2022, propose to approve or disapprove the interstate ozone SIPs of Alabama, Iowa, Maryland, Michigan, Minnesota, New York, Ohio, Pennsylvania, Texas, West Virginia and Wisconsin. On February 22, 2022, the EPA published a series of proposed decisions to disapprove the SIPs for interstate ozone transport of 19 states. Relevant to the Registrants, these states include Alabama, Maryland, Michigan, Minnesota, New York, Ohio, West Virginia and Wisconsin. The EPA also proposed to approve Iowa's SIP after re-analyzing the state's data. The EPA must finalize the proposed rules by December 15, 2022. In addition, the EPA must, by December 15, 2022, approve or disapprove the interstate plans of Arizona, California, Nevada and Wyoming. On April 15, 2022, the EPA issued its final rule approving Iowa's SIP as meeting the good neighbor provisions for the 2015 ozone standard. Until the EPA takes final action consistent with this decree, additional impacts to the relevant Registrants cannot be determined.
Separately, on March 28, 2022, the EPA proposed determinations as to whether certain areas have achieved levels of ground-level ozone pollution that meet the 2008 and 2015 ozone NAAQS, respectively. Relevant to the Registrants, the Southern Wasatch Front in Utah and Yuma, Arizona are proposed to have met the 2015 ozone standard; and the Cincinnati area of Ohio and Kentucky and the Northern Wasatch Front in Utah are proposed to have not met the 2015 ozone, will be reclassified as Moderate Non-Attainment, and will have until August 3, 2024 to meet the standard. Until the EPA takes final action on the proposal and the affected states submit any required SIPs, the relevant Registrants cannot determine the impacts of the proposed rule.
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 U.S., 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, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. The 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 U.S. 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 generating facilities 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 generating facilities 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 Rule largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule. In June 2021, a new lawsuit was filed that challenges the Revised CSAPR Update Rule. Litigation is ongoing in the D.C. Circuit Court. Until litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
In March 2022, the EPA released its Good Neighbor Rule, which contains proposed revisions to the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. The rule focuses on reductions of NOx, precursors to ozone formation and covers 26 states. Relevant to the Registrants, four states are included in the cross-state program for the first time - California, Nevada, Utah and Wyoming. Iowa is not included in the proposal. In a separate but related action in February 2022, the EPA proposed to approve the good neighbor provisions of Iowa's SIP addressing ozone transport and the 2015 ozone standard. The EPA proposes to retain emissions allowance trading for generating facilities. Beginning in 2023, emissions budgets would be set at the level of reductions achievable through immediately available measures such as consistently operating existing emissions controls. Starting in 2026, emissions budgets would be set at levels achievable by the installation of SCR controls at certain generating facilities. The proposal also includes additional industries beyond the power sector for the first time, with a focus on the top NOx emitting stationary source categories. These include natural gas pipeline compressor stations, pulp and paper mills, cement production, iron and steel boilers and furnaces, glass furnaces, chemical manufacturing and petroleum and coal product manufacturing. These sources will not have access to trading and will instead be subject to rate-based limits that are assigned for each source category. The EPA is accepting comments on the proposal through June 6, 2022. Until the EPA takes final action consistent with this decree, impacts to the relevant Registrants cannot be determined.
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 equipment at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. The EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a FIP requiring the installation of SCR equipment 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 generating facility enforceable under the SIP and removes the requirement to install SCR equipment 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 generating facility federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington generating facilities. The proposed approval withdraws the FIP requirements to install SCR equipment 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 generating facilities. 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. After review of the rule by the Biden administration, the EPA determined it would defend the rule, and briefing in the case is ongoing. A date for oral arguments has not been scheduled. The Utah Air Quality Board approved the Utah Division of Air Quality's SIP for the regional haze second planning period on April 6, 2022. The public comment period is anticipated to begin in early May 2022. The proposed plan sets mass-based emissions limits for PacifiCorp's Hunter and Huntington generating facilities to ensure reasonable visibility progress for the second planning period. The division proposes to add existing SO2 emission limits for all five Hunter and Huntington units as enforceable regional haze controls. The division also proposes new enforceable mass-based NOx emission limits for both generating facilities based on actual emissions. The state is on track to submit a final implementation plan to the EPA by July 2022.
The state of Wyoming issued two regional haze SIPs requiring the installation of SO2, NOx and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the SO2 SIP in December 2012 and the EPA's approval was upheld on appeal by the Tenth Circuit in October 2014. In addition, the EPA initially proposed in June 2012 to disapprove portions of the NOx and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the NOx and particulate matter SIP and the proposed FIP, published a re-proposed rule in June 2013, and finalized its determination in January 2014, which aligns more closely with the SIP proposed by the state of Wyoming. The EPA's final action on the Wyoming SIP approved the state's plan to have PacifiCorp install low-NOx burners at Naughton Units 1 and 2, SCR controls at Naughton Unit 3 by December 2014, SCR controls at Jim Bridger Units 1 through 4 between 2015 and 2022, and low-NOx burners at Dave Johnston Unit 4. The EPA disapproved a portion of the Wyoming SIP and issued a FIP for Dave Johnston Unit 3, where it required the installation of SCR controls by 2019 or, in lieu of installing SCR controls, a commitment to shut down Dave Johnston Unit 3 by 2027, its currently approved depreciable life. The EPA also disapproved a portion of the Wyoming SIP and issued a FIP for the Wyodak coal-fueled generating facility, requiring the installation of SCR controls within five years (i.e., by 2019). The EPA action became final on March 3, 2014. PacifiCorp filed an appeal of the EPA's final action on Wyodak in March 2014. The state of Wyoming also filed an appeal of the EPA's final action, as did the Powder River Basin Resource Council, National Parks Conservation Association and Sierra Club. In September 2014, the Tenth Circuit issued a stay of the March 2019 compliance deadline for Wyodak, pending further action by the Tenth Circuit in the appeal. The EPA, U.S. Department of Justice, state of Wyoming and PacifiCorp executed a settlement agreement December 16, 2020, removing the requirement to install SCR in lieu of monthly and annual NOx emissions limits. The settlement agreement was subject to a comment period which ended July 6, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement. The EPA did not proceed with final approval of the settlement agreement for Wyodak and is currently engaged with Wyoming and PacifiCorp concerning alternative paths for resolution. On February 5, 2019, PacifiCorp submitted a reasonable progress reassessment permit application and reasonable progress determination for Jim Bridger Units 1 and 2, seeking a rescission of the December 2017 permit requiring the installation of SCR, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. In May 2020, the Wyoming Air Quality Division issued a permit approving PacifiCorp's monthly and annual NOx and SO2 emission limits on the four Jim Bridger units and submitted a regional haze SIP revision to the EPA. The revised SIP would grant approval of PacifiCorp's Jim Bridger reasonable progress reassessment application and incorporates PacifiCorp's proposed emission limits in lieu of the requirement to install SCR systems on Jim Bridger Units 1 and 2. On December 27, 2021, Wyoming's governor issued an emergency suspension order under Section 110(g) of the Clean Air Act, allowing the operation of Jim Bridger Unit 2 through April 30, 2022, while the state, the EPA and PacifiCorp continue settlement discussions. On January 18, 2022, the EPA proposed to reject the SIP revisions. The EPA took comment on the proposal through February 17, 2022. On February 14, 2022, the First Judicial District Court for the State of Wyoming entered a consent decree reached between the state of Wyoming and PacifiCorp under Sections 201 and 209(a) of the Wyoming Environmental Quality Act, resolving claims of threatened violations of the Clean Air Act, the Wyoming Environmental Quality Act and the Wyoming Air Quality Standards and Regulations at the Jim Bridger facility. No penalties were imposed under the consent decree. Consistent with the terms and conditions of the consent decree and as forecasted in PacifiCorp's 2021 IRP, PacifiCorp must convert both units to natural gas and begin meeting emissions limits consistent with that conversion by January 1, 2024. In addition, PacifiCorp must propose an RFP by January 1, 2023, for carbon capture technology at Jim Bridger Units 3 and 4. Wyoming issued its proposed implementation plan for second planning period reasonable progress on February 18, 2022 and accepted comments through March 23, 2022. Wyoming determined that no controls will be necessary on any Wyoming resources to make reasonable progress for the second round of regional haze planning. It is estimated that the state will submit a final state-approved implementation plan to the EPA in May 2022.
In February 2022, NV Energy received 30-day notice letters from the Nevada Division of Environmental Protection regarding the reopening and revision of the Valmy and Tracy Generating Station's Title V air quality operating permits to add federally enforceable retirement dates of December 31, 2028 for Valmy Units 1 and 2 and December 31, 2031 for Tracy Unit 4. The enforceable retirement dates will implement Nevada's SIP for the regional haze second planning period. The revised permits were received in March and April 2022. It is anticipated that the Nevada Division of Environmental Protection will begin the public comment period for its SIP by May 2022 and submit the final SIP to the EPA by June 2022.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, impairment of goodwill and long-lived assets, 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, 2021. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2021.
PacifiCorp and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | | | | |
| | As of |
| | March 31, | | December 31, |
| | 2022 | | 2021 |
ASSETS |
Current assets: | | | | |
Cash and cash equivalents | | $ | 335 | | | $ | 179 | |
Trade receivables, net | | 674 | | | 725 | |
Other receivables, net | | 49 | | | 52 | |
Inventories | | 479 | | | 474 | |
Derivative contracts | | 145 | | | 76 | |
| | | | |
Regulatory assets | | 125 | | | 65 | |
| | | | |
Other current assets | | 163 | | | 150 | |
Total current assets | | 1,970 | | | 1,721 | |
| | | | |
Property, plant and equipment, net | | 23,081 | | | 22,914 | |
Regulatory assets | | 1,231 | | | 1,287 | |
Other assets | | 562 | | | 534 | |
| | | | |
Total assets | | $ | 26,844 | | | $ | 26,456 | |
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, |
| | 2022 | | 2021 |
LIABILITIES AND SHAREHOLDERS' EQUITY |
Current liabilities: | | | | |
Accounts payable | | $ | 724 | | | $ | 680 | |
Accrued interest | | 115 | | | 121 | |
Accrued property, income and other taxes | | 113 | | | 78 | |
| | | | |
Accrued employee expenses | | 109 | | | 89 | |
| | | | |
Current portion of long-term debt | | 155 | | | 155 | |
Regulatory liabilities | | 114 | | | 118 | |
Other current liabilities | | 196 | | | 219 | |
Total current liabilities | | 1,526 | | | 1,460 | |
| | | | |
Long-term debt | | 8,567 | | | 8,575 | |
Regulatory liabilities | | 2,807 | | | 2,650 | |
Deferred income taxes | | 2,886 | | | 2,847 | |
Other long-term liabilities | | 1,014 | | | 1,011 | |
Total liabilities | | 16,800 | | | 16,543 | |
| | | | |
Commitments and contingencies (Note 8) | | | | |
| | | | |
Shareholders' equity: | | | | |
Preferred stock | | 2 | | | 2 | |
Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding | | — | | | — | |
Additional paid-in capital | | 4,479 | | | 4,479 | |
Retained earnings | | 5,579 | | | 5,449 | |
Accumulated other comprehensive loss, net | | (16) | | | (17) | |
Total shareholders' equity | | 10,044 | | | 9,913 | |
| | | | |
Total liabilities and shareholders' equity | | $ | 26,844 | | | $ | 26,456 | |
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, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Operating revenue | | | | | $ | 1,297 | | | $ | 1,242 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 465 | | | 424 | |
Operations and maintenance | | | | | 277 | | | 259 | |
Depreciation and amortization | | | | | 280 | | | 264 | |
Property and other taxes | | | | | 59 | | | 61 | |
Total operating expenses | | | | | 1,081 | | | 1,008 | |
| | | | | | | |
Operating income | | | | | 216 | | | 234 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (106) | | | (107) | |
Allowance for borrowed funds | | | | | 6 | | | 6 | |
Allowance for equity funds | | | | | 13 | | | 13 | |
Interest and dividend income | | | | | 7 | | | 6 | |
Other, net | | | | | (4) | | | 6 | |
Total other income (expense) | | | | | (84) | | | (76) | |
| | | | | | | |
Income before income tax expense (benefit) | | | | | 132 | | | 158 | |
Income tax expense (benefit) | | | | | 2 | | | (11) | |
Net income | | | | | $ | 130 | | | $ | 169 | |
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, 2020 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,711 | | | $ | (19) | | | $ | 9,173 | |
Net income | | — | | | — | | | — | | | 169 | | | — | | | 169 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 4,880 | | | $ | (19) | | | $ | 9,342 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,449 | | | $ | (17) | | | $ | 9,913 | |
Net income | | — | | | — | | | — | | | 130 | | | — | | | 130 | |
Other comprehensive income | | — | | | — | | | — | | | — | | | 1 | | | 1 | |
| | | | | | | | | | | | |
Balance, March 31, 2022 | | $ | 2 | | | $ | — | | | $ | 4,479 | | | $ | 5,579 | | | $ | (16) | | | $ | 10,044 | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net income | $ | 130 | | | $ | 169 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 280 | | | 264 | |
Allowance for equity funds | (13) | | | (13) | |
Changes in regulatory assets and liabilities | (9) | | | (4) | |
Deferred income taxes and amortization of investment tax credits | 19 | | | 13 | |
Other, net | 4 | | | (2) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables, other receivables and other assets | 59 | | | 61 | |
Inventories | (5) | | | 7 | |
Derivative collateral, net | 22 | | | 7 | |
Prepaid expenses | — | | | 6 | |
Accrued property, income and other taxes, net | 15 | | | 12 | |
Accounts payable and other liabilities | 35 | | | (51) | |
Net cash flows from operating activities | 537 | | | 469 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (374) | | | (439) | |
Other, net | 3 | | | (1) | |
Net cash flows from investing activities | (371) | | | (440) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Repayments of long-term debt | (9) | | | — | |
Net proceeds from short-term debt | — | | | 2 | |
| | | |
| | | |
Other, net | (2) | | | (1) | |
Net cash flows from financing activities | (11) | | | 1 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 155 | | | 30 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 186 | | | 19 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 341 | | | $ | 49 | |
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 U.S. 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, 2022 and for the three-month periods ended March 31, 2022 and 2021. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month periods ended March 31, 2022 and 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 PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021 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, 2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 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, |
| 2022 | | 2021 |
Cash and cash equivalents | $ | 335 | | | $ | 179 | |
Restricted cash and cash equivalents included in other current assets | 4 | | | 4 | |
Restricted cash included in other assets | 2 | | | 3 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 341 | | | $ | 186 | |
(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 | | 2022 | | 2021 |
Utility Plant: | | | | | |
Generation | 15 - 59 years | | $ | 13,688 | | | $ | 13,679 | |
Transmission | 60 - 90 years | | 7,914 | | | 7,894 | |
Distribution | 20 - 75 years | | 8,125 | | | 8,044 | |
Intangible plant(1) | 5 - 75 years | | 1,112 | | | 1,106 | |
Other | 5 - 60 years | | 1,563 | | | 1,539 | |
Utility plant in-service | | | 32,402 | | | 32,262 | |
Accumulated depreciation and amortization | | | (10,704) | | | (10,507) | |
Utility plant in-service, net | | | 21,698 | | | 21,755 | |
Other non-regulated, net of accumulated depreciation and amortization | 14 - 95 years | | 18 | | | 18 | |
Plant, net | | | 21,716 | | | 21,773 | |
Construction work-in-progress | | | 1,365 | | | 1,141 | |
Property, plant and equipment, net | | | $ | 23,081 | | | $ | 22,914 | |
(1)Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.
(4) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax (benefit) expense is as follows:
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | | | | | 3 | | | 3 | |
Federal income tax credits | | | | | (20) | | | (20) | |
Effects of ratemaking(1) | | | | | (11) | | | (13) | |
| | | | | | | |
Valuation allowance | | | | | 6 | | | — | |
Other | | | | | 3 | | | 2 | |
Effective income tax rate | | | | | 2 | % | | (7) | % |
(1)Effects of ratemaking is primarily attributable to activity associated with excess deferred income taxes.
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. PTCs for the three-month periods ended March 31, 2022 and 2021 totaled $26 million and $31 million, respectively.
For the three-month period ended March 31, 2022 PacifiCorp recorded a valuation allowance related to state net operating loss carryforwards.
(5) Employee Benefit Plans
Net periodic benefit cost (credit) for the pension and other postretirement benefit plans included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
Pension: | | | | | | | |
Service cost | | | | | $ | — | | | $ | — | |
Interest cost | | | | | 7 | | | 7 | |
Expected return on plan assets | | | | | (10) | | | (13) | |
| | | | | | | |
Net amortization | | | | | 4 | | | 5 | |
Net periodic benefit cost (credit) | | | | | $ | 1 | | | $ | (1) | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | | | | | $ | — | | | $ | — | |
Interest cost | | | | | 2 | | | 2 | |
Expected return on plan assets | | | | | (2) | | | (2) | |
Net amortization | | | | | — | | | — | |
Net periodic benefit cost (credit) | | | | | $ | — | | | $ | — | |
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 $— million, respectively, during 2022. As of March 31, 2022, $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, assess, manage and report on 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, futures, 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):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Derivative | | | | | | | | |
| Contracts - | | | | Other | | Other | | |
| Current | | Other | | Current | | Long-term | | |
| Assets | | Assets | | Liabilities | | Liabilities | | Total |
As of March 31, 2022 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 165 | | | $ | 37 | | | $ | 6 | | | $ | (1) | | | $ | 207 | |
Commodity liabilities | (3) | | | — | | | (9) | | | — | | | (12) | |
Total | 162 | | | 37 | | | (3) | | | (1) | | | 195 | |
| | | | | | | | | |
Total derivatives | 162 | | | 37 | | | (3) | | | (1) | | | 195 | |
Cash collateral payable | (17) | | | — | | | — | | | — | | | (17) | |
Total derivatives - net basis | $ | 145 | | | $ | 37 | | | $ | (3) | | | $ | (1) | | | $ | 178 | |
| | | | | | | | | |
As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 81 | | | $ | 21 | | | $ | 2 | | | $ | — | | | $ | 104 | |
Commodity liabilities | (5) | | | (1) | | | (38) | | | (7) | | | (51) | |
Total | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
| | | | | | | | | |
Total derivatives | 76 | | | 20 | | | (36) | | | (7) | | | 53 | |
Cash collateral receivable | — | | | — | | | 5 | | | — | | | 5 | |
Total derivatives - net basis | $ | 76 | | | $ | 20 | | | $ | (31) | | | $ | (7) | | | $ | 58 | |
(1)PacifiCorp's commodity derivatives are generally included in rates. As of March 31, 2022 a regulatory liability of $195 million was recorded related to the net derivative asset of $195 million. As of December 31, 2021 a regulatory liability of $53 million was recorded related to the net derivative asset of $53 million.
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, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Beginning balance | | | | | $ | (53) | | | $ | 17 | |
Changes in fair value recognized in regulatory assets | | | | | (168) | | | (17) | |
Net losses reclassified to operating revenue | | | | | (3) | | | — | |
Net gains reclassified to energy costs | | | | | 29 | | | — | |
Ending balance | | | | | $ | (195) | | | $ | — | |
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 | | 2022 | | 2021 |
| | | | | |
Electricity purchases, net | Megawatt hours | | 1 | | | 2 | |
Natural gas purchases | Decatherms | | 105 | | | 106 | |
| | | | | |
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, 2022, 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 $10 million and $37 million as of March 31, 2022 and December 31, 2021, respectively, for which PacifiCorp had posted collateral of $— million and $5 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, 2022 and December 31, 2021, PacifiCorp would have been required to post $2 million and $23 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 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, 2022: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 207 | | | $ | — | | | $ | (25) | | | $ | 182 | |
Money market mutual funds | 319 | | | — | | | — | | | — | | | 319 | |
Investment funds | 28 | | | — | | | — | | | — | | | 28 | |
| $ | 347 | | | $ | 207 | | | $ | — | | | $ | (25) | | | $ | 529 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (12) | | | $ | — | | | $ | 8 | | | $ | (4) | |
| | | | | | | | | |
As of December 31, 2021: | | | | | | | | | |
Assets: | | | | | | | | | |
Commodity derivatives | $ | — | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 96 | |
Money market mutual funds | 181 | | | — | | | — | | | — | | | 181 | |
Investment funds | 27 | | | — | | | — | | | — | | | 27 | |
| $ | 208 | | | $ | 104 | | | $ | — | | | $ | (8) | | | $ | 304 | |
| | | | | | | | | |
Liabilities - Commodity derivatives | $ | — | | | $ | (51) | | | $ | — | | | $ | 13 | | | $ | (38) | |
(1)Represents netting under master netting arrangements and a net cash collateral payable of $17 million and a net cash collateral receivable of $5 million as of March 31, 2022 and December 31, 2021, respectively.
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, 2022 | | As of December 31, 2021 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 8,722 | | | $ | 9,423 | | | $ | 8,730 | | | $ | 10,374 | |
(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, real and personal property and natural resource damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California (the "2020 Wildfires"). 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 destroyed, including residences; 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.
Multiple 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. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. 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 real and personal property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.
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, real and personal property damage, personal injury damages and loss of life damages, but exclude estimated potential losses for natural resource damage as PacifiCorp is unable to reasonably estimate such losses at this time. 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 variation in those types of properties and lack of available details. 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 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. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions. In June 2021, the FERC approved transfer of the four mainstem Klamath dams from PacifiCorp to the KRRC and the States as co-licensees. In July 2021, the Oregon, Wyoming, Idaho and California state public utility commissions conditionally approved the required property transfer applications. In August 2021, PacifiCorp notified the Public Service Commission of Utah of the property transfer, however no formal approval is required in Utah. The transfer will be effective within 30 days following the issuance of a license surrender from the FERC for the project, which remains pending. In February 2022, the FERC staff issued a draft environmental impact statement for the project, concluding that dam removal is the preferred alternative. Comments on the draft were due in April 2022, and a final environmental impact statement is expected later in 2022.
Guarantees
PacifiCorp has entered into guarantees as part of the normal course of business and the sale or transfer 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 line of business, with further disaggregation of retail by customer class (in millions):
| | | | | | | | | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | | | | | $ | 505 | | | $ | 483 | |
Commercial | | | | | 370 | | | 359 | |
Industrial | | | | | 273 | | | 271 | |
Other retail | | | | | 37 | | | 32 | |
Total retail | | | | | 1,185 | | | 1,145 | |
Wholesale | | | | | 55 | | | 36 | |
Transmission | | | | | 32 | | | 25 | |
Other Customer Revenue | | | | | 20 | | | 23 | |
Total Customer Revenue | | | | | 1,292 | | | 1,229 | |
Other revenue | | | | | 5 | | | 13 | |
Total operating revenue | | | | | $ | 1,297 | | | $ | 1,242 | |
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 2022 and 2021
Overview
Net income for the first quarter of 2022 was $130 million, a decrease of $39 million, or 23%, compared to 2021. Net income decreased primarily due to higher operations and maintenance expense, higher depreciation and amortization expense, higher income tax expense and higher other expense, partially offset by higher utility margin. Utility margin increased primarily due to higher retail revenue from higher volumes and higher average prices, higher average wholesale market prices, lower coal-fueled generation volumes and higher net power cost deferrals, partially offset by higher purchased electricity prices and volumes and higher natural gas-fueled generation prices and volumes. Retail customer volumes increased 1.9%, primarily due to an increase in the average number of customers, favorable impacts of weather and an increase in customer usage. Energy generated was essentially flat for the first quarter of 2022 compared to 2021. Wholesale electricity sales volumes decreased 2% and purchased electricity volumes increased 6%.
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 | | |
| 2022 | | 2021 | | Change | | | | | | |
Utility margin: | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,297 | | | $ | 1,242 | | | $ | 55 | | | 4 | % | | | | | | | | |
Cost of fuel and energy | 465 | | | 424 | | | 41 | | | 10 | | | | | | | | | |
Utility margin | 832 | | | 818 | | | 14 | | | 2 | | | | | | | | | |
Operations and maintenance | 277 | | | 259 | | | 18 | | | 7 | | | | | | | | | |
Depreciation and amortization | 280 | | | 264 | | | 16 | | | 6 | | | | | | | | | |
Property and other taxes | 59 | | | 61 | | | (2) | | | (3) | | | | | | | | | |
Operating income | $ | 216 | | | $ | 234 | | | $ | (18) | | | (8) | % | | | | | | | | |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter | | |
| 2022 | | 2021 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | $ | 1,297 | | | $ | 1,242 | | | $ | 55 | | | 4 | % | | | | | | | | |
Cost of fuel and energy | 465 | | | 424 | | | 41 | | | 10 | | | | | | | | | |
Utility margin | $ | 832 | | | $ | 818 | | | $ | 14 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | 4,764 | | | 4,632 | | | 132 | | | 3 | % | | | | | | | | |
Commercial | 4,550 | | | 4,470 | | | 80 | | | 2 | | | | | | | | | |
Industrial, irrigation and other | 4,523 | | | 4,474 | | | 49 | | | 1 | | | | | | | | | |
Total retail | 13,837 | | | 13,576 | | | 261 | | | 2 | | | | | | | | | |
Wholesale | 1,553 | | | 1,591 | | | (38) | | | (2) | | | | | | | | | |
Total sales | 15,390 | | | 15,167 | | | 223 | | | 1 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | 2,025 | | | 1,989 | | | 36 | | | 2 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | $ | 85.46 | | | $ | 84.15 | | | $ | 1.31 | | | 2 | % | | | | | | | | |
Wholesale | $ | 39.12 | | | $ | 30.89 | | | $ | 8.23 | | | 27 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Heating degree days | 4,745 | | | 4,687 | | | 58 | | | 1 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Cooling degree days | 5 | | | — | | | 5 | | | N/A | | | | | | | | |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Coal | 6,911 | | | 7,644 | | | (733) | | | (10) | % | | | | | | | | |
Natural gas | 3,115 | | | 3,065 | | | 50 | | | 2 | | | | | | | | | |
Wind(2) | 2,392 | | | 1,738 | | | 654 | | | 38 | | | | | | | | | |
Hydroelectric and other(2) | 984 | | | 988 | | | (4) | | | — | | | | | | | | | |
Total energy generated | 13,402 | | | 13,435 | | | (33) | | | — | | | | | | | | | |
Energy purchased | 3,223 | | | 3,028 | | | 195 | | | 6 | | | | | | | | | |
Total | 16,625 | | | 16,463 | | | 162 | | | 1 | % | | | | | | | | |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | $ | 18.83 | | | $ | 17.66 | | | $ | 1.17 | | | 7 | % | | | | | | | | |
Energy purchased | $ | 55.49 | | | $ | 47.13 | | | $ | 8.36 | | | 18 | % | | | | | | | | |
(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 Renewable Energy Credits 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, 2022 compared to Quarter Ended March 31, 2021
Utility margin increased $14 million, or 2%, for the first quarter of 2022 compared to 2021 primarily due to:
•$40 million increase in retail revenue due to higher volumes and higher average prices. Retail customer volumes increased 1.9%, primarily due to an increase in the average number of customers, favorable impacts of weather and an increase in customer usage;
•$12 million increase in wholesale revenue due to higher average market prices, partially offset by lower volumes;
•$12 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher average prices;
•$8 million of higher deferred net power costs in accordance with established adjustment mechanisms; and
•$8 million of favorable wheeling activities.
The increases above were partially offset by:
•$36 million of higher purchased electricity costs from higher average market prices and volumes; and
•$27 million of higher natural gas-fueled generation costs due to higher average prices and higher volumes.
Operations and maintenance increased $18 million, or 7%, for the first quarter of 2022 compared to 2021 primarily due to higher maintenance costs, higher DSM amortization of regulatory balances, and higher insurance premiums due to cost increases related to wildfire coverage, partially offset by lower labor expenses and lower vegetation management costs.
Depreciation and amortization increased $16 million, or 6%, for the first quarter of 2022 compared to 2021 primarily due to higher plant in-service balances.
Other, net decreased $10 million for the first quarter of 2022 compared to 2021 primarily due to market movements related to corporate-owned life insurance policies and higher pension and postretirement costs.
Income tax expense (benefit) increased $13 million to an expense of $2 million for the first quarter of 2022 compared to a benefit of $11 million for the first quarter of 2021. The effective tax rate was 2% for the first quarter of 2022 and (7)% for the first quarter of 2021. The effective tax rate increased primarily due to a valuation allowance PacifiCorp recorded in the first quarter of 2022 against state net operating loss carryforwards.
Liquidity and Capital Resources
As of March 31, 2022, PacifiCorp's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 335 | |
| | |
Credit facilities | | 1,200 | |
Less: | | |
| | |
Tax-exempt bond support | | (218) | |
Net credit facilities | | 982 | |
| | |
Total net liquidity | | $ | 1,317 | |
| | |
Credit facilities: | | |
Maturity dates | | 2024 | |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021 were $537 million and $469 million, respectively. The change was primarily due to timing of operating payables and higher collections from retail customers, partially offset by higher wholesale purchases.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021 were $(371) million and $(440) million, respectively. The change is primarily due to a decrease in capital expenditures of $65 million. 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, 2022 were $(11) million. Uses of cash consisted substantially of $9 million for the repayment of long-term debt.
Net cash flows from financing activities for the three-month period ended March 31, 2021 were $1 million. Sources of cash consisted of $2 million from the borrowing of short-term debt.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of March 31, 2022 and December 31, 2021, PacifiCorp had no short-term debt outstanding.
Debt Authorizations
PacifiCorp currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $2 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.
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 associated with PacifiCorp 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 |
| 2021 | | 2022 | | 2022 |
| | | | | |
Wind generation | $ | 33 | | | $ | 8 | | | $ | 154 | |
Electric distribution | 195 | | | 142 | | | 660 | |
Electric transmission | 60 | | | 153 | | | 1,185 | |
Other | 151 | | | 71 | | | 360 | |
Total | $ | 439 | | | $ | 374 | | | $ | 2,359 | |
PacifiCorp's 2021 IRP identified a roadmap for a significant increase in renewable and carbon free generation resources, coal to natural gas conversion of certain coal-fueled units, energy storage and associated transmission. PacifiCorp's 2021 IRP identified over 1,800 MWs of new wind-powered generating resources that are expected to be online by 2025. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp has included an estimate for these new generation resources and associated transmission in its forecast capital expenditures for 2022 through 2024. 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 $3 million and $27 million for the three-month periods ended March 31, 2022 and 2021, respectively. Construction includes 516 MWs of new wind-powered generating facilities that were placed in-service in 2021. Planned spending for the construction of additional wind-powered generating facilities totals $109 million for the remainder of 2022.
◦Planned acquisition and repowering of two wind-powered generating facilities by PacifiCorp totaling $3 million and $1 million for the three-month periods ended March 31, 2022 and 2021, respectively. The repowered facilities are expected to be placed in-service in 2023 and 2024. Planned spending for acquiring and repowering generating facilities totals $18 million for the remainder of 2022.
•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation and wildfire and storm damage restoration. Expenditures for these items totaled $25 million and $83 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for wildfire mitigation and wildfire and storm damage restoration totals $118 million for the remainder of 2022. Remaining investments relate to expenditures for new connections and distribution operations.
•Electric transmission includes both growth projects and operating expenditures. Transmission investment primarily reflects planned costs for the 416-mile, 500-kV high-voltage transmission line between the Aeolus substation near Medicine Bow in Wyoming and the Clover substation near Mona, Utah; the 59-mile, 230-kV high-voltage transmission line between the Windstar substation near Glenrock, Wyoming and the Aeolus substation; and the 290-mile, 500-kV high-voltage transmission line from the Longhorn substation near Boardman, Oregon to the Hemingway substation near Boise, Idaho. Expenditures for these segments totaled $95 million and $16 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for these Energy Gateway Transmission segments to be placed in-service in 2024-2026 totals $814 million for the remainder of 2022.
•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $45 million and $13 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned information technology spending totals $127 million for the remainder of 2022. Remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.
Energy Supply Planning
As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations.
In September 2021, PacifiCorp filed its 2021 IRP with its state commissions and subsequently filed its 2021 IRP Update in March and April 2022. In March 2022, the OPUC acknowledged PacifiCorp's 2021 IRP and its preferred portfolio. Reviews of the 2021 IRP by the UPSC, the Wyoming Public Service Commission, the WUTC and the Idaho Public Utilities Commission are ongoing.
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.
A draft of PacifiCorp's 2022 All Source RFP ("2022AS RFP") was filed for approval with the WUTC in December 2021, and with the UPSC and the OPUC in January 2022. The draft 2022AS RFP was approved by the WUTC in March 2022 and by the UPSC and the OPUC in April 2022. PacifiCorp expects to issue the 2022AS RFP to market in the second quarter of 2022.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2021.
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, 2021. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2021.
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, 2022, the related statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2022 and 2021, 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, 2021, 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 25, 2022, 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, 2021, 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 29, 2022
MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2022 | | 2021 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 131 | | | $ | 232 | |
Trade receivables, net | 468 | | | 526 | |
Income tax receivable | 297 | | | 79 | |
Inventories | 185 | | | 234 | |
Other current assets | 187 | | | 123 | |
Total current assets | 1,268 | | | 1,194 | |
| | | |
Property, plant and equipment, net | 20,344 | | | 20,301 | |
Regulatory assets | 492 | | | 473 | |
Investments and restricted investments | 985 | | | 1,026 | |
Other assets | 262 | | | 263 | |
| | | |
Total assets | $ | 23,351 | | | $ | 23,257 | |
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, |
| 2022 | | 2021 |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 429 | | | $ | 531 | |
Accrued interest | 88 | | | 84 | |
Accrued property, income and other taxes | 144 | | | 158 | |
| | | |
Current portion of long-term debt | 7 | | | — | |
Other current liabilities | 144 | | | 145 | |
Total current liabilities | 812 | | | 918 | |
| | | |
Long-term debt | 7,719 | | | 7,721 | |
Regulatory liabilities | 1,057 | | | 1,080 | |
Deferred income taxes | 3,373 | | | 3,389 | |
Asset retirement obligations | 723 | | | 714 | |
Other long-term liabilities | 463 | | | 475 | |
Total liabilities | 14,147 | | | 14,297 | |
| | | |
Commitments and contingencies (Note 7) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | | | — | |
Additional paid-in capital | 561 | | | 561 | |
Retained earnings | 8,643 | | | 8,399 | |
| | | |
Total shareholder's equity | 9,204 | | | 8,960 | |
| | | |
Total liabilities and shareholder's equity | $ | 23,351 | | | $ | 23,257 | |
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, |
| | | | | 2022 | | 2021 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 608 | | | $ | 545 | |
Regulated natural gas and other | | | | | 397 | | | 522 | |
Total operating revenue | | | | | 1,005 | | | 1,067 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 125 | | | 151 | |
Cost of natural gas purchased for resale and other | | | | | 298 | | | 432 | |
Operations and maintenance | | | | | 192 | | | 193 | |
Depreciation and amortization | | | | | 250 | | | 207 | |
Property and other taxes | | | | | 40 | | | 36 | |
Total operating expenses | | | | | 905 | | | 1,019 | |
| | | | | | | |
Operating income | | | | | 100 | | | 48 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (78) | | | (74) | |
Allowance for borrowed funds | | | | | 4 | | | 2 | |
Allowance for equity funds | | | | | 15 | | | 6 | |
Other, net | | | | | (3) | | | 11 | |
Total other income (expense) | | | | | (62) | | | (55) | |
| | | | | | | |
Income (loss) before income tax benefit | | | | | 38 | | | (7) | |
Income tax benefit | | | | | (206) | | | (154) | |
| | | | | | | |
Net income | | | | | $ | 244 | | | $ | 147 | |
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, 2020 | $ | — | | | $ | 561 | | | $ | 7,504 | | | $ | 8,065 | |
Net income | — | | | — | | | 147 | | | 147 | |
| | | | | | | |
Balance, March 31, 2021 | $ | — | | | $ | 561 | | | $ | 7,651 | | | $ | 8,212 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Balance, December 31, 2021 | $ | — | | | $ | 561 | | | $ | 8,399 | | | $ | 8,960 | |
Net income | — | | | — | | | 244 | | | 244 | |
| | | | | | | |
Balance, March 31, 2022 | $ | — | | | $ | 561 | | | $ | 8,643 | | | $ | 9,204 | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net income | $ | 244 | | | $ | 147 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 250 | | | 207 | |
Amortization of utility plant to other operating expenses | 9 | | | 8 | |
Allowance for equity funds | (15) | | | (6) | |
Deferred income taxes and investment tax credits, net | 16 | | | 154 | |
Settlements of asset retirement obligations | (7) | | | (4) | |
Other, net | 10 | | | (18) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 42 | | | (299) | |
Inventories | 49 | | | 46 | |
| | | |
Pension and other postretirement benefit plans | 3 | | | 1 | |
Accrued property, income and other taxes, net | (244) | | | (331) | |
Accounts payable and other liabilities | 3 | | | 10 | |
Net cash flows from operating activities | 360 | | | (85) | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (459) | | | (298) | |
Purchases of marketable securities | (105) | | | (52) | |
Proceeds from sales of marketable securities | 102 | | | 47 | |
Other, net | 1 | | | — | |
Net cash flows from investing activities | (461) | | | (303) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
Repayments of long-term debt | (1) | | | — | |
Net proceeds from short-term debt | — | | | 387 | |
Other, net | 1 | | | — | |
Net cash flows from financing activities | — | | | 387 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (101) | | | (1) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 239 | | | 45 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 138 | | | $ | 44 | |
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, 2022, and for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month periods ended March 31, 2022, 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, 2021, 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, 2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents 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, |
| 2022 | | 2021 |
| | | |
Cash and cash equivalents | $ | 131 | | | $ | 232 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 138 | | | $ | 239 | |
(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 | | 2022 | | 2021 |
Utility plant in-service, net: | | | | | |
Generation | 20-70 years | | $ | 17,466 | | | $ | 17,397 | |
Transmission | 52-75 years | | 2,488 | | | 2,474 | |
Electric distribution | 20-75 years | | 4,713 | | | 4,661 | |
Natural gas distribution | 29-75 years | | 2,055 | | | 2,039 | |
Utility plant in-service | | | 26,722 | | | 26,571 | |
Accumulated depreciation and amortization | | | (7,555) | | | (7,376) | |
Utility plant in-service, net | | | 19,167 | | | 19,195 | |
Nonregulated property, net: | | | | | |
Nonregulated property gross | 20-50 years | | 7 | | | 7 | |
Accumulated depreciation and amortization | | | (1) | | | (1) | |
Nonregulated property, net | | | 6 | | | 6 | |
| | | 19,173 | | | 19,201 | |
Construction work-in-progress | | | 1,171 | | | 1,100 | |
Property, plant and equipment, net | | | $ | 20,344 | | | $ | 20,301 | |
(4) 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 pretax 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 pretax 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, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
Income tax credits | | | | | (534) | | | 2,400 | |
State income tax, net of federal income tax impacts | | | | | (21) | | | (29) | |
Effects of ratemaking | | | | | (8) | | | (186) | |
Other, net | | | | | — | | | (6) | |
Effective income tax rate | | | | | (542) | % | | 2,200 | % |
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, 2022 and 2021 totaled $203 million and $151 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. 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. MidAmerican Energy made no cash payments for income tax to BHE for each of the three-month periods ended March 31, 2022 and 2021.
(5) 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 for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
| | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
Pension: | | | | | | | |
Service cost | | | | | $ | 5 | | | $ | 5 | |
Interest cost | | | | | 5 | | | 6 | |
Expected return on plan assets | | | | | (7) | | | (9) | |
Settlement | | | | | 2 | | | — | |
| | | | | | | |
Net periodic benefit cost | | | | | $ | 5 | | | $ | 2 | |
| | | | | | | |
Other postretirement: | | | | | | | |
Service cost | | | | | $ | 2 | | | $ | 2 | |
Interest cost | | | | | 2 | | | 2 | |
Expected return on plan assets | | | | | (4) | | | (2) | |
Net amortization | | | | | — | | | (1) | |
Net periodic benefit cost | | | | | $ | — | | | $ | 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 $3 million, respectively, during 2022. As of March 31, 2022, $2 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(6) 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, 2022: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | 66 | | | $ | 4 | | | $ | — | | | $ | 70 | |
Money market mutual funds | | 132 | | | — | | | — | | | — | | | 132 | |
Debt securities: | | | | | | | | | | |
U.S. government obligations | | 225 | | | — | | | — | | | — | | | 225 | |
International government obligations | | — | | | 1 | | | — | | | — | | | 1 | |
Corporate obligations | | — | | | 79 | | | — | | | — | | | 79 | |
Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | | — | | | 1 | | | — | | | — | | | 1 | |
Equity securities: | | | | | | | | | | |
U.S. companies | | 415 | | | — | | | — | | | — | | | 415 | |
International companies | | 9 | | | — | | | — | | | — | | | 9 | |
Investment funds | | 23 | | | — | | | — | | | — | | | 23 | |
| | $ | 804 | | | $ | 150 | | | $ | 4 | | | $ | — | | | $ | 958 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | (1) | | | $ | — | | | $ | — | | | $ | — | | | $ | (1) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other(1) | | Total |
As of December 31, 2021: | | | | | | | | | | |
Assets: | | | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | 32 | | | $ | 3 | | | $ | (7) | | | $ | 28 | |
Money market mutual funds | | 228 | | | — | | | — | | | — | | | 228 | |
Debt securities: | | | | | | | | | | |
U.S. government obligations | | 232 | | | — | | | — | | | — | | | 232 | |
International government obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Corporate obligations | | — | | | 90 | | | — | | | — | | | 90 | |
Municipal obligations | | — | | | 3 | | | — | | | — | | | 3 | |
Agency, asset and mortgage-backed obligations | | — | | | 2 | | | — | | | — | | | 2 | |
Equity securities: | | | | | | | | | | |
U.S. companies | | 428 | | | — | | | — | | | — | | | 428 | |
International companies | | 10 | | | — | | | — | | | — | | | 10 | |
Investment funds | | 18 | | | — | | | — | | | — | | | 18 | |
| | $ | 916 | | | $ | 129 | | | $ | 3 | | | $ | (7) | | | $ | 1,041 | |
| | | | | | | | | | |
Liabilities - commodity derivatives | | $ | — | | | $ | (6) | | | $ | (8) | | | $ | 12 | | | $ | (2) | |
(1)Represents netting under master netting arrangements and a net cash collateral receivable of $— million and $5 million as of March 31, 2022 and December 31, 2021, respectively.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2022 | | As of December 31, 2021 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,726 | | | $ | 8,196 | | | $ | 7,721 | | | $ | 9,037 | |
(7) 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, 2022, has accrued an $8 million liability for refunds of amounts collected under the higher ROE during the periods covered by both complaints.
(8) Revenue from Contracts with Customers
The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 9 (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | For the Three-Month Period Ended March 31, 2022 |
| | | | | | | | | Electric | | Natural Gas | | Other | | Total |
Customer Revenue: | | | | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | | | | |
Residential | | | | | | | | | $ | 168 | | | $ | 225 | | | $ | — | | | $ | 393 | |
Commercial | | | | | | | | | 74 | | | 88 | | | — | | | 162 | |
Industrial | | | | | | | | | 198 | | | 9 | | | — | | | 207 | |
Natural gas transportation services | | | | | | | | | — | | | 14 | | | — | | | 14 | |
Other retail(1) | | | | | | | | | 32 | | | 1 | | | — | | | 33 | |
Total retail | | | | | | | | | 472 | | | 337 | | | — | | | 809 | |
Wholesale | | | | | | | | | 104 | | | 58 | | | — | | | 162 | |
Multi-value transmission projects | | | | | | | | | 15 | | | — | | | — | | | 15 | |
Other Customer Revenue | | | | | | | | | — | | | — | | | 1 | | | 1 | |
Total Customer Revenue | | | | | | | | | 591 | | | 395 | | | 1 | | | 987 | |
Other revenue | | | | | | | | | 17 | | | 1 | | | — | | | 18 | |
Total operating revenue | | | | | | | | | $ | 608 | | | $ | 396 | | | $ | 1 | | | $ | 1,005 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 | | | — | | | 5 | |
Total operating revenue | | | | | | | | | $ | 545 | | | $ | 512 | | | $ | 10 | | | $ | 1,067 | |
(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.
(9) Segment Information
MidAmerican Energy has identified two 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, |
| | | | | 2022 | | 2021 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 608 | | | $ | 545 | |
Regulated natural gas | | | | | 396 | | | 512 | |
Other | | | | | 1 | | | 10 | |
Total operating revenue | | | | | $ | 1,005 | | | $ | 1,067 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | | | | | $ | 51 | | | $ | 9 | |
Regulated natural gas | | | | | 49 | | | 39 | |
| | | | | | | |
Total operating income | | | | | 100 | | | 48 | |
Interest expense | | | | | (78) | | | (74) | |
Allowance for borrowed funds | | | | | 4 | | | 2 | |
Allowance for equity funds | | | | | 15 | | | 6 | |
Other, net | | | | | (3) | | | 11 | |
Income (loss) before income tax benefit | | | | | $ | 38 | | | $ | (7) | |
| | | | | | | | | | | |
| As of |
| March 31, 2022 | | December 31, 2021 |
Assets: | | | |
Regulated electric | $ | 21,613 | | | $ | 21,385 | |
Regulated natural gas | 1,737 | | | 1,871 | |
Other | 1 | | | 1 | |
Total assets | $ | 23,351 | | | $ | 23,257 | |
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, 2022, the related consolidated statements of operations, changes in member's equity, and cash flows for the three-month periods ended March 31, 2022 and 2021, 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, 2021, 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 25, 2022, 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, 2021, 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 29, 2022
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2022 | | 2021 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 132 | | | $ | 233 | |
Trade receivables, net | 468 | | | 526 | |
Income tax receivable | 299 | | | 80 | |
Inventories | 185 | | | 234 | |
Other current assets | 187 | | | 123 | |
Total current assets | 1,271 | | | 1,196 | |
| | | |
Property, plant and equipment, net | 20,345 | | | 20,302 | |
Goodwill | 1,270 | | | 1,270 | |
Regulatory assets | 492 | | | 473 | |
Investments and restricted investments | 987 | | | 1,028 | |
Other assets | 261 | | | 262 | |
| | | |
Total assets | $ | 24,626 | | | $ | 24,531 | |
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, |
| 2022 | | 2021 |
LIABILITIES AND MEMBER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 429 | | | $ | 531 | |
Accrued interest | 89 | | | 89 | |
Accrued property, income and other taxes | 144 | | | 158 | |
Note payable to affiliate | 197 | | | 189 | |
| | | |
Current portion of long-term debt | 7 | | | — | |
Other current liabilities | 145 | | | 146 | |
Total current liabilities | 1,011 | | | 1,113 | |
| | | |
Long-term debt | 7,959 | | | 7,961 | |
Regulatory liabilities | 1,057 | | | 1,080 | |
Deferred income taxes | 3,371 | | | 3,387 | |
Asset retirement obligations | 723 | | | 714 | |
Other long-term liabilities | 463 | | | 475 | |
Total liabilities | 14,584 | | | 14,730 | |
| | | |
Commitments and contingencies (Note 7) | | | |
| | | |
Member's equity: | | | |
Paid-in capital | 1,679 | | | 1,679 | |
Retained earnings | 8,363 | | | 8,122 | |
| | | |
Total member's equity | 10,042 | | | 9,801 | |
| | | |
Total liabilities and member's equity | $ | 24,626 | | | $ | 24,531 | |
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, |
| | | | | 2022 | | 2021 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 608 | | | $ | 545 | |
Regulated natural gas and other | | | | | 397 | | | 522 | |
Total operating revenue | | | | | 1,005 | | | 1,067 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 125 | | | 151 | |
Cost of natural gas purchased for resale and other | | | | | 298 | | | 432 | |
Operations and maintenance | | | | | 192 | | | 193 | |
Depreciation and amortization | | | | | 250 | | | 207 | |
Property and other taxes | | | | | 40 | | | 36 | |
Total operating expenses | | | | | 905 | | | 1,019 | |
| | | | | | | |
Operating income | | | | | 100 | | | 48 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (82) | | | (78) | |
Allowance for borrowed funds | | | | | 4 | | | 2 | |
Allowance for equity funds | | | | | 15 | | | 6 | |
Other, net | | | | | (4) | | | 10 | |
Total other income (expense) | | | | | (67) | | | (60) | |
| | | | | | | |
Income (loss) before income tax benefit | | | | | 33 | | | (12) | |
Income tax benefit | | | | | (208) | | | (156) | |
| | | | | | | |
Net income | | | | | $ | 241 | | | $ | 144 | |
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, 2020 | $ | 1,679 | | | $ | 7,240 | | | $ | 8,919 | |
Net income | — | | | 144 | | | 144 | |
| | | | | |
Balance, March 31, 2021 | $ | 1,679 | | | $ | 7,384 | | | $ | 9,063 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
Balance, December 31, 2021 | $ | 1,679 | | | $ | 8,122 | | | $ | 9,801 | |
Net income | — | | | 241 | | | 241 | |
| | | | | |
Balance, March 31, 2022 | $ | 1,679 | | | $ | 8,363 | | | $ | 10,042 | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net income | $ | 241 | | | $ | 144 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
Depreciation and amortization | 250 | | | 207 | |
Amortization of utility plant to other operating expenses | 9 | | | 8 | |
Allowance for equity funds | (15) | | | (6) | |
Deferred income taxes and investment tax credits, net | 16 | | | 153 | |
| | | |
Settlements of asset retirement obligations | (7) | | | (4) | |
Other, net | 10 | | | (17) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 43 | | | (298) | |
Inventories | 49 | | | 46 | |
| | | |
Pension and other postretirement benefit plans | 3 | | | 1 | |
Accrued property, income and other taxes, net | (245) | | | (332) | |
Accounts payable and other liabilities | (1) | | | 6 | |
Net cash flows from operating activities | 353 | | | (92) | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (459) | | | (298) | |
Purchases of marketable securities | (105) | | | (52) | |
Proceeds from sales of marketable securities | 102 | | | 47 | |
| | | |
Other, net | 1 | | | — | |
Net cash flows from investing activities | (461) | | | (303) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
Repayments of long-term debt | (1) | | | — | |
Net change in note payable to affiliate | 8 | | | 7 | |
Net proceeds from short-term debt | — | | | 387 | |
| | | |
Net cash flows from financing activities | 7 | | | 394 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | (101) | | | (1) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 240 | | | 46 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 139 | | | $ | 45 | |
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, 2022, and for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month periods ended March 31, 2022, are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2021, 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, 2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents 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, |
| 2022 | | 2021 |
| | | |
Cash and cash equivalents | $ | 132 | | | $ | 233 | |
Restricted cash and cash equivalents in other current assets | 7 | | | 7 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 139 | | | $ | 240 | |
(3) Property, Plant and Equipment, Net
Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.
(4) Income Taxes
The effective income tax rate for the three-month period ended March 31, 2021, is 1,300% and results from a $156 million income tax benefit associated with a $12 million pretax 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 pretax 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, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
Income tax credits | | | | | (618) | | | 1,400 | |
State income tax, net of federal income tax impacts | | | | | (24) | | | (8) | |
Effects of ratemaking | | | | | (9) | | | (108) | |
Other, net | | | | | — | | | (5) | |
Effective income tax rate | | | | | (630) | % | | 1,300 | % |
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, 2022 and 2021 totaled $203 million and $151 million, respectively.
Berkshire Hathaway includes BHE and subsidiaries in its U.S. 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. MidAmerican Funding made no cash payments for income tax to BHE for each of the three-month periods ended March 31, 2022 and 2021.
(5) Employee Benefit Plans
Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.
(6) Fair Value Measurements
Refer to Note 6 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, 2022 | | As of December 31, 2021 |
| Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | | | | |
Long-term debt | $ | 7,966 | | | $ | 8,480 | | | $ | 7,961 | | | $ | 9,350 | |
(7) 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 7 of MidAmerican Energy's Notes to Financial Statements.
(8) Revenue from Contracts with Customers
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.
(9) Segment Information
MidAmerican Funding has identified two 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, |
| | | | | 2022 | | 2021 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 608 | | | $ | 545 | |
Regulated natural gas | | | | | 396 | | | 512 | |
Other | | | | | 1 | | | 10 | |
Total operating revenue | | | | | $ | 1,005 | | | $ | 1,067 | |
| | | | | | | |
Operating income: | | | | | | | |
Regulated electric | | | | | $ | 51 | | | $ | 9 | |
Regulated natural gas | | | | | 49 | | | 39 | |
| | | | | | | |
Total operating income | | | | | 100 | | | 48 | |
Interest expense | | | | | (82) | | | (78) | |
Allowance for borrowed funds | | | | | 4 | | | 2 | |
Allowance for equity funds | | | | | 15 | | | 6 | |
Other, net | | | | | (4) | | | 10 | |
Income (loss) before income tax benefit | | | | | $ | 33 | | | $ | (12) | |
| | | | | | | | | | | |
| As of |
| March 31, 2022 | | December 31, 2021 |
Assets(1): | | | |
Regulated electric | $ | 22,804 | | | $ | 22,576 | |
Regulated natural gas | 1,816 | | | 1,950 | |
Other | 6 | | | 5 | |
Total assets | $ | 24,626 | | | $ | 24,531 | |
| | | | | |
(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 2022 and 2021
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the first quarter of 2022 was $244 million, an increase of $97 million, or 66%, compared to 2021, primarily due to higher electric utility margin of $89 million, higher natural gas utility margin of $18 million, higher income tax benefit of $52 million and higher allowances for equity and borrowed funds of $11 million, offset by higher depreciation and amortization expense of $43 million, unfavorable other, net of $14 million, lower nonregulated utility margins of $9 million, higher property and other taxes of $4 million and higher interest expense of $4 million. Electric retail customer volumes increased 6% primarily due to higher usage for certain industrial customers and the favorable impact of weather. Wholesale electricity sales volumes increased 31% due to favorable market conditions. Energy generated increased 17% primarily due to greater wind-powered generation, resulting in a 10% decrease in the average per-unit cost of energy generated. Natural gas retail customer volumes increased 8% due to the favorable impact of weather.
MidAmerican Funding -
MidAmerican Funding's net income for the first quarter of 2022 was $241 million, an increase of $97 million, or 67%, compared to 2021. The variances in net income were primarily due to the changes in MidAmerican Energy's earnings discussed above.
Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.
MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | First Quarter |
| | | | | | | | 2022 | | 2021 | | Change |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 608 | | | $ | 545 | | | $ | 63 | | 12 | % |
Cost of fuel and energy | | | | | | | | | 125 | | | 151 | | | (26) | | (17) | |
Electric utility margin | | | | | | | | | 483 | | | 394 | | | 89 | | 23 | % |
| | | | | | | | | | | | | | |
Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | 396 | | | 512 | | | (116) | | (23) | % |
Natural gas purchased for resale | | | | | | | | | 298 | | | 432 | | | (134) | | (31) | |
Natural gas utility margin | | | | | | | | | 98 | | | 80 | | | 18 | | 23 | % |
| | | | | | | | | | | | | | |
Utility margin | | | | | | | | | 581 | | | 474 | | | 107 | | 23 | % |
| | | | | | | | | | | | | | |
Other operating revenue | | | | | | | | | 1 | | | 10 | | | (9) | | (90) | % |
| | | | | | | | | | | | | | |
Operations and maintenance | | | | | | | | | 192 | | | 193 | | | (1) | | (1) | |
Depreciation and amortization | | | | | | | | | 250 | | | 207 | | | 43 | | 21 | |
Property and other taxes | | | | | | | | | 40 | | | 36 | | | 4 | | 11 | |
| | | | | | | | | | | | | | |
Operating income | | | | | | | | | $ | 100 | | | $ | 48 | | | $ | 52 | | * |
* Not meaningful.
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First Quarter |
| | | | | | | 2022 | | 2021 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 608 | | | $ | 545 | | | $ | 63 | | | 12 | % |
Cost of fuel and energy | | | | | | | | | 125 | | | 151 | | | (26) | | | (17) | |
Utility margin | | | | | | | | | $ | 483 | | | $ | 394 | | | $ | 89 | | | 23 | % |
| | | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | | |
Residential | | | | | | | | | 1,853 | | | 1,738 | | | 115 | | | 7 | % |
Commercial | | | | | | | | | 1,013 | | | 938 | | | 75 | | | 8 | |
Industrial | | | | | | | | | 3,979 | | | 3,819 | | | 160 | | | 4 | |
Other | | | | | | | | | 403 | | | 370 | | | 33 | | | 9 | |
Total retail | | | | | | | | | 7,248 | | | 6,865 | | | 383 | | | 6 | |
Wholesale | | | | | | | | | 5,325 | | | 4,051 | | | 1,274 | | | 31 | |
Total sales | | | | | | | | | 12,573 | | | 10,916 | | | 1,657 | | | 15 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | | | | | | | | 810 | | 801 | | 9 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | | |
Retail | | | | | | | | | $ | 65.10 | | | $ | 65.82 | | | $ | (0.72) | | | (1) | % |
Wholesale | | | | | | | | | $ | 20.65 | | | $ | 16.64 | | | $ | 4.01 | | | 24 | % |
| | | | | | | | | | | | | | | |
Heating degree days | | | | | | | | | 3,315 | | | 3,211 | | | 104 | | | 3 | % |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Sources of energy (GWhs)(1): | | | | | | | | | | | | | | | |
Wind and other(2) | | | | | | | | | 8,290 | | | 6,122 | | | 2,168 | | | 35 | % |
Coal | | | | | | | | | 2,359 | | | 2,902 | | | (543) | | | (19) | |
Nuclear | | | | | | | | | 920 | | | 895 | | | 25 | | | 3 | |
Natural gas | | | | | | | | | 234 | | | 143 | | | 91 | | | 64 | |
Total energy generated | | | | | | | | | 11,803 | | | 10,062 | | | 1,741 | | | 17 | |
Energy purchased | | | | | | | | | 962 | | | 1,018 | | | (56) | | | (6) | |
Total | | | | | | | | | 12,765 | | | 11,080 | | | 1,685 | | | 15 | % |
| | | | | | | | | | | | | | | |
Average cost of energy per MWh: | | | | | | | | | | | | | | | |
Energy generated(3) | | | | | | | | | $ | 5.56 | | | $ | 6.15 | | | $ | (0.59) | | | (10) | % |
Energy purchased | | | | | | | | | $ | 62.04 | | | $ | 87.45 | | | $ | (25.41) | | | (29) | % |
(1) GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | First Quarter |
| | | | | | | 2022 | | 2021 | | Change |
Utility margin (in millions): | | | | | | | | | | | | | | | |
Operating revenue | | | | | | | | | $ | 396 | | | $ | 512 | | | $ | (116) | | | (23) | % |
Natural gas purchased for resale | | | | | | | | | 298 | | | 432 | | | (134) | | | (31) | |
Utility margin | | | | | | | | | $ | 98 | | | $ | 80 | | | $ | 18 | | | 23 | % |
| | | | | | | | | | | | | | | |
Throughput (000's Dths): | | | | | | | | | | | | | | | |
Residential | | | | | | | | | 27,099 | | | 25,282 | | | 1,817 | | | 7 | % |
Commercial | | | | | | | | | 12,460 | | | 11,733 | | | 727 | | | 6 | |
Industrial | | | | | | | | | 1,844 | | | 1,437 | | | 407 | | | 28 | |
Other | | | | | | | | | 35 | | | 37 | | | (2) | | | (5) | |
Total retail sales | | | | | | | | | 41,438 | | | 38,489 | | | 2,949 | | | 8 | |
Wholesale sales | | | | | | | | | 12,232 | | | 10,773 | | | 1,459 | | | 14 | |
Total sales | | | | | | | | | 53,670 | | | 49,262 | | | 4,408 | | | 9 | |
Natural gas transportation service | | | | | | | | | 31,313 | | | 29,640 | | | 1,673 | | | 6 | |
Total throughput | | | | | | | | | 84,983 | | | 78,902 | | | 6,081 | | | 8 | % |
| | | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | | | | | | | | 785 | | | 777 | | | 8 | | | 1 | % |
| | | | | | | | | | | | | | | |
Average revenue per retail Dth sold | | | | | | | | | $ | 7.84 | | | $ | 11.70 | | | $ | (3.86) | | | (33) | % |
| | | | | | | | | | | | | | | |
Heating degree days | | | | | | | | | 3,485 | | | 3,301 | | | 184 | | | 6 | % |
| | | | | | | | | | | | | | | |
Average cost of natural gas per retail Dth sold | | | | | | | | | $ | 5.80 | | | $ | 9.87 | | | $ | (4.07) | | | (41) | % |
| | | | | | | | | | | | | | | |
Combined retail and wholesale average cost of natural gas per Dth sold | | | | | | | | | $ | 5.55 | | | $ | 8.76 | | | $ | (3.21) | | | (37) | % |
Quarter Ended March 31, 2022 Compared to Quarter Ended March 31, 2021
MidAmerican Energy -
Electric utility margin increased $89 million, or 23%, for the first quarter of 2022 compared to 2021, due to:
•a $64 million increase in wholesale utility margin due to higher margins per unit of $58 million, reflecting lower energy costs and higher market prices, and higher volumes of 31.4%; and
•a $25 million increase in retail utility margin primarily due to $17 million from higher customer usage; $9 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $1 million from the favorable impact of weather; partially offset by $2 million due to price impacts from changes in sales mix. Retail customer volumes increased 5.6%.
Natural gas utility margin increased $18 million, or 23%, for the first quarter of 2022 compared to 2021 primarily due to:
•an $8 million increase from lower refunds related to amortization of excess accumulated deferred income taxes arising from 2017 Tax Reform (offset in income tax benefit);
•a $5 million increase from higher average prices primarily due to the timing of recoveries through a capital tracker mechanism; and
•a $4 million increase from the favorable impact of weather.
Depreciation and amortization for the first quarter of 2022 increased $43 million, or 21%, compared to 2021 primarily due to $42 million from higher Iowa revenue sharing accruals, $7 million from wind-powered generating facilities and other plant placed in-service and $6 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $12 million from a regulatory mechanism deferring certain depreciation expense in 2022.
Allowance for borrowed and equity funds increased $11 million, or 138%, for the first quarter of 2022 compared to 2021 primarily due to higher construction work-in-progress balances related to wind- and solar-powered generation.
Other, net decreased $14 million, or 127%, for the first quarter of 2022 compared to 2021 primarily due to unfavorable investment earnings, largely attributable to lower cash surrender values of corporate-owned life insurance policies, and higher non-service costs of postretirement employee benefit plans.
Income tax benefit increased $52 million, or 34%, for the first quarter of 2022 compared to 2021, and the effective tax rate was (542)% for 2022 and 2,200% for 2021. The change in the effective tax rates for 2022 compared to 2021 was primarily due to higher PTCs, the timing of state income tax benefits and the effects of ratemaking, partially offset by higher pretax income. PTCs for the first quarter of 2022 and 2021 totaled $203 million and $151 million, respectively.
MidAmerican Funding -
Income tax benefit increased $52 million, or 33%, for the first quarter of 2022 compared to 2021, and the effective tax rate was (630)% for 2022 and 1,300% for 2021. 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, 2022, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):
| | | | | | | | |
MidAmerican Energy: | | |
Cash and cash equivalents | | $ | 131 | |
| | |
Credit facilities, maturing 2022 and 2024 | | 1,505 | |
Less: | | |
| | |
Tax-exempt bond support | | (370) | |
Net credit facilities | | 1,135 | |
| | |
MidAmerican Energy total net liquidity | | $ | 1,266 | |
| | |
MidAmerican Funding: | | |
MidAmerican Energy total net liquidity | | $ | 1,266 | |
Cash and cash equivalents | | 1 | |
MHC, Inc. credit facility, maturing 2022 | | 4 | |
MidAmerican Funding total net liquidity | | $ | 1,271 | |
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021, were $360 million and $(85) million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021, were $353 million and $(92) million, respectively. Cash flows from operating activities reflect higher utility margins for MidAmerican Energy's regulated electric and natural gas businesses, lower payments to vendors and lower derivative collateral posted, partially offset by higher interest expense. Higher utility margins are largely attributable to the recovery of higher natural gas costs caused by the February 2021 polar vortex weather event.
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, 2022 and 2021, were $(461) million and $(303) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021, were $(461) million and $(303) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital 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, 2022 and 2021 were $— million and $387 million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2022 and 2021, were $7 million and $394 million, respectively. Through its commercial paper program, MidAmerican Energy received $387 million in 2021. MidAmerican Funding received $8 million and $7 million in 2022 and 2021, respectively, through its note payable with BHE.
Debt Authorizations and Related Matters
Short-term Debt
MidAmerican Energy has authority from the FERC to issue through April 2, 2024, 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 $1.5 billion unsecured credit facility expiring in June 2024. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
Long-term Debt and Preferred Stock
MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities and preferred stock through June 13, 2024. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million and from the Illinois Commerce Commission to issue long-term debt securities up to an aggregate of $350 million through August 20, 2022. Additionally, MidAmerican Energy has authority from the Illinois Commerce Commission through October 15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024.
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 |
| 2021 | | 2022 | | 2022 |
| | | | | |
Wind generation | $ | 32 | | | $ | 133 | | | $ | 762 | |
Electric distribution | 46 | | | 54 | | | 260 | |
Electric transmission | 23 | | | 21 | | | 171 | |
Solar generation | 3 | | | 44 | | | 139 | |
Other | 194 | | | 207 | | | 681 | |
Total | $ | 298 | | | $ | 459 | | | $ | 2,013 | |
MidAmerican Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction of wind-powered generating facilities totaling $3 million for the three-month period ended March 31, 2022. Planned spending for the construction of additional wind-powered generating facilities totals $142 million for the remainder of 2022.
◦Repowering of wind-powered generating facilities totaling $120 million and $24 million for the three-month periods ended March 31, 2022 and 2021, respectively. Planned spending for the repowering of wind-powered generating facilities totals $386 million for the remainder of 2022. 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 812 MWs of current repowering projects not in-service as of March 31, 2022, 511 MWs are currently expected to qualify for 80% of the PTCs available for 10 years following each facility's return to service and 301 MWs are expected to qualify for 60% of such credits.
•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 generation includes the construction of solar-powered generating facilities totaling 141 MWs of small- and utility-scale solar generation, with total spend of $44 million and $3 million for the three-month periods ended March 31, 2022 and 2021, respectively and planned spending of $96 million for the remainder of 2022.
•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.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's material cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2021.
Quad Cities Generating Station Operating Status
Constellation Energy Corp. ("Constellation Energy," previously Exelon Generation Company, LLC, which was a subsidiary of Exelon Corporation prior to February 1, 2022), 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 ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Constellation Energy additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a state government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expanded the breadth and scope of the PJM's MOPR, which became effective as of the PJM's capacity auction for the 2022-2023 planning year in May 2021. While the FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. A number of parties, including Constellation Energy, have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the D.C. Circuit.
As a result, the MOPR applied to Quad Cities Station in the capacity auction for the 2022-2023 planning year, which prevented Quad Cities Station from clearing in that capacity auction.
At the direction of the PJM Board of Managers, the PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. The PJM filed related tariff revisions at the FERC on July 30, 2021, and, on September 29, 2021, the PJM's proposed MOPR reforms became effective by operation of law. Under the new tariff provisions, the MOPR will no longer apply to Quad Cities Station. Requests for rehearing of the FERC's notice establishing the effective date for the PJM's proposed market reforms were filed in October 2021 and denied by operation of law on November 4, 2021. Several parties have filed petitions for review of the FERC's orders in this proceeding, which remain pending before the Court of Appeals for the Third Circuit. Constellation Energy is strenuously opposing these appeals.
Assuming the continued effectiveness of the Illinois zero emission standard, Constellation Energy no longer considers Quad Cities Station to be at heightened risk for early retirement. However, to the extent the Illinois zero emission standard does not operate as expected over its full term, Quad Cities Station would be at heightened risk for early retirement. The FERC's December 19, 2019 order on the PJM MOPR may undermine the continued effectiveness of the Illinois zero emission standard unless the PJM adopts further changes to the MOPR or Illinois implements an FRR mechanism, under which Quad Cities Station would be removed from the PJM's capacity auction.
Regulatory Matters
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 MidAmerican Energy'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. MidAmerican Energy 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 MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and consolidated 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 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, 2021. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2021.
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, 2022, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, 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, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
April 29, 2022
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2022 | | 2021 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 47 | | | $ | 33 | |
Trade receivables, net | 187 | | | 227 | |
Inventories | 61 | | | 64 | |
| | | |
Regulatory assets | 327 | | | 291 | |
Prepayments | 48 | | | 33 | |
| | | |
Other current assets | 59 | | | 53 | |
Total current assets | 729 | | | 701 | |
| | | |
Property, plant and equipment, net | 6,992 | | | 6,891 | |
| | | |
Regulatory assets | 759 | | | 728 | |
Other assets | 431 | | | 432 | |
| | | |
Total assets | $ | 8,911 | | | $ | 8,752 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 224 | | | $ | 242 | |
Accrued interest | 38 | | | 32 | |
Accrued property, income and other taxes | 30 | | | 29 | |
| | | |
| | | |
| | | |
Short-term debt | 104 | | | 180 | |
Regulatory liabilities | 49 | | | 49 | |
Customer deposits | 45 | | | 44 | |
| | | |
| | | |
Derivative contracts | 88 | | | 55 | |
Other current liabilities | 59 | | | 62 | |
Total current liabilities | 637 | | | 693 | |
| | | |
Long-term debt | 2,700 | | | 2,499 | |
Finance lease obligations | 306 | | | 310 | |
Regulatory liabilities | 1,083 | | | 1,100 | |
Deferred income taxes | 799 | | | 782 | |
Other long-term liabilities | 358 | | | 338 | |
Total liabilities | 5,883 | | | 5,722 | |
| | | |
Commitments and contingencies (Note 8) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — | | | — | |
Additional paid-in capital | 2,308 | | | 2,308 | |
Retained earnings | 722 | | | 724 | |
Accumulated other comprehensive loss, net | (2) | | | (2) | |
Total shareholder's equity | 3,028 | | | 3,030 | |
| | | |
Total liabilities and shareholder's equity | $ | 8,911 | | | $ | 8,752 | |
| | | |
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, | | |
| 2022 | | 2021 | | | | |
| | | | | | | |
Operating revenue | $ | 415 | | | $ | 370 | | | | | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | 212 | | | 165 | | | | | |
Operations and maintenance | 65 | | | 63 | | | | | |
Depreciation and amortization | 103 | | | 101 | | | | | |
Property and other taxes | 13 | | | 12 | | | | | |
Total operating expenses | 393 | | | 341 | | | | | |
| | | | | | | |
Operating income | 22 | | | 29 | | | | | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (38) | | | (38) | | | | | |
Allowance for borrowed funds | 1 | | | 1 | | | | | |
Allowance for equity funds | 3 | | | 1 | | | | | |
Interest and dividend income | 9 | | | 5 | | | | | |
Other, net | 1 | | | 4 | | | | | |
Total other income (expense) | (24) | | | (27) | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Net (loss) income | $ | (2) | | | $ | 2 | | | | | |
| | | | | | | |
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, 2020 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 634 | | | $ | (3) | | | $ | 2,939 | |
Net income | | — | | | — | | | — | | | 2 | | | — | | | 2 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 636 | | | $ | (3) | | | $ | 2,941 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 724 | | | $ | (2) | | | $ | 3,030 | |
Net loss | | — | | | — | | | — | | | (2) | | | — | | | (2) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 2,308 | | | $ | 722 | | | $ | (2) | | | $ | 3,028 | |
| | | | | | | | | | | | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net (loss) income | $ | (2) | | | $ | 2 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
| | | |
Depreciation and amortization | 103 | | | 101 | |
Allowance for equity funds | (3) | | | (1) | |
Changes in regulatory assets and liabilities | (8) | | | (15) | |
Deferred income taxes and amortization of investment tax credits | 5 | | | (10) | |
Deferred energy | (51) | | | 41 | |
Amortization of deferred energy | 13 | | | — | |
Other, net | 4 | | | (1) | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 33 | | | 41 | |
Inventories | 3 | | | 4 | |
Accrued property, income and other taxes | (15) | | | 3 | |
Accounts payable and other liabilities | 3 | | | 14 | |
Net cash flows from operating activities | 85 | | | 179 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (189) | | | (106) | |
| | | |
| | | |
| | | |
Net cash flows from investing activities | (189) | | | (106) | |
| | | |
Cash flows from financing activities: | | | |
Proceeds from long-term debt | 200 | | | — | |
| | | |
Net repayment of short-term debt | (76) | | | — | |
| | | |
| | | |
| | | |
Other, net | (4) | | | (5) | |
Net cash flows from financing activities | 120 | | | (5) | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 16 | | | 68 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 45 | | | 36 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 61 | | | $ | 104 | |
| | | |
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 U.S. 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, 2022 and for the three-month periods ended March 31, 2022 and 2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month period ended March 31, 2022 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, 2021 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, 2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 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 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, |
| 2022 | | 2021 |
Cash and cash equivalents | $ | 47 | | | $ | 33 | |
Restricted cash and cash equivalents included in other current assets | 14 | | | 12 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 61 | | | $ | 45 | |
(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, |
| | 2022 | | 2021 |
Utility plant: | | | | | |
Generation | 30 - 55 years | | $ | 3,810 | | | $ | 3,793 | |
Transmission | 45 - 70 years | | 1,508 | | | 1,503 | |
Distribution | 20 - 65 years | | 3,979 | | | 3,920 | |
General and intangible plant | 5 - 65 years | | 831 | | | 836 | |
Utility plant | | | 10,128 | | | 10,052 | |
Accumulated depreciation and amortization | | | (3,478) | | | (3,406) | |
Utility plant, net | | | 6,650 | | | 6,646 | |
Other non-regulated, net of accumulated depreciation and amortization | 45 years | | 1 | | | 1 | |
Plant, net | | | 6,651 | | | 6,647 | |
Construction work-in-progress | | | 341 | | | 244 | |
Property, plant and equipment, net | | | $ | 6,992 | | | $ | 6,891 | |
(4) Recent Financing Transactions
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
(5) Employee Benefit Plans
Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts 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, |
| 2022 | | 2021 |
Qualified Pension Plan: | | | |
Other non-current assets | $ | 42 | | | $ | 42 | |
| | | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
| | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (8) | | | (8) | |
| | | |
Other Postretirement Plans: | | | |
Other non-current assets | 8 | | | 8 | |
| | | |
| | | |
(6) Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power'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. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power 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, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power 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 Nevada Power's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Derivative | | | | |
| Other | | | | Contracts - | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
| | | | | | | | | |
As of March 31, 2022 | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
| | | | | | | | | |
Commodity liabilities | $ | — | | | | | $ | (88) | | | $ | (80) | | | $ | (168) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | — | | | | | $ | (88) | | | $ | (80) | | | $ | (168) | |
| | | | | | | | | |
As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 4 | | | | | $ | — | | | $ | — | | | $ | 4 | |
Commodity liabilities | — | | | | | (55) | | | (62) | | | (117) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Total derivative - net basis | $ | 4 | | | | | $ | (55) | | | $ | (62) | | | $ | (113) | |
(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2022 a regulatory asset of $168 million was recorded related to the net derivative liability of $168 million. As of December 31, 2021 a regulatory asset of $113 million was recorded related to the net derivative liability of $113 million.
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 | | 2022 | | 2021 |
| | | | | |
Electricity purchases | Megawatt hours | | 3 | | | 1 | |
Natural gas purchases | Decatherms | | 138 | | | 119 | |
| | | | | |
Credit Risk
Nevada Power 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 Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power 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, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power 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 Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2022, Nevada Power'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 Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $7 million and $6 million as of March 31, 2022 and December 31, 2021, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power'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 Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.
The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | |
| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of March 31, 2022: | | | | | | | |
Assets: | | | | | | | |
| | | | | | | |
Money market mutual funds | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 46 | | | $ | — | | | $ | — | | | $ | 46 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (168) | | | $ | (168) | |
| | | | | | | |
As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 4 | | | $ | 4 | |
Money market mutual funds | 34 | | | — | | | — | | | 34 | |
Investment funds | 3 | | | — | | | — | | | 3 | |
| $ | 37 | | | $ | — | | | $ | 4 | | | $ | 41 | |
| | | | | | | |
Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (117) | | | $ | (117) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of March 31, 2022 and December 31, 2021, 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, |
| 2022 | | 2021 |
| | | |
Beginning balance | $ | (113) | | | $ | 15 | |
Changes in fair value recognized in regulatory assets | (56) | | | 11 | |
| | | |
Settlements | 1 | | | 1 | |
Ending balance | $ | (168) | | | $ | 27 | |
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, 2022 | | As of December 31, 2021 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
| | | | | | | |
Long-term debt | $ | 2,700 | | | $ | 2,985 | | | $ | 2,499 | | | $ | 3,067 | |
(8) Commitments and Contingencies
Legal Matters
Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
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.
(9) Revenue from Contracts with Customers
The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):
| | | | | | | | | | | | | | | |
| Three-Month Periods | | |
| Ended March 31, | | |
| 2022 | | 2021 | | | | |
Customer Revenue: | | | | | | | |
Retail: | | | | | | | |
Residential | $ | 214 | | | $ | 196 | | | | | |
Commercial | 96 | | | 84 | | | | | |
Industrial | 78 | | | 63 | | | | | |
Other | 1 | | | 3 | | | | | |
Total fully bundled | 389 | | | 346 | | | | | |
Distribution only service | 5 | | | 5 | | | | | |
Total retail | 394 | | | 351 | | | | | |
Wholesale, transmission and other | 16 | | | 14 | | | | | |
Total Customer Revenue | 410 | | | 365 | | | | | |
Other revenue | 5 | | | 5 | | | | | |
Total revenue | $ | 415 | | | $ | 370 | | | | | |
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 2022 and 2021
Overview
Net loss for the first quarter of 2022 was $2 million, a decrease of $4 million compared to 2021 primarily due to $3 million of lower other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, $2 million of lower utility margin, $2 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher earnings sharing, and $2 million of higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin decreased primarily due to lower regulatory-related revenue deferrals and lower other retail revenue, partially offset by an increase in the average number of customers and favorable changes in customer usage patterns. These decreases are offset by $4 million of higher interest and dividend income, mainly from carrying charges on regulatory balances. Energy generated decreased 6% for the first quarter of 2022 compared to 2021 primarily due to lower natural gas-fueled generation. Wholesale electricity sales volumes increased 49% and purchased electricity volumes increased 30%.
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 | | |
| | 2022 | | 2021 | | Change | | | | | | |
Utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 415 | | | $ | 370 | | | $ | 45 | | 12 | % | | | | | | | |
Cost of fuel and energy | | 212 | | | 165 | | | 47 | | 28 | | | | | | | | |
Utility margin | | 203 | | | 205 | | | (2) | | (1) | | | | | | | | |
Operations and maintenance | | 65 | | | 63 | | | 2 | | 3 | | | | | | | | |
Depreciation and amortization | | 103 | | | 101 | | | 2 | | 2 | | | | | | | | |
Property and other taxes | | 13 | | | 12 | | | 1 | | 8 | | | | | | | | |
Operating income | | $ | 22 | | | $ | 29 | | | $ | (7) | | (24) | % | | | | | | | |
Utility Margin
A comparison of key operating results related to utility margin is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | First Quarter | | |
| | 2022 | | 2021 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 415 | | | $ | 370 | | | $ | 45 | | 12 | % | | | | | | | |
Cost of fuel and energy | | 212 | | | 165 | | | 47 | | 28 | | | | | | | | |
Utility margin | | $ | 203 | | | $ | 205 | | | $ | (2) | | (1) | % | | | | | | | |
| | | | | | | | | | | | | | |
Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 1,585 | | | 1,587 | | | (2) | | — | % | | | | | | | |
Commercial | | 998 | | | 954 | | | 44 | | 5 | | | | | | | | |
Industrial | | 1,175 | | | 1,057 | | | 118 | | 11 | | | | | | | | |
Other | | 46 | | | 47 | | | (1) | | (2) | | | | | | | | |
Total fully bundled(1) | | 3,804 | | | 3,645 | | | 159 | | 4 | | | | | | | | |
Distribution only service | | 569 | | | 516 | | | 53 | | 10 | | | | | | | | |
Total retail | | 4,373 | | | 4,161 | | | 212 | | 5 | | | | | | | | |
Wholesale | | 125 | | | 84 | | | 41 | | 49 | | | | | | | | |
Total GWhs sold | | 4,498 | | | 4,245 | | | 253 | | 6 | % | | | | | | | |
| | | | | | | | | | | | | | |
Average number of retail customers (in thousands) | | 995 | | | 978 | | | 17 | | 2 | % | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 102.11 | | | $ | 95.01 | | | $ | 7.10 | | 7 | % | | | | | | | |
| | | | | | | | | | | | | | |
Wholesale | | $ | 42.91 | | | $ | 49.42 | | | $ | (6.51) | | (13) | % | | | | | | | |
| | | | | | | | | | | | | | |
Heating degree days | | 954 | | | 994 | | | (40) | | (4) | % | | | | | | | |
Cooling degree days | | 49 | | | 6 | | | 43 | | * | | | | | | | |
| | | | | | | | | | | | | | |
Sources of energy (GWhs)(2)(3): | | | | | | | | | | | | | | |
Natural gas | | 2,378 | | | 2,534 | | | (156) | | (6) | % | | | | | | | |
| | | | | | | | | | | | | | |
Renewables | | 14 | | | 16 | | | (2) | | (13) | | | | | | | | |
Total energy generated | | 2,392 | | | 2,550 | | | (158) | | (6) | | | | | | | | |
Energy purchased | | 1,761 | | | 1,355 | | | 406 | | 30 | | | | | | | | |
Total | | 4,153 | | | 3,905 | | | 248 | | 6 | % | | | | | | | |
| | | | | | | | | | | | | | |
Average cost of energy per MWh(4): | | | | | | | | | | | | | | |
Energy generated | | $ | 41.92 | | | $ | 14.96 | | | $ | 26.96 | | * | | | | | | | |
Energy purchased | | $ | 63.27 | | | $ | 93.84 | | | $ | (30.57) | | (33) | % | | | | | | | |
* 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 424 GWhs and 683 GWhs of gas generated energy that is purchased at cost by related parties for the first quarter of 2022 and 2021, respectively.
(3) GWh amounts are net of energy used by the related generating facilities.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Quarter Ended March 31, 2022 Compared to Quarter Ended March 31, 2021
Utility margin decreased $2 million, or 1%, for the first quarter of 2022 compared to 2021 primarily due to:
•$2 million of lower energy efficiency program rates (offset in operations and maintenance expense);
•$2 million of lower regulatory-related revenue deferrals; and
•$2 million of lower other retail revenue.
The decrease in utility margin was offset by:
•$3 million of higher electric retail utility margin primarily due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 5.1% primarily due to an increase in the average number of customers and favorable changes in customer usage patterns, offset by the unfavorable impact of weather; and
•$1 million of higher transmission and wholesale revenue.
Operations and maintenance increased $2 million, or 3%, for the first quarter of 2022 compared to 2021 primarily due to higher plant operations and maintenance expenses and higher earnings sharing, partially offset by lower energy efficiency program costs (offset in operating revenue).
Depreciation and amortization increased $2 million, or 2%, for the first quarter of 2022 compared to 2021 primarily due to higher plant placed in-service.
Interest and dividend income increased $4 million, or 80%, for the first quarter of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $3 million, or 75%, for the first quarter of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies.
Liquidity and Capital Resources
As of March 31, 2022, Nevada Power's total net liquidity was as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 47 | |
Credit facility | | 400 | |
Less - | | |
Short-term debt | | (104) | |
Net credit facility | | 296 | |
| | |
Delayed draw term loan facility | | $ | 300 | |
Less - | | |
Long-term debt | | (200) | |
Net delayed draw term loan facility | | 100 | |
| | |
Total net liquidity | | $ | 443 | |
Credit facility and delayed draw term loan facility: | | |
Maturity date | | 2024 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021 were $85 million and $179 million, respectively. The change was primarily due to higher payments related to fuel and energy costs and the timing of payments for operating costs, partially offset by higher collections from customers.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021 were $(189) million and $(106) 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, 2022 and 2021 were $120 million and $(5) million, respectively. The change was primarily due to higher proceeds from the issuance of long-term debt, partially offset by higher repayments of short-term debt.
Long-Term Debt
In January 2022, Nevada Power entered into a $300 million secured delayed draw term loan facility maturing in January 2024. Amounts borrowed under the facility bear interest at variable rates based on the Secured Overnight Financing Rate or a base rate, at Nevada Power's option, plus a pricing margin. In January 2022, Nevada Power borrowed $200 million under the facility at an initial interest rate of 0.55%. Nevada Power may draw all or none of the remaining unused commitment through June 2022. Nevada Power used the proceeds to repay amounts outstanding under its existing secured credit facility and for general corporate purposes.
Debt Authorizations
Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.8 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.
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 |
| 2021 | | 2022 | | 2022 |
| | | | | |
Electric distribution | $ | 41 | | | $ | 51 | | | $ | 223 | |
Electric transmission | 13 | | | 21 | | | 168 | |
Solar generation | 1 | | | 7 | | | 80 | |
Other | 51 | | | 110 | | | 386 | |
Total | $ | 106 | | | $ | 189 | | | $ | 857 | |
Nevada Power received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission. Nevada Power has included estimates from its latest IRP filing in its forecast capital expenditures for 2022. These estimates may change as a result of the RFP process. 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 received approval from the PUCN 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; 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 Robinson Summit substations. 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-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2021.
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, 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. Nevada Power 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 Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated 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, 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, 2021. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2021.
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, 2022, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2022 and 2021, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2021, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 25, 2022, 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, 2021, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
Basis for Review Results
This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
April 29, 2022
SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2022 | | 2021 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 15 | | | $ | 10 | |
Trade receivables, net | 120 | | | 128 | |
| | | |
Inventories | 71 | | | 65 | |
| | | |
Regulatory assets | 164 | | | 177 | |
| | | |
Other current assets | 36 | | | 35 | |
Total current assets | 406 | | | 415 | |
| | | |
Property, plant and equipment, net | 3,386 | | | 3,340 | |
| | | |
Regulatory assets | 282 | | | 263 | |
Other assets | 205 | | | 205 | |
| | | |
Total assets | $ | 4,279 | | | $ | 4,223 | |
| | | |
LIABILITIES AND SHAREHOLDER'S EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 125 | | | $ | 147 | |
| | | |
Accrued property, income and other taxes | 28 | | | 16 | |
Short-term debt | 57 | | | 159 | |
| | | |
| | | |
Regulatory liabilities | 20 | | | 19 | |
Customer deposits | 16 | | | 15 | |
Derivative contracts | 28 | | | 16 | |
Other current liabilities | 39 | | | 42 | |
Total current liabilities | 313 | | | 414 | |
| | | |
Long-term debt | 1,164 | | | 1,164 | |
| | | |
Regulatory liabilities | 440 | | | 444 | |
Deferred income taxes | 401 | | | 402 | |
Other long-term liabilities | 268 | | | 264 | |
Total liabilities | 2,586 | | | 2,688 | |
| | | |
Commitments and contingencies (Note 9) | | | |
| | | |
Shareholder's equity: | | | |
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | | | — | |
Additional paid-in capital | 1,241 | | | 1,111 | |
Retained earnings | 453 | | | 425 | |
Accumulated other comprehensive loss, net | (1) | | | (1) | |
Total shareholder's equity | 1,693 | | | 1,535 | |
| | | |
Total liabilities and shareholder's equity | $ | 4,279 | | | $ | 4,223 | |
| | | |
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, |
| | | | | 2022 | | 2021 |
Operating revenue: | | | | | | | |
Regulated electric | | | | | $ | 227 | | | $ | 181 | |
Regulated natural gas | | | | | 52 | | | 39 | |
Total operating revenue | | | | | 279 | | | 220 | |
| | | | | | | |
Operating expenses: | | | | | | | |
Cost of fuel and energy | | | | | 124 | | | 82 | |
Cost of natural gas purchased for resale | | | | | 34 | | | 21 | |
Operations and maintenance | | | | | 41 | | | 36 | |
Depreciation and amortization | | | | | 36 | | | 36 | |
Property and other taxes | | | | | 6 | | | 6 | |
Total operating expenses | | | | | 241 | | | 181 | |
| | | | | | | |
Operating income | | | | | 38 | | | 39 | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | | | | | (13) | | | (14) | |
Allowance for borrowed funds | | | | | 1 | | | — | |
Allowance for equity funds | | | | | 2 | | | 1 | |
Interest and dividend income | | | | | 3 | | | 2 | |
Other, net | | | | | 2 | | | 4 | |
Total other income (expense) | | | | | (5) | | | (7) | |
| | | | | | | |
Income before income tax expense | | | | | 33 | | | 32 | |
Income tax expense | | | | | 5 | | | 4 | |
Net income | | | | | $ | 28 | | | $ | 28 | |
| | | | | | | |
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, 2020 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 301 | | | $ | (1) | | | $ | 1,411 | |
Net income | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, March 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 329 | | | $ | (1) | | | $ | 1,439 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Balance, December 31, 2021 | | 1,000 | | | $ | — | | | $ | 1,111 | | | $ | 425 | | | $ | (1) | | | $ | 1,535 | |
Net income | | — | | | — | | | — | | | 28 | | | — | | | 28 | |
| | | | | | | | | | | | |
Contributions | | — | | | — | | | 130 | | | — | | | — | | | 130 | |
| | | | | | | | | | | | |
Balance, March 31, 2022 | | 1,000 | | | $ | — | | | $ | 1,241 | | | $ | 453 | | | $ | (1) | | | $ | 1,693 | |
| | | | | | | | | | | | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net income | $ | 28 | | | $ | 28 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
Depreciation and amortization | 36 | | | 36 | |
Allowance for equity funds | (2) | | | (1) | |
Changes in regulatory assets and liabilities | (4) | | | (13) | |
Deferred income taxes and amortization of investment tax credits | (3) | | | 4 | |
Deferred energy | (7) | | | (18) | |
Amortization of deferred energy | 23 | | | (3) | |
| | | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 12 | | | 8 | |
Inventories | (6) | | | 3 | |
Accrued property, income and other taxes | 7 | | | (3) | |
Accounts payable and other liabilities | (21) | | | 1 | |
Net cash flows from operating activities | 63 | | | 42 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (83) | | | (61) | |
| | | |
| | | |
Net cash flows from investing activities | (83) | | | (61) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
Net (repayment of) proceeds from short-term debt | (102) | | | 10 | |
| | | |
| | | |
Contributions from parent | 130 | | | — | |
Other, net | (2) | | | (2) | |
Net cash flows from financing activities | 26 | | | 8 | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 6 | | | (11) | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 16 | | | 26 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 22 | | | $ | 15 | |
| | | |
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 U.S. 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, 2022 and for the three-month periods ended March 31, 2022 and 2021. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month period ended March 31, 2022 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, 2021 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, 2022.
(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 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 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, |
| 2022 | | 2021 |
Cash and cash equivalents | $ | 15 | | | $ | 10 | |
Restricted cash and cash equivalents included in other current assets | 7 | | | 6 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 22 | | | $ | 16 | |
(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, |
| | 2022 | | 2021 |
Utility plant: | | | | | |
Electric generation | 25 - 60 years | | $ | 1,169 | | | $ | 1,163 | |
Electric transmission | 50 - 100 years | | 937 | | | 940 | |
Electric distribution | 20 - 100 years | | 1,885 | | | 1,846 | |
Electric general and intangible plant | 5 - 70 years | | 206 | | | 204 | |
Natural gas distribution | 35 - 70 years | | 445 | | | 438 | |
Natural gas general and intangible plant | 5 - 70 years | | 14 | | | 14 | |
Common general | 5 - 70 years | | 370 | | | 370 | |
Utility plant | | | 5,026 | | | 4,975 | |
Accumulated depreciation and amortization | | | (1,878) | | | (1,854) | |
Utility plant, net | | | 3,148 | | | 3,121 | |
| | | | | |
| | | | | |
Construction work-in-progress | | | 238 | | | 219 | |
Property, plant and equipment, net | | | $ | 3,386 | | | $ | 3,340 | |
(4) Recent Financing Transactions
Long-Term Debt
In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the London Interbank Offer Rate market plus a spread of 0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
| | | | | | | | | | | | | | | |
| Three-Month Periods | | |
| Ended March 31, | | |
| 2022 | | 2021 | | | | |
| | | | | | | |
Federal statutory income tax rate | 21 | % | | 21 | % | | | | |
Effects of ratemaking | (7) | | | (10) | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Other | 1 | | | 2 | | | | | |
Effective income tax rate | 15 | % | | 13 | % | | | | |
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.
(6) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $2 million to the Other Postretirement Plans for the three-month period ended March 31, 2022. 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, |
| 2022 | | 2021 |
Qualified Pension Plan: | | | |
| | | |
Other non-current assets | $ | 63 | | | $ | 62 | |
| | | |
| | | |
| | | |
Non-Qualified Pension Plans: | | | |
| | | |
| | | |
Other current liabilities | (1) | | | (1) | |
Other long-term liabilities | (7) | | | (7) | |
| | | |
Other Postretirement Plans: | | | |
| | | |
| | | |
| | | |
Other long-term liabilities | (8) | | | (10) | |
(7) Risk Management and Hedging Activities
Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific'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. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.
Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific 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, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific 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 Sierra Pacific's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
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| | | | | Derivative | | | | |
| Other | | | | Contracts - | | Other | | |
| Current | | | | Current | | Long-term | | |
| Assets | | | | Liabilities | | Liabilities | | Total |
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As of March 31, 2022 | | | | | | | | | |
Not designated as hedging contracts (1): | | | | | | | | | |
Commodity assets | $ | 1 | | | | | $ | — | | | $ | — | | | $ | 1 | |
Commodity liabilities | — | | | | | (28) | | | (25) | | | (53) | |
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Total derivative - net basis | $ | 1 | | | | | $ | (28) | | | $ | (25) | | | $ | (52) | |
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As of December 31, 2021 | | | | | | | | | |
Not designated as hedging contracts(1): | | | | | | | | | |
Commodity assets | $ | 2 | | | | | $ | — | | | $ | — | | | $ | 2 | |
Commodity liabilities | — | | | | | (16) | | | (19) | | | (35) | |
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Total derivative - net basis | $ | 2 | | | | | $ | (16) | | | $ | (19) | | | $ | (33) | |
(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2022 a net regulatory asset of $52 million was recorded related to the net derivative liability of $52 million. As of December 31, 2021 a net regulatory asset of $33 million was recorded related to the net derivative liability of $33 million.
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):
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| Unit of | | March 31, | | December 31, |
| Measure | | 2022 | | 2021 |
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Electricity purchases | Megawatt hours | | 1 | | | 1 | |
Natural gas purchases | Decatherms | | 60 | | | 53 | |
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Credit Risk
Sierra Pacific 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 Sierra Pacific's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific 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, Sierra Pacific enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific 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 Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2022, Sierra Pacific'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 Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $2 million and $— million as of March 31, 2022 and December 31, 2021, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
(8) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.
The following table presents Sierra Pacific's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
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| Input Levels for Fair Value Measurements | | |
| Level 1 | | Level 2 | | Level 3 | | Total |
As of March 31, 2022: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 1 | | | $ | 1 | |
Money market mutual funds | 13 | | | — | | | — | | | 13 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 14 | | | $ | — | | | $ | 1 | | | $ | 15 | |
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Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (53) | | | $ | (53) | |
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As of December 31, 2021: | | | | | | | |
Assets: | | | | | | | |
Commodity derivatives | $ | — | | | $ | — | | | $ | 2 | | | $ | 2 | |
Money market mutual funds | 10 | | | — | | | — | | | 10 | |
Investment funds | 1 | | | — | | | — | | | 1 | |
| $ | 11 | | | $ | — | | | $ | 2 | | | $ | 13 | |
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Liabilities - commodity derivatives | $ | — | | | $ | — | | | $ | (35) | | | $ | (35) | |
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.
The following table reconciles the beginning and ending balances of Sierra Pacific's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
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| Three-Month Periods |
| Ended March 31, |
| 2022 | | 2021 |
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Beginning balance | $ | (33) | | | $ | 7 | |
Changes in fair value recognized in regulatory assets | (19) | | | 5 | |
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Ending balance | $ | (52) | | | $ | 12 | |
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):
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| As of March 31, 2022 | | As of December 31, 2021 |
| Carrying | | Fair | | Carrying | | Fair |
| Value | | Value | | Value | | Value |
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Long-term debt | $ | 1,164 | | | $ | 1,261 | | | $ | 1,164 | | | $ | 1,316 | |
(9) Commitments and Contingencies
Legal Matters
Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.
(10) Revenue from Contracts with Customers
The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 11 (in millions):
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| Three-Month Periods |
| Ended March 31, |
| 2022 | | 2021 |
| Electric | | Natural Gas | | Total | | Electric | | Natural Gas | | Total |
Customer Revenue: | | | | | | | | | | | |
Retail: | | | | | | | | | | | |
Residential | $ | 85 | | | $ | 32 | | | $ | 117 | | | $ | 71 | | | $ | 25 | | | $ | 96 | |
Commercial | 70 | | | 15 | | | 85 | | | 54 | | | 10 | | | 64 | |
Industrial | 49 | | | 4 | | | 53 | | | 39 | | | 3 | | | 42 | |
Other | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
Total fully bundled | 205 | | | 51 | | | 256 | | | 165 | | | 38 | | | 203 | |
Distribution only service | 1 | | | — | | | 1 | | | 1 | | | — | | | 1 | |
Total retail | 206 | | | 51 | | | 257 | | | 166 | | | 38 | | | 204 | |
Wholesale, transmission and other | 21 | | | — | | | 21 | | | 15 | | | — | | | 15 | |
Total Customer Revenue | 227 | | | 51 | | | 278 | | | 181 | | | 38 | | | 219 | |
Other revenue | — | | | 1 | | | 1 | | | — | | | 1 | | | 1 | |
Total revenue | $ | 227 | | | $ | 52 | | | $ | 279 | | | $ | 181 | | | $ | 39 | | | $ | 220 | |
(11) Segment Information
Sierra Pacific has identified two 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, | | |
| 2022 | | 2021 | | | | |
Operating revenue: | | | | | | | |
Regulated electric | $ | 227 | | | $ | 181 | | | | | |
Regulated natural gas | 52 | | | 39 | | | | | |
Total operating revenue | $ | 279 | | | $ | 220 | | | | | |
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Operating income: | | | | | | | |
Regulated electric | $ | 30 | | | $ | 31 | | | | | |
Regulated natural gas | 8 | | | 8 | | | | | |
Total operating income | 38 | | | 39 | | | | | |
Interest expense | (13) | | | (14) | | | | | |
Allowance for borrowed funds | 1 | | | — | | | | | |
Allowance for equity funds | 2 | | | 1 | | | | | |
Interest and dividend income | 3 | | | 2 | | | | | |
Other, net | 2 | | | 4 | | | | | |
Income before income tax expense | $ | 33 | | | $ | 32 | | | | | |
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| | | As of |
| | | | | March 31, | | December 31, |
| | | | | 2022 | | 2021 |
Assets: | | | | | | | |
Regulated electric | | | | | $ | 3,869 | | | $ | 3,829 | |
Regulated natural gas | | | | | 375 | | | 365 | |
Other(1) | | | | | 35 | | | 29 | |
Total assets | | | | | $ | 4,279 | | | $ | 4,223 | |
(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 Quarter of 2022 and 2021
Overview
Net income for the first quarter of 2022 was $28 million, consistent when compared to 2021 primarily due to $5 million of higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher earnings sharing, and $2 million of lower other, net, mainly due to lower cash surrender value of corporate-owned life insurance policies, partially offset by $4 million of higher electric utility margin, mainly from higher transmission and wholesale revenue, partially offset by lower regulatory-related revenue deferrals, higher allowance for equity funds, mainly due to higher construction work-in-progress, and higher interest and dividend income, mainly from carrying charges on regulatory balances. Energy generated increased 3% for the first quarter of 2022 compared to 2021 primarily due to higher coal-fueled generation, partially offset by lower natural gas-fueled generation. Wholesale electricity sales volumes increased 66% and purchased electricity volumes decreased 25%.
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 | | |
| | 2022 | | 2021 | | Change | | | | | | |
Electric utility margin: | | | | | | | | | | | | | | |
Operating revenue | | $ | 227 | | | $ | 181 | | | $ | 46 | | 25 | % | | | | | | | |
Cost of fuel and energy | | 124 | | | 82 | | | 42 | | 51 | | | | | | | | |
Electric utility margin | | 103 | | | 99 | | | 4 | | 4 | | | | | | | | |
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Natural gas utility margin: | | | | | | | | | | | | | | |
Operating revenue | | 52 | | | 39 | | | 13 | | 33 | % | | | | | | | |
Natural gas purchased for resale | | 34 | | | 21 | | | 13 | | 62 | | | | | | | | |
Natural gas utility margin | | 18 | | | 18 | | | — | | — | | | | | | | | |
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Utility margin | | 121 | | | 117 | | | 4 | | 3 | % | | | | | | | |
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Operations and maintenance | | 41 | | | 36 | | | 5 | | 14 | % | | | | | | | |
Depreciation and amortization | | 36 | | | 36 | | | — | | — | | | | | | | | |
Property and other taxes | | 6 | | | 6 | | | — | | — | | | | | | | | |
Operating income | | $ | 38 | | | $ | 39 | | | $ | (1) | | (3) | % | | | | | | | |
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows:
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| | First Quarter | | |
| | 2022 | | 2021 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 227 | | | $ | 181 | | | $ | 46 | | 25 | % | | | | | | | |
Cost of fuel and energy | | 124 | | | 82 | | | 42 | | 51 | | | | | | | | |
Utility margin | | $ | 103 | | | $ | 99 | | | $ | 4 | | 4 | % | | | | | | | |
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Sales (GWhs): | | | | | | | | | | | | | | |
Residential | | 663 | | | 671 | | | (8) | | (1) | % | | | | | | | |
Commercial | | 700 | | | 677 | | | 23 | | 3 | | | | | | | | |
Industrial | | 755 | | | 897 | | | (142) | | (16) | | | | | | | | |
Other | | 4 | | | 4 | | | — | | — | | | | | | | | |
Total fully bundled(1) | | 2,122 | | | 2,249 | | | (127) | | (6) | | | | | | | | |
Distribution only service | | 585 | | | 397 | | | 188 | | 47 | | | | | | | | |
Total retail | | 2,707 | | | 2,646 | | | 61 | | 2 | | | | | | | | |
Wholesale | | 291 | | | 175 | | | 116 | | 66 | | | | | | | | |
Total GWhs sold | | 2,998 | | | 2,821 | | | 177 | | 6 | % | | | | | | | |
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Average number of retail customers (in thousands) | | 369 | | | 363 | | | 6 | | 2 | % | | | | | | | |
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Average revenue per MWh: | | | | | | | | | | | | | | |
Retail - fully bundled(1) | | $ | 96.40 | | | $ | 73.17 | | | $ | 23.23 | | 32 | % | | | | | | | |
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Wholesale | | $ | 51.14 | | | $ | 60.18 | | | $ | (9.04) | | (15) | % | | | | | | | |
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Heating degree days | | 2,037 | | 2,198 | | (161) | | (7) | % | | | | | | | |
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Sources of energy (GWhs)(2): | | | | | | | | | | | | | | |
Natural gas | | 990 | | | 1,082 | | | (92) | | (9) | % | | | | | | | |
Coal | | 153 | | | 29 | | | 124 | | * | | | | | | | |
Renewables(3) | | 5 | | | 6 | | | (1) | | (17) | | | | | | | | |
Total energy generated | | 1,148 | | | 1,117 | | | 31 | | 3 | | | | | | | | |
Energy purchased | | 1,033 | | | 1,373 | | | (340) | | (25) | | | | | | | | |
Total | | 2,181 | | | 2,490 | | | (309) | | (12) | % | | | | | | | |
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Average cost of energy per MWh(4): | | | | | | | | | | | | | | |
Energy generated | | $ | 59.86 | | | $ | 25.23 | | | $ | 34.63 | | * | | | | | | | |
Energy purchased | | $ | 53.19 | | | $ | 38.93 | | | $ | 14.26 | | 37 | % | | | | | | | |
* Not meaningful
(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 was under lease by Sierra Pacific until it was acquired in December 2021.
(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows:
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| | First Quarter | | |
| | 2022 | | 2021 | | Change | | | | | | |
Utility margin (in millions): | | | | | | | | | | | | | | |
Operating revenue | | $ | 52 | | | $ | 39 | | | $ | 13 | | 33 | % | | | | | | | |
Natural gas purchased for resale | | 34 | | | 21 | | | 13 | | 62 | | | | | | | | |
Utility margin | | $ | 18 | | | $ | 18 | | | $ | — | | — | % | | | | | | | |
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Sold (000's Dths): | | | | | | | | | | | | | | |
Residential | | 4,552 | | | 4,658 | | | (106) | | (2) | % | | | | | | | |
Commercial | | 2,512 | | | 2,304 | | | 208 | | 9 | | | | | | | | |
Industrial | | 653 | | | 745 | | | (92) | | (12) | | | | | | | | |
Total retail | | 7,717 | | | 7,707 | | | 10 | | — | % | | | | | | | |
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Average number of retail customers (in thousands) | | 179 | | | 176 | | | 3 | | 2 | % | | | | | | | |
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Average revenue per retail Dth sold | | $ | 6.69 | | | $ | 5.03 | | | $ | 1.66 | | 33 | % | | | | | | | |
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Heating degree days | | 2,037 | | | 2,198 | | | (161) | | (7) | % | | | | | | | |
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Average cost of natural gas per retail Dth sold | | $ | 4.36 | | | $ | 2.73 | | | $ | 1.63 | | 60 | % | | | | | | | |
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Quarter Ended March 31, 2022 Compared to Quarter Ended March 31, 2021
Electric utility margin increased $4 million, or 4%, for the first quarter of 2022 compared to 2021 primarily due to:
•$3 million of higher transmission and wholesale revenue;
•$2 million of higher energy efficiency implementation rates; and
•$1 million of higher electric retail utility margin primarily due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 2.3% primarily due to an increase in the average number of customers, offset by the unfavorable impact of weather.
The increase in utility margin was offset by:
•$1 million of lower regulatory-related revenue deferrals; and
•$1 million of lower energy efficiency programs rates (offset in operations and maintenance expense).
Operations and maintenance increased $5 million, or 14%, for the first quarter of 2022 compared to 2021 primarily due to higher plant operations and maintenance expenses and higher earnings sharing, partially offset by lower energy efficiency program costs (offset in operating revenue).
Allowance for equity funds increased $1 million for the first quarter of 2022 compared to 2021 primarily due to higher construction work-in progress.
Interest and dividend income increased $1 million for the first quarter of 2022 compared to 2021 primarily due to higher interest income, mainly from carrying charges on regulatory balances.
Other, net decreased $2 million, or 50%, for the first quarter of 2022 compared to 2021 primarily due to lower cash surrender value of corporate-owned life insurance policies.
Income tax expense increased $1 million, or 25%, for the first quarter of 2022 compared to 2021 primarily due to higher pretax income. The effective tax rate was 15% in 2022 and 13% in 2021.
Liquidity and Capital Resources
As of March 31, 2022, Sierra Pacific's total net liquidity was as follows (in millions):
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Cash and cash equivalents | | $ | 15 | |
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Credit facility | | 250 | |
Less - | | |
| | |
Short-term debt | | (57) | |
Net credit facility | | 193 | |
| | |
Total net liquidity | | $ | 208 | |
Credit facility: | | |
Maturity date | | 2024 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021 were $63 million and $42 million, respectively. The change was primarily due to higher collections from customers, partially offset by higher payments related to fuel and energy costs, higher inventory purchases and the timing of payments for operating costs.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021 were $(83) million and $(61) 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, 2022 and 2021 were $26 million and $8 million, respectively. The change was primarily due to contributions from NV Energy, Inc., partially offset by higher repayments of short-term debt.
Long-Term Debt
In April 2022, Sierra Pacific entered into a $200 million unsecured loan with NV Energy payable upon demand. The net proceeds were used to purchase certain tax-exempt refunding revenue bond obligations that were subject to mandatory purchase by Sierra Pacific in April 2022. The loan has an underlying variable interest rate based on 30-day U.S. dollar deposits offered on the London Interbank Offer Rate market plus a spread of 0.75%.
In April 2022, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036; and $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029. Sierra Pacific purchased these bonds as required by the bond indentures. Sierra Pacific is holding these bonds and can re-offer them at a future date.
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 $1.9 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.
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 |
| 2021 | | 2022 | | 2022 |
| | | | | |
| | | | | |
Electric distribution | $ | 20 | | | $ | 20 | | | $ | 125 | |
Electric transmission | 16 | | | 20 | | | 128 | |
Solar generation | — | | | — | | | 1 | |
Other | 25 | | | 43 | | | 171 | |
Total | $ | 61 | | | $ | 83 | | | $ | 425 | |
Sierra Pacific received PUCN approval through its recent IRP filings for an increase in solar generation and electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its forecast capital expenditures for 2022. These estimates may change as a result of the RFP process. 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 received approval from the PUCN 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; 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 Robinson Summit substations. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.
•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2021.
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, 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. Sierra Pacific 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 Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and consolidated 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, 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, 2021. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2021.
Eastern Energy Gas Holdings, LLC and its subsidiaries
Consolidated Financial Section
PART I
Item 1.Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Eastern Energy Gas Holdings, LLC
Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of March 31, 2022, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2022 and 2021, 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, 2021, 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 25, 2022, 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, 2021, 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 29, 2022
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
| | | | | | | | | | | |
| As of |
| March 31, 2022 | | December 31, 2021 |
ASSETS |
Current assets: | | | |
Cash and cash equivalents | $ | 54 | | | $ | 22 | |
| | | |
Trade receivables, net | 154 | | | 183 | |
Receivables from affiliates | 32 | | | 47 | |
| | | |
Notes receivable from affiliates | 122 | | | 7 | |
Other receivables | 3 | | | 9 | |
Inventories | 124 | | | 122 | |
| | | |
Natural gas imbalances | 105 | | | 100 | |
Other current assets | 132 | | | 131 | |
Total current assets | 726 | | | 621 | |
| | | |
Property, plant and equipment, net | 10,183 | | | 10,200 | |
Goodwill | 1,286 | | | 1,286 | |
| | | |
Investments | 423 | | | 412 | |
| | | |
Other assets | 122 | | | 129 | |
| | | |
Total assets | $ | 12,740 | | | $ | 12,648 | |
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, 2022 | | December 31, 2021 |
LIABILITIES AND EQUITY |
Current liabilities: | | | |
Accounts payable | $ | 42 | | | $ | 79 | |
Accounts payable to affiliates | 13 | | | 38 | |
Accrued interest | 54 | | | 19 | |
Accrued property, income and other taxes | 59 | | | 89 | |
Accrued employee expenses | 21 | | | 13 | |
| | | |
Regulatory liabilities | 44 | | | 40 | |
| | | |
| | | |
Other current liabilities | 110 | | | 87 | |
Total current liabilities | 343 | | | 365 | |
| | | |
Long-term debt | 3,899 | | | 3,906 | |
| | | |
| | | |
Regulatory liabilities | 645 | | | 645 | |
| | | |
Other long-term liabilities | 263 | | | 238 | |
Total liabilities | 5,150 | | | 5,154 | |
| | | |
Commitments and contingencies (Note 8) | | | |
| | | |
Equity: | | | |
Member's equity: | | | |
| | | |
Membership interests | 3,595 | | | 3,501 | |
| | | |
| | | |
Accumulated other comprehensive loss, net | (38) | | | (43) | |
Total member's equity | 3,557 | | | 3,458 | |
Noncontrolling interests | 4,033 | | | 4,036 | |
Total equity | 7,590 | | | 7,494 | |
| | | |
Total liabilities and equity | $ | 12,740 | | | $ | 12,648 | |
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, | | |
| 2022 | | 2021 | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Operating revenue | $ | 482 | | | $ | 486 | | | | | |
| | | | | | | |
Operating expenses: | | | | | | | |
| | | | | | | |
Excess gas | (1) | | | — | | | | | |
Operations and maintenance | 118 | | | 124 | | | | | |
Depreciation and amortization | 85 | | | 80 | | | | | |
Property and other taxes | 29 | | | 39 | | | | | |
| | | | | | | |
Total operating expenses | 231 | | | 243 | | | | | |
| | | | | | | |
Operating income | 251 | | | 243 | | | | | |
| | | | | | | |
Other income (expense): | | | | | | | |
Interest expense | (36) | | | (44) | | | | | |
| | | | | | | |
Allowance for equity funds | 2 | | | 2 | | | | | |
| | | | | | | |
| | | | | | | |
Other, net | (1) | | | 1 | | | | | |
Total other income (expense) | (35) | | | (41) | | | | | |
| | | | | | | |
Income before income tax expense and equity income | 216 | | | 202 | | | | | |
Income tax expense | 30 | | | 27 | | | | | |
Equity income | 19 | | | 16 | | | | | |
| | | | | | | |
| | | | | | | |
Net income | 205 | | | 191 | | | | | |
Net income attributable to noncontrolling interests | 111 | | | 102 | | | | | |
Net income attributable to Eastern Energy Gas | $ | 94 | | | $ | 89 | | | | | |
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, | | |
| 2022 | | 2021 | | | | |
| | | | | | | |
Net income | $ | 205 | | | $ | 191 | | | | | |
| | | | | | | |
Other comprehensive income, net of tax: | | | | | | | |
Unrecognized amounts on retirement benefits, net of tax of $— and $— | 1 | | | 2 | | | | | |
| | | | | | | |
| | | | | | | |
Unrealized gains on cash flow hedges, net of tax of $1 and $3 | 4 | | | 10 | | | | | |
Total other comprehensive income, net of tax | 5 | | | 12 | | | | | |
| | | | | | | |
Comprehensive income | 210 | | | 203 | | | | | |
Comprehensive income attributable to noncontrolling interests | 111 | | | 106 | | | | | |
Comprehensive income attributable to Eastern Energy Gas | $ | 99 | | | $ | 97 | | | | | |
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, 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 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, December 31, 2021 | | | | | | | | | $ | 3,501 | | | $ | (43) | | | $ | 4,036 | | | $ | 7,494 | |
Net income | | | | | | | | | 94 | | | — | | | 111 | | | 205 | |
Other comprehensive income | | | | | | | | | — | | | 5 | | | — | | | 5 | |
| | | | | | | | | | | | | | | |
Distributions | | | | | | | | | — | | | — | | | (114) | | | (114) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Balance, March 31, 2022 | | | | | | | | | $ | 3,595 | | | $ | (38) | | | $ | 4,033 | | | $ | 7,590 | |
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, |
| 2022 | | 2021 |
Cash flows from operating activities: | | | |
Net income | $ | 205 | | | $ | 191 | |
Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| | | |
Losses on other items, net | 1 | | | — | |
Depreciation and amortization | 85 | | | 80 | |
Allowance for equity funds | (2) | | | (2) | |
Equity income, net of distributions | (8) | | | (5) | |
Changes in regulatory assets and liabilities | (14) | | | 6 | |
Deferred income taxes | 27 | | | 30 | |
Other, net | 2 | | | — | |
Changes in other operating assets and liabilities: | | | |
Trade receivables and other assets | 44 | | | (56) | |
Derivative collateral, net | 2 | | | 2 | |
| | | |
Accrued property, income and other taxes | (29) | | | (25) | |
Accounts payable and other liabilities | 28 | | | 20 | |
Net cash flows from operating activities | 341 | | | 241 | |
| | | |
Cash flows from investing activities: | | | |
Capital expenditures | (75) | | | (55) | |
| | | |
| | | |
Repayment of loans by affiliates | 3 | | | — | |
Loans to affiliates | (117) | | | — | |
| | | |
Other, net | (5) | | | (1) | |
Net cash flows from investing activities | (194) | | | (56) | |
| | | |
Cash flows from financing activities: | | | |
| | | |
| | | |
| | | |
Repayment of notes payable, net | — | | | (9) | |
| | | |
| | | |
| | | |
Distributions | (114) | | | (109) | |
| | | |
| | | |
Net cash flows from financing activities | (114) | | | (118) | |
| | | |
| | | |
| | | |
Net change in cash and cash equivalents and restricted cash and cash equivalents | 33 | | | 67 | |
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period | 39 | | | 48 | |
Cash and cash equivalents and restricted cash and cash equivalents at end of period | $ | 72 | | | $ | 115 | |
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
Eastern Energy Gas Holdings, LLC is a holding company, and together with its subsidiaries ("Eastern Energy Gas") 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 U.S. 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. Eastern Energy Gas 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 the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2022 and for the three-month periods ended March 31, 2022 and 2021. The results of operations for the three-month period ended March 31, 2022 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2022.
(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 | | 2022 | | 2021 |
Utility Plant: | | | | | |
| | | | | |
Interstate natural gas pipeline assets | 21 - 44 years | | $ | 8,776 | | | $ | 8,675 | |
Intangible plant | 5 - 10 years | | 110 | | | 110 | |
Utility plant in-service | | | 8,886 | | | 8,785 | |
Accumulated depreciation and amortization | | | (2,936) | | | (2,901) | |
Utility plant in-service, net | | | 5,950 | | | 5,884 | |
| | | | | |
Nonutility Plant: | | | | | |
| | | | | |
LNG facility | 40 years | | 4,477 | | | 4,475 | |
Intangible plant | 14 years | | 25 | | | 25 | |
Nonutility plant in-service | | | 4,502 | | | 4,500 | |
Accumulated depreciation and amortization | | | (454) | | | (423) | |
Nonutility plant in-service, net | | | 4,048 | | | 4,077 | |
Plant, net | | | 9,998 | | | 9,961 | |
Construction work-in-progress | | | 185 | | | 239 | |
Property, plant and equipment, net | | | $ | 10,183 | | | $ | 10,200 | |
Construction work-in-progress includes $151 million and $209 million as of March 31, 2022 and December 31, 2021, respectively, related to the construction of utility plant.
(3) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following (in millions):
| | | | | | | | | | | |
| As of |
| March 31, | | December 31, |
| 2022 | | 2021 |
Investments: | | | |
Investment funds | $ | 15 | | | $ | 13 | |
| | | |
| | | |
Equity method investments: | | | |
Iroquois | 408 | | | 399 | |
| | | |
| | | |
Total investments | 423 | | | 412 | |
| | | |
Restricted cash and cash equivalents: | | | |
Customer deposits | 18 | | | 17 | |
Total restricted cash and cash equivalents | 18 | | | 17 | |
| | | |
Total investments and restricted cash and cash equivalents | $ | 441 | | | $ | 429 | |
| | | |
Reflected as: | | | |
Current assets | $ | 18 | | | $ | 17 | |
Noncurrent assets | 423 | | | 412 | |
Total investments and restricted cash and cash equivalents | $ | 441 | | | $ | 429 | |
Equity Method Investments
Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.
As of both March 31, 2022 and December 31, 2021, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $11 million and $10 million for the three-month periods ended March 31, 2022 and 2021, respectively.
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents 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, |
| 2022 | | 2021 |
| | | |
Cash and cash equivalents | $ | 54 | | | $ | 22 | |
Restricted cash and cash equivalents included in other current assets | 18 | | | 17 | |
Total cash and cash equivalents and restricted cash and cash equivalents | $ | 72 | | | $ | 39 | |
(4) Regulatory Matters
In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.
(5) Income Taxes
A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
| | | | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
| | | | | | | |
Federal statutory income tax rate | | | | | 21 | % | | 21 | % |
State income tax, net of federal income tax benefit | | | | | 5 | | | 3 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Equity interest | | | | | 2 | | | 2 | |
Effects of ratemaking | | | | | (4) | | | (1) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Noncontrolling interest | | | | | (11) | | | (11) | |
| | | | | | | |
Other, net | | | | | 1 | | | (1) | |
Effective income tax rate | | | | | 14 | % | | 13 | % |
For the period ended March 31, 2022, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's 75% noncontrolling interest.
Eastern Energy Gas, as a subsidiary of BHE, is included in Berkshire Hathaway's U.S. federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provisions for income tax have been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. Eastern Energy Gas made no cash payments for income tax to BHE for the three-month periods ended March 31, 2022 and 2021.
(6) Employee Benefit Plans
Eastern Energy Gas is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $3 million to the MidAmerican Energy Company Retirement Plan and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the three-month period ended March 31, 2022. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in accordance with the intercompany administrative service agreement. 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. As of both March 31, 2022 and December 31, 2021, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $95 million.
(7) Fair Value Measurements
The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
•Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Eastern Energy Gas has the ability to access at the measurement date.
•Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•Level 3 - Unobservable inputs reflect Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.
The following table presents Eastern Energy Gas' financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Input Levels for Fair Value Measurements | | |
| | Level 1 | | Level 2 | | Level 3 | | Total |
As of March 31, 2022: | | | | | | | | |
Assets: | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
Money market mutual funds | | $ | 28 | | | $ | — | | | $ | — | | | $ | 28 | |
Equity securities: | | | | | | | | |
Investment funds | | 15 | | | — | | | — | | | 15 | |
| | $ | 43 | | | $ | — | | | $ | — | | | $ | 43 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
Commodity derivatives | | $ | — | | | $ | (2) | | | $ | — | | | $ | (2) | |
Foreign currency exchange rate derivatives | | — | | | (3) | | | — | | | (3) | |
| | | | | | | | |
| | $ | — | | | $ | (5) | | | $ | — | | | $ | (5) | |
| | | | | | | | |
As of December 31, 2021: | | | | | | | | |
Assets: | | | | | | | | |
| | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | 3 | | | $ | — | | | $ | 3 | |
Equity securities: | | | | | | | | |
Investment funds | | 13 | | | — | | | — | | | 13 | |
| | $ | 13 | | | $ | 3 | | | $ | — | | | $ | 16 | |
| | | | | | | | |
Liabilities: | | | | | | | | |
| | | | | | | | |
Foreign currency exchange rate derivatives | | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
| | | | | | | | |
| | $ | — | | | $ | (3) | | | $ | — | | | $ | (3) | |
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by Eastern Energy Gas. Market price quotations are generally readily obtainable for the applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.
Eastern Energy Gas' long-term debt is carried at cost, including unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Financial Statements. The fair value of Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Eastern Energy Gas' variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Eastern Energy Gas' long-term debt (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | As of March 31, 2022 | | As of December 31, 2021 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
Long-term debt | | $ | 3,899 | | | $ | 3,911 | | | $ | 3,906 | | | $ | 4,266 | |
(8) Commitments and Contingencies
Legal Matters
Eastern Energy Gas is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Eastern Energy Gas' current and future operations. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations.
(9) Revenue from Contracts with Customers
The following table summarizes Eastern Energy Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):
| | | | | | | | | | | | | | | | | |
| | | Three-Month Periods |
| | | Ended March 31, |
| | | | | 2022 | | 2021 |
Customer Revenue: | | | | | | | |
Regulated: | | | | | | | |
Gas transportation and storage | | | | | $ | 285 | | | $ | 279 | |
Wholesale | | | | | — | | | 17 | |
| | | | | | | |
Total regulated | | | | | 285 | | | 296 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Nonregulated | | | | | 203 | | | 190 | |
Total Customer Revenue | | | | | 488 | | | 486 | |
Other revenue | | | | | (6) | | | — | |
Total operating revenue | | | | | $ | 482 | | | $ | 486 | |
Remaining Performance Obligations
The following table summarizes Eastern Energy Gas' revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of March 31, 2022 (in millions):
| | | | | | | | | | | | | | | | | |
| Performance obligations expected to be satisfied | | |
| Less than 12 months | | More than 12 months | | Total |
Eastern Energy Gas | $ | 1,832 | | | $ | 17,061 | | | $ | 18,893 | |
(10) Components of Accumulated Other Comprehensive Loss, Net
The following table shows the change in accumulated other comprehensive loss by each component of other comprehensive income (loss), net of applicable income tax (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Unrecognized | | | | | | Accumulated |
| | Amounts On | | Unrealized | | | | Other |
| | Retirement | | Losses on Cash | | Noncontrolling | | Comprehensive |
| | Benefits | | Flow Hedges | | Interests | | Loss, Net |
Balance, December 31, 2020 | | $ | (12) | | | $ | (51) | | | $ | 10 | | | $ | (53) | |
Other comprehensive income (loss) | | 2 | | | 10 | | | (4) | | | 8 | |
Balance, March 31, 2021 | | $ | (10) | | | $ | (41) | | | $ | 6 | | | $ | (45) | |
| | | | | | | | |
Balance, December 31, 2021 | | $ | (6) | | | $ | (42) | | | $ | 5 | | | $ | (43) | |
Other comprehensive income | | 1 | | | 4 | | | — | | | 5 | |
Balance, March 31, 2022 | | $ | (5) | | | $ | (38) | | | $ | 5 | | | $ | (38) | |
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the future could differ significantly from the historical results.
Results of Operations for the First Quarter of 2022 and 2021
Overview
Net income attributable to Eastern Energy Gas for the first quarter of 2022 was $94 million, an increase of $5 million compared to 2021. Net income increased primarily due to lower than estimated 2021 tax assessments of $10 million and lower interest expense of $8 million primarily due to the repayment of long-term debt in the second quarter of 2021. These increases were partially offset by lower margins from regulated gas transportation and storage operations of $16 million due to unfavorable natural gas prices and volumes.
Quarter Ended March 31, 2022 Compared to Quarter Ended March 31, 2021
Operating revenue decreased $4 million, or 1%, for the first quarter of 2022 compared to 2021, primarily due to a decrease in regulated gas revenues for operational and system balancing purposes due to decreased volumes of $17 million, partially offset by an increase in Cove Point liquefied natural gas variable revenue of $13 million.
Excess gas was a credit of $1 million for the first quarter of 2022, primarily due to a decrease in volumes sold of $14 million, partially offset by an unfavorable change in natural gas prices of $9 million and increased volumes of $4 million.
Operations and maintenance decreased $6 million, or 5%, for the first quarter of 2022 compared to 2021, primarily due to a decrease in postretirement benefit costs.
Depreciation and amortization increased $5 million, or 6%, for the first quarter of 2022 compared to 2021, primarily due to higher plant placed in-service.
Property and other taxes decreased $10 million, or 26%, for the first quarter of 2022 compared to 2021, primarily due to lower than estimated 2021 tax assessments.
Interest expense decreased $8 million, or 18%, for the first quarter of 2022 compared to 2021, primarily due to the repayment of $500 million of long-term debt in the second quarter of 2021.
Income tax expense increased $3 million, or 11%, for the first quarter of 2022 compared to 2021 primarily due to higher pre-tax income. The effective tax rate was 14% for the first quarter of 2022 and 13% for the first quarter of 2021.
Net income attributable to noncontrolling interests increased $9 million, or 9%, for the first quarter of 2022 compared to 2021, primarily due to an increase in Cove Point liquefied natural gas variable revenue.
Liquidity and Capital Resources
As of March 31, 2022, Eastern Energy Gas' total net liquidity was $454 million as follows (in millions):
| | | | | | | | |
Cash and cash equivalents | | $ | 54 | |
| | |
Intercompany revolving credit agreement | | 400 | |
| | |
| | |
| | |
| | |
| | |
Total net liquidity | | $ | 454 | |
| | |
Intercompany revolving credit agreement: | | |
Maturity date | | 2022 |
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2022 and 2021 were $341 million and $241 million, respectively. The change was primarily due to increased cash receipts from receivables and other working capital adjustments.
The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2022 and 2021 were $(194) million and $(56) million, respectively. The change was primarily due to loans to its parent under an intercompany revolving credit agreement of $117 million and an increase in capital expenditures of $20 million.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(114) million. Uses of cash totaled $114 million and consisted of distributions to noncontrolling interests from Cove Point.
Net cash flows from financing activities for the three-month period ended March 31, 2021 were $(118) million. Uses of cash totaled $118 million and consisted primarily of distributions to noncontrolling interests from Cove Point of $109 million.
Future Uses of Cash
Eastern Energy Gas has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.
Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
| | | | | | | | | | | | | | | | | |
| Three-Month Periods | | Annual |
| Ended March 31, | | Forecast |
| 2021 | | 2022 | | 2022 |
| | | | | |
Natural gas transmission and storage | $ | 8 | | | $ | 7 | | | $ | 57 | |
Other | 47 | | | 68 | | | 319 | |
Total | $ | 55 | | | $ | 75 | | | $ | 376 | |
Eastern Energy Gas' natural gas transmission and storage capital expenditures primarily include growth capital expenditures related to planned regulated projects. Eastern Energy Gas' other capital expenditures consist primarily of non-regulated and routine capital expenditures for natural gas transmission, storage and liquefied natural gas terminalling infrastructure needed to serve existing and expected demand.
Material Cash Requirements
As of March 31, 2022, there have been no material changes outside the normal course of business in material cash requirements from the information provided in Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021.
Regulatory Matters
Eastern Energy Gas 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 Eastern Energy Gas' current regulatory matters.
Environmental Laws and Regulations
Eastern Energy Gas is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Eastern Energy Gas' 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. Eastern Energy Gas 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 Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and consolidated 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, impairment of goodwill and long-lived assets and income taxes. For additional discussion of Eastern Energy Gas' critical accounting estimates, see Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2021. There have been no significant changes in Eastern Energy Gas' assumptions regarding critical accounting estimates since December 31, 2021.