Item 1. Business
GENERAL
BHE is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of January 31, 2021, Berkshire Hathaway, Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and related or affiliated entities) and Mr. Gregory E. Abel, BHE's Chairman, beneficially owned 91.1%, 7.9% and 1.0%, respectively, of BHE's voting common stock.
Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns an LNG import, export and storage facility, in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.
BHE owns a highly diversified portfolio of primarily regulated businesses that generate, transmit, store, distribute and supply energy and serve customers and end-users across geographically diverse service territories, including 28 states located throughout the United States and in Great Britain and Canada.
•83% of Berkshire Hathaway Energy's consolidated operating income during 2020 was generated from rate-regulated businesses.
•The Utilities serve 5.2 million electric and natural gas customers in 11 states in the United States, Northern Powergrid serves 3.9 million end-users in northern England and AltaLink serves approximately 85% of Alberta, Canada's population.
•As of December 31, 2020, the Company owns approximately 33,700 MWs of generation capacity in operation and under construction:
◦Approximately 29,000 MWs of generation capacity is owned by its regulated electric utility businesses;
◦Approximately 4,700 MWs of generation capacity is owned by its nonregulated subsidiaries, the majority of which provides power to utilities under long-term contracts;
◦Owned generation capacity in operation and under construction consists of 38% wind and solar, 32% natural gas, 24% coal, 5% hydroelectric and geothermal and 1% nuclear and other; and,
◦Cumulative investments in wind, solar, geothermal and biomass generation facilities is approximately $34 billion.
•The Company owns approximately 36,000 miles of transmission lines and owns a 50% interest in ETT that has approximately 1,900 miles of transmission lines.
•The BHE Pipeline Group operates approximately 21,300 miles of pipeline with a market area design capacity of approximately 21 Bcf of natural gas per day, serves customers and end-users in 23 states and transported approximately 15% of the total natural gas consumed in the United States during 2020. The BHE Pipeline Group also operates 20 natural gas storage facilities with a total operating storage design capacity of 499 Bcf.
•HomeServices closed over $152.2 billion of home sales in 2020, up 13.1% from 2019, and continued to grow its brokerage, mortgage and franchise businesses, with services in all 50 states. HomeServices' franchise business has approximately 370 franchisees primarily in the United States and internationally.
Human Capital
The Registrants are committed to attracting, retaining and developing the highest quality of employees; maintaining a safe, diverse and inclusive work environment; offering competitive compensation and benefit programs; and providing employees with opportunities for growth and development.
Employees
As of December 31, 2020, BHE had approximately 23,800 employees, consisting of approximately 14,200 (60%) electric and natural gas operations employees, approximately 6,300 (26%) real estate services employees and approximately 3,300 (14%) corporate services employees. HomeServices has approximately 43,000 real estate agents who are independent contractors. As of December 31, 2020, approximately 8,200 BHE employees were covered by union contracts. The majority of the union employees are employed by the Utilities and are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the United Utility Workers Association and the International Brotherhood of Boilermakers.
Safety
Safety and security are integral to the Registrants' culture and will always be one of the Registrants' top priorities. The Registrants' safety, cyber and physical security programs are built on personal ownership, compliance with standards, accountability for performance, and continuous improvement. The Registrants' provide best-in-class training to ensure that all employees understand the risks and have thorough and specific knowledge to protect themselves, as well as the Registrants' assets, information and operations.
The Registrants use the recordable incident rate to measure employee safety. The recordable incident rate is defined as the number of work-related injuries per 100 full-time workers during a one-year period. The recordable incident rates for each of the Registrants are included below:
Compensation and Benefits
The Registrants' commitment to employees is further demonstrated through competitive compensation and benefits and by providing opportunities for personal growth and career development. In addition to market-based salary, the Registrants' compensation packages include incentive programs to recognize and reward outstanding performance. The Registrants' benefits programs are designed to meet the diverse needs of employees and their families and includes, among other benefits:
•A comprehensive and flexible benefits package that includes medical, dental and vision coverage; employee assistance programs; pre-tax flexible spending accounts; and adoption assistance;
•Income protection that includes options for short- and long-term disability coverage and life insurance;
•Retirement planning that includes a retirement savings plan 401(k) and a variety of employee and employer contribution and matching options;
•Family Medical Leave as well as paid time off and holiday benefits; and
•Career development opportunities that provide access to a variety of learning programs and career development support, including tuition reimbursement.
BHE was incorporated under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.brkenergy.com.
PACIFICORP
General
PacifiCorp, an indirect wholly owned subsidiary of BHE, is a United States regulated electric utility company headquartered in Oregon that serves approximately 2.0 million retail electric customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp is principally engaged in the business of generating, transmitting, distributing and selling electricity. PacifiCorp's combined service territory covers approximately 141,400 square miles and includes diverse regional economies across six states. No single segment of the economy dominates the combined service territory, which helps mitigate PacifiCorp's exposure to economic fluctuations. In the eastern portion of the service territory, consisting of Utah, Wyoming and southeastern Idaho, the principal industries are manufacturing, mining or extraction of natural resources, agriculture, technology, recreation and government. In the western portion of the service territory, consisting of Oregon, southern Washington and northern California, the principal industries are agriculture, manufacturing, forest products, food processing, technology, government and primary metals. In addition to retail sales, PacifiCorp buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize the economic benefits of electricity generation, retail customer loads and existing wholesale transactions. Certain PacifiCorp subsidiaries support its electric utility operations by providing coal mining services.
PacifiCorp's operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The average term of the franchise agreements is approximately 22 years. Several of these franchise agreements allow the municipality the right to seek amendment to the franchise agreement at a specified time during the term. PacifiCorp generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electric service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow PacifiCorp an opportunity to recover its costs of providing services and to earn a reasonable return on its investments.
PacifiCorp was incorporated under the laws of the state of Oregon in 1989 and its principal executive offices are located at 825 N.E. Multnomah Street, Portland, Oregon 97232, its telephone number is (888) 221-7070 and its internet address is www.pacificorp.com. PacifiCorp delivers electricity to customers in Utah, Wyoming and Idaho under the trade name Rocky Mountain Power and to customers in Oregon, Washington and California under the trade name Pacific Power.
All shares of PacifiCorp's common stock are indirectly owned by BHE. PacifiCorp also has shares of preferred stock outstanding that are subject to voting rights in certain limited circumstances.
Regulated Electric Operations
Customers
The GWhs and percentages of electricity sold to PacifiCorp's retail customers by jurisdiction for the years ended December 31 were as follows:
Electricity sold to PacifiCorp's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
Variations in weather, economic conditions and various conservation, energy efficiency and private generation measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.
The annual hourly peak customer demand, which represents the highest demand on a given day and at a given hour, occurs in the summer when air conditioning and irrigation systems are heavily used. Peak demand in the winter occurs due to heating requirements. During 2020, PacifiCorp's peak demand was 10,546 MWs in the summer and 8,327 MWs in the winter.
Generating Facilities and Fuel Supply
PacifiCorp has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding PacifiCorp's owned generating facilities as of December 31, 2020:
(1)Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the Internal Revenue Service ("IRS") as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for ten years at rates that depend upon the date on which construction begins.
(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates PacifiCorp's ownership of Facility Net Capacity.
(3)Cholla Unit 4 was retired in December 2020 consistent with the preferred portfolio in PacifiCorp's 2019 IRP. Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for further discussion.
(4)Naughton Unit 3 was removed from coal-fueled service in January 2019. PacifiCorp determined in its 2019 IRP that converting Naughton Unit 3 to a natural gas-fueled generation resource provides economic benefits to customers. PacifiCorp completed the conversion to natural gas in 2020.
(5)Foote Creek is in the process of being repowered and is expected to be completed in 2021.
(6)Includes portions of TB Flats and Pryor Mountain projects that remain under construction.
The following table shows the percentages of PacifiCorp's total energy supplied by energy source for the years ended December 31:
(1)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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
PacifiCorp is required to have resources available to continuously meet its customer needs and reliably operate its electric system. The percentage of PacifiCorp's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints and wholesale market prices of electricity. PacifiCorp evaluates these factors continuously in order to facilitate economical dispatch of its generating facilities. When factors for one energy source are less favorable, PacifiCorp places more reliance on other energy sources. For example, PacifiCorp can generate more electricity using its low cost hydroelectric and wind-powered generating facilities when factors associated with these facilities are favorable. In addition to meeting its customers' energy needs, PacifiCorp is required to maintain operating reserves on its system to mitigate the impacts of unplanned outages or other disruption in supply, and to meet intra-hour changes in load and resource balance. This operating reserve requirement is dispersed across PacifiCorp's generation portfolio on a least-cost basis based on the operating characteristics of the portfolio. Operating reserves may be held on hydroelectric, coal-fueled, natural gas-fueled or certain types of interruptible load. PacifiCorp manages certain risks relating to its supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives and may include forwards, options, swaps and other agreements. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and to PacifiCorp's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
Coal
PacifiCorp has interests in coal mines that support its coal-fueled generating facilities and jointly operates the Bridger surface and Bridger underground coal mines. These mines supplied 16%, 19% and 17% of PacifiCorp's total coal requirements during the years ended December 31, 2020, 2019 and 2018, respectively. The remaining coal requirements are acquired through long and short-term third-party contracts.
Most of PacifiCorp's coal reserves are held through agreements with the federal Bureau of Land Management and from certain states and private parties. The agreements generally have multi-year terms that may be renewed or extended and require payment of rents and royalties. In addition, federal and state regulations require that comprehensive environmental protection and reclamation standards be met during the course of mining operations and upon completion of mining activities.
Coal reserve estimates are subject to adjustment as a result of the development of additional engineering and geological data, new mining technology and changes in regulation and economic factors affecting the utilization of such reserves.
Recoverability by surface mining methods typically ranges from 90% to 95%. Recoverability by underground mining techniques ranges from 50% to 70%. To meet applicable standards, PacifiCorp blends coal from its owned mines with contracted coal and utilizes emissions reduction technologies for controlling SO2 and other emissions. For fuel needs at PacifiCorp's coal-fueled generating facilities in excess of coal reserves available, PacifiCorp believes it will be able to purchase coal under both long- and short-term contracts to supply its generating facilities over their currently expected remaining useful lives.
Natural Gas
PacifiCorp uses natural gas as fuel for its generating facilities that use combined-cycle, simple-cycle and steam turbines. Oil and natural gas are also used for igniter fuel and standby purposes. These sources are presently in adequate supply and available to meet PacifiCorp's needs.
PacifiCorp enters into forward natural gas purchases at fixed or indexed market prices. PacifiCorp purchases natural gas in the spot market with both fixed and indexed market prices for physical delivery to fulfill any fuel requirements not already satisfied through forward purchases of natural gas and sells natural gas in the spot market for the disposition of any excess supply if the forecasted requirements of its natural gas-fueled generating facilities decrease. PacifiCorp also utilizes financial swap contracts to mitigate price risk associated with its forecasted fuel requirements.
Hydroelectric
The amount of electricity PacifiCorp is able to generate from its hydroelectric facilities depends on a number of factors, including snowpack in the mountains upstream of its hydroelectric facilities, reservoir storage, precipitation in its watersheds, generating unit availability and restrictions imposed by oversight bodies due to competing water management objectives.
PacifiCorp operates the majority of its hydroelectric generating portfolio under long-term licenses. The FERC regulates 99% of the net capacity of this portfolio through 15 individual licenses, which have terms of 30 to 50 years. The licenses for major hydroelectric generating facilities expire at various dates through 2059. A portion of this portfolio is licensed under the Oregon Hydroelectric Act. For discussion of PacifiCorp's hydroelectric relicensing activities, including updated information regarding the Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.
Wind and Other Renewable Resources
PacifiCorp has pursued renewable resources as a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Renewable resources have low to no emissions and require little or no fossil fuel. PacifiCorp is repowering all of its existing wind-powered generating facilities by replacing a significant portion of the equipment to requalify the facilities for federal renewable electricity PTCs for ten years from the date the repowered facilities were placed in-service. The repowering project will extend the lives of the existing wind facilities and increase the anticipated electrical generation from the repowered wind facilities, on average, by approximately 26%. Additionally, new wind-powered generating facilities totaling 674 MWs were placed in-service during 2020 with another 516 MWs expected to be placed in-service during 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in-service. In addition to the discussion contained herein regarding repowering activities, refer to "Regulatory Matters" in Item 1 of this Form 10-K.
Wholesale Activities
PacifiCorp purchases and sells electricity in the wholesale markets as needed to balance its generation with its retail load obligations. PacifiCorp may also purchase electricity in the wholesale markets when it is more economical than generating electricity from its own facilities and may sell surplus electricity in the wholesale markets when it can do so economically. When prudent, PacifiCorp enters into financial swap contracts and forward electricity sales and purchases for physical delivery at fixed prices to reduce its exposure to electricity price volatility.
Energy Imbalance Market
PacifiCorp and the California ISO implemented an EIM in November 2014, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western United States. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western United States do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM, bringing incremental resource diversity.
Transmission and Distribution
PacifiCorp operates one balancing authority area in the western portion of its service territory ("PacifiCorp-West") and one balancing authority area in the eastern portion of its service territory ("PacifiCorp-East"). A balancing authority area is a geographic area with transmission systems that control generation to maintain schedules with other balancing authority areas and ensure reliable operations. In operating the balancing authority areas, PacifiCorp is responsible for continuously balancing electricity supply and demand by dispatching generating resources and interchange transactions so that generation internal to the balancing authority area, plus net imported power, matches customer loads. Deliveries of energy over PacifiCorp's transmission system are managed and scheduled in accordance with FERC requirements.
PacifiCorp's transmission system is part of the Western Interconnection, which includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. PacifiCorp's transmission system, together with contractual rights on other transmission systems, enables PacifiCorp to integrate and access generation resources to meet its customer load requirements. PacifiCorp's transmission and distribution systems included approximately 16,900 miles of transmission lines in ten states, 63,800 miles of distribution lines and 900 substations as of December 31, 2020.
PacifiCorp's transmission and distribution system is managed on a coordinated basis to obtain maximum load-carrying capability and efficiency. Portions of PacifiCorp's transmission and distribution systems are located:
•On property owned or used through agreements by PacifiCorp;
•Under or over streets, alleys, highways and other public places, the public domain and national forests and state and federal lands under franchises, easements or other rights that are generally subject to termination;
•Under or over private property as a result of easements obtained primarily from the title holder of record; or
•Under or over Native American reservations through agreements with the United States Secretary of Interior or Native American tribes.
It is possible that some of the easements and the property over which the easements were granted may have title defects or may be subject to mortgages or liens existing at the time the easements were acquired.
PacifiCorp's Energy Gateway Transmission Expansion Program represents plans to build approximately 2,000 miles of new high-voltage transmission lines, with an estimated cost of $6 billion, primarily in Wyoming, Utah, Idaho and Oregon. The $6 billion estimated cost includes: (a) the 135-mile, 345-kV transmission line between the Terminal substation near the Salt Lake City Airport and the Populus substation in Downey, Idaho, placed in-service in 2010; (b) the 100-mile, 345/500-kV transmission line between the Mona substation in central Utah and the Oquirrh substation in the Salt Lake Valley, placed in-service in 2013; (c) the 170-mile, 345-kV transmission line between the Sigurd substation in central Utah and the Red Butte substation in southwest Utah, placed in-service in 2015; (d) the 140-mile, 500-kV transmission line between Aeolus substation near Medicine Bow in Wyoming and Jim Bridger generating facility, placed in-service in 2020; (e) the 400-mile, 500kV high-voltage transmission line between the Aeolus substation and the Clover substation near Mona, Utah; (f) the 290-mile, 500kV high-voltage transmission line from Longhorn Substation near Boardman, Oregon, to the existing Hemingway Substation southwest of Boise, Idaho (a joint project with Idaho Power and the Bonneville Power Administration); and (g) other segments that are expected to be placed in-service in future years, depending on load growth, siting, permitting and construction schedules. The transmission line segments are intended to: (a) address customer load growth; (b) improve system reliability; (c) reduce transmission system constraints; (d) provide access to diverse generation resources, including renewable resources; and (e) improve the flow of electricity throughout PacifiCorp's six-state service area. Proposed transmission line segments are evaluated to ensure optimal benefits and timing before committing to move forward with permitting and construction. Through December 31, 2020, $2.7 billion had been spent and $2.3 billion, including AFUDC, had been placed in-service.
Future Generation, Conservation and Energy Efficiency
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. The IRP process identifies the amount and timing of PacifiCorp's expected future resource needs, accounting for planning uncertainty, risks, reliability, state energy policies and other factors. The IRP is prepared following a public process, which provides an opportunity for stakeholders to participate in PacifiCorp's resource planning process. PacifiCorp files its IRP on an every-two-year basis with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states.
In October 2019, PacifiCorp filed its 2019 IRP with its state commissions. In November 2019, the WUTC temporarily suspended its practice of acknowledging utility IRPs, including PacifiCorp's 2019 IRP, due to ongoing implementation activities associated with Washington state's Senate Bill 5116, the Clean Energy Transformation Act. In May 2020, the OPUC acknowledged the 2019 IRP with conditions. The UPSC also acknowledged the 2019 IRP in May 2020. In September 2020, the IPUC acknowledged the 2019 IRP. In October 2020, the WPSC concluded its docket investigating the 2019 IRP. A written decision was issued in January 2021 requiring PacifiCorp to incorporate additional analyses for the 2021 IRP and periodically file reports related to the action plan and other items.
The 2019 IRP includes new transmission investments that will facilitate growth in new renewable energy resources, new storage resources, and expansion in new energy efficiency measures and demand-response programs. The IRP also includes accelerated coal-fueled generation facility retirements and the need for incremental flexible capacity resources beginning in 2021. Delivery of new transmission infrastructure that will facilitate approximately 4,400 MWs of new renewable energy resources, incremental to new renewable capacity that was expected to come online by the end of 2020 and 2021, and the addition of approximately 600 MWs of new storage capacity is planned through 2023. The 2019 IRP outlines PacifiCorp's plan to procure these near-term generating facilities through a Request for Proposals ("RFP") process that will determine how many of the new resources identified in the 2019 IRP will be developed as owned assets or power purchase agreements. Over the next 20 years, the 2019 IRP calls for retiring approximately 4,500 MWs of coal-fueled generating capacity while adding approximately 8,900 MWs of new renewable resources, incremental to new renewable capacity of approximately 2,000 MWs that were expected to come online by the end of 2020 and 2021, and approximately 2,800 MWs of new storage capacity. All or some of the renewable energy attributes associated with generation from these renewable resources may be used in future years to comply with RPS or other regulatory requirements, sold to third parties in the form of RECs or other environmental commodities, or excluded from energy purchased.
Requests for Proposals
PacifiCorp issues individual RFPs, each of which typically focuses on a specific category of generation resources consistent with the IRP or other customer-driven demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or RPS requirements. 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 2020 All Source RFP ("2020AS RFP") was filed for approval with the UPSC and the OPUC in April 2020. In July 2020, the UPSC and the OPUC approved the 2020AS RFP, and PacifiCorp issued the 2020AS RFP to the market. The 2020AS RFP sought bids for resources capable of coming online by the end of 2024 up to the level of resources identified in PacifiCorp's 2019 IRP. Bids were submitted in August 2020, and an initial shortlist was identified in October 2020. The initial shortlist includes a total of 6,982 MWs of new generation and storage capacity. Of the total, 5,652 MWs are new generation resources (represented by 3,173 MWs of solar generation and 2,479 MWs of wind generation) and an additional 1,330 MWs of new battery storage assets, which includes 1,130 MWs of solar collocated battery storage and 200 MWs of stand-alone battery storage. The final shortlist of winning bids will be identified by June 2021.
Energy Efficiency Programs
PacifiCorp has provided a comprehensive set of DSM programs to its customers since the 1970s. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. PacifiCorp offers services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, PacifiCorp offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for energy project management, efficient building operations and efficient construction. Incentives are also paid to solicit participation in load management programs by residential, business and agricultural customers through programs such as PacifiCorp's residential and small commercial air conditioner load control program and irrigation equipment load control programs. Although subject to prudence reviews, state regulations allow for recovery of costs incurred for the DSM programs through state-specific energy efficiency surcharges to retail customers or for recovery of costs through rates. During 2020, PacifiCorp spent $159 million on these DSM programs, resulting in an estimated 574,114 MWhs of first-year energy savings and an estimated 270 MWs of peak load management. In addition to these DSM programs, PacifiCorp has load curtailment contracts with a number of large industrial customers that deliver up to 305 MWs of load reduction when needed, depending on the customers' actual loads. Recovery of the costs associated with the large industrial load management program are captured in the retail special contract agreements with those customers approved by their respective state commissions or through PacifiCorp's general rate case process.
Human Capital
Employees
As of December 31, 2020, PacifiCorp had approximately 5,200 employees, of which approximately 2,900 were covered by union contracts, principally with the International Brotherhood of Electrical Workers, the Utility Workers Union of America and the International Brotherhood of Boilermakers. For more information regarding PacifiCorp's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
General
MidAmerican Funding and MHC
MidAmerican Funding, a wholly owned subsidiary of BHE, is a holding company headquartered in Iowa that owns all of the outstanding common stock of MHC Inc. ("MHC"), which is a holding company owning all of the common stock of MidAmerican Energy and Midwest Capital Group, Inc. ("Midwest Capital"). MidAmerican Funding and MidAmerican Energy are indirect consolidated subsidiaries of Berkshire Hathaway. MidAmerican Funding conducts no business other than activities related to its debt securities and the ownership of MHC. MHC conducts no business other than the ownership of its subsidiaries. MidAmerican Energy is a substantial portion of MidAmerican Funding's and MHC's assets, revenue and earnings.
MidAmerican Funding was formed as a limited liability company under the laws of the state of Iowa in 1999 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580 and its telephone number is (515) 242-4300.
MidAmerican Energy
MidAmerican Energy, an indirect wholly owned subsidiary of BHE, is a United States regulated electric and natural gas utility company headquartered in Iowa that serves 0.8 million retail electric customers in portions of Iowa, Illinois and South Dakota and 0.8 million retail and transportation natural gas customers in portions of Iowa, South Dakota, Illinois and Nebraska. MidAmerican Energy is principally engaged in the business of generating, transmitting, distributing and selling electricity and in distributing, selling and transporting natural gas. MidAmerican Energy's service territory covers approximately 11,000 square miles. Metropolitan areas in which MidAmerican Energy distributes electricity at retail include Council Bluffs, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; and the Quad Cities (Davenport and Bettendorf, Iowa and Rock Island, Moline and East Moline, Illinois). Metropolitan areas in which it distributes natural gas at retail include Cedar Rapids, Des Moines, Fort Dodge, Iowa City, Sioux City and Waterloo, Iowa; the Quad Cities; and Sioux Falls, South Dakota. MidAmerican Energy has a diverse customer base consisting of urban and rural residential customers and a variety of commercial and industrial customers. Principal industries served by MidAmerican Energy include electronic data storage; processing and sales of food products; manufacturing, processing and fabrication of primary metals, farm and other non-electrical machinery; cement and gypsum products; and government. In addition to retail sales and natural gas transportation, MidAmerican Energy sells electricity principally to markets operated by RTOs and natural gas to other utilities and market participants on a wholesale basis. MidAmerican Energy is a transmission-owning member of the MISO and participates in its capacity, energy and ancillary services markets.
MidAmerican Energy's regulated electric and natural gas operations are conducted under numerous franchise agreements, certificates, permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 20- to 25-year terms. Several of these franchise agreements give either party the right to seek amendment to the franchise agreement at one or two specified times during the term. MidAmerican Energy generally has an exclusive right to serve electric customers within its service territories and, in turn, has an obligation to provide electricity service to those customers. In return, the state utility commissions have established rates on a cost-of-service basis, which are designed to allow MidAmerican Energy an opportunity to recover its costs of providing services and to earn a reasonable return on its investment. In Illinois, MidAmerican Energy's regulated retail electric customers may choose their energy supplier.
The percentages of MidAmerican Energy's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows:
MidAmerican Energy was incorporated under the laws of the state of Iowa in 1995 and its principal executive offices are located at 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580, its telephone number is (515) 242-4300 and its internet address is www.midamericanenergy.com.
Regulated Electric Operations
Customers
The GWhs and percentages of electricity sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
Electricity sold to MidAmerican Energy's retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
Variations in weather, economic conditions and various conservation and energy efficiency measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.
There are seasonal variations in MidAmerican Energy's electricity sales that are principally related to weather and the related use of electricity for air conditioning. Additionally, electricity sales are priced higher in the summer months compared to the remaining months of the year. As a result, 40% to 50% of MidAmerican Energy's regulated electric retail revenue is reported in the months of June, July, August and September.
A degree of concentration of sales exists with certain large electric retail customers. Sales to the ten largest customers, from a variety of industries, comprised 23%, 21% and 20% of total retail electric sales in 2020, 2019 and 2018, respectively. Sales to electronic data storage customers included in the ten largest customers comprised 16%, 12% and 9% of total retail electric sales in 2020, 2019 and 2018, respectively.
The annual hourly peak demand on MidAmerican Energy's electric system usually occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On July 8, 2020, retail customer usage of electricity caused an hourly peak demand of 5,035 MWs on MidAmerican Energy's electric distribution system, which is 60 MWs less than the record hourly peak demand of 5,095 MWs set July 19, 2019.
Generating Facilities and Fuel Supply
MidAmerican Energy has ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding MidAmerican Energy's owned generating facilities as of December 31, 2020:
(1)Repowered dates are associated with component replacements on existing wind-powered generating facilities commonly referred to by the Internal Revenue Service ("IRS") as repowering. IRS rules provide for re-establishment of the PTCs for an existing wind-powered generating facility upon the replacement of a significant portion of its components. If the degree of component replacement in such projects meets IRS guidelines, PTCs are re-established for ten years at rates that depend upon the date on which construction begins.
(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates MidAmerican Energy's ownership of Facility Net Capacity.
(3)The Pocahontas Prairie was acquired in 2020 and is currently not eligible to earn federal renewable electricity PTCs.
(4)Riverside Unit No. 5 was retired in January 2021.
The following table shows the percentages of MidAmerican Energy's total energy supplied by energy source for the years ended December 31:
(1)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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
MidAmerican Energy is required to have resources available for dispatch by MISO to continuously meet its customer needs and reliably operate its electric system. The percentage of MidAmerican Energy's energy supplied by energy source varies from year to year and is subject to numerous operational and economic factors such as planned and unplanned outages, fuel commodity prices, fuel transportation costs, weather, environmental considerations, transmission constraints, and wholesale market prices of electricity. MidAmerican Energy evaluates these factors continuously in order to facilitate economical dispatch of its generating facilities by MISO. When factors for one energy source are less favorable, MidAmerican Energy places more reliance on other energy sources. For example, MidAmerican Energy can generate more electricity using its low cost wind-powered generating facilities when factors associated with these facilities are favorable. When factors associated with wind resources are less favorable, MidAmerican Energy must increase its reliance on more expensive generation or purchased electricity. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction.
Wind
MidAmerican Energy owns more wind-powered generating capacity than any other United States rate-regulated electric utility and believes wind-powered generation offers a viable, economical and environmentally prudent means of supplying electricity and complying with laws and regulations. Pursuant to ratemaking principles approved by the IUB, facilities accounting for 96% of MidAmerican Energy's wind-powered generating capacity in-service at December 31, 2020, are authorized to earn over their regulatory lives a fixed rate of return on equity ranging from 11.0% to 12.2% on the depreciated cost of their original construction, which excludes the cost of later replacements, in any future Iowa rate proceeding. MidAmerican Energy's wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for federal renewable electricity PTCs for 10 years from the date the facilities are placed in-service. PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold. PTCs for MidAmerican Energy's wind-powered generating facilities currently in-service began expiring in 2014, with final expiration in 2030. Since 2014, MidAmerican Energy has repowered, or plans to repower, 2,310 MWs of wind-powered generating facilities for which PTCs have expired or will expire by the end of 2022. MidAmerican Energy anticipates energy generation from the repowered facilities will increase between 19% and 30% depending upon the technology being repowered.
Of the 6,998 MWs of wind-powered generating facilities in-service as of December 31, 2020, 6,866 MWs were generating PTCs, including 1,275 MWs of repowered facilities. PTCs earned by MidAmerican Energy's wind-powered generating facilities placed in-service prior to 2013, except for repowered facilities, are included in MidAmerican Energy's Iowa energy adjustment clause, through which MidAmerican Energy is allowed to recover fluctuations in its electric retail energy costs. Facilities earning PTCs that currently benefit customers through the Iowa energy adjustment clause totaled 1,000 MWs (nominal ratings) as of December 31, 2020, with the eligibility of those facilities to earn PTCs expiring by the end of 2022. MidAmerican Energy earned PTCs totaling $510 million and $378 million in 2020 and 2019, respectively, of which 15% and 19%, respectively, were included in the Iowa energy adjustment clause.
Coal
All of the coal-fueled generating facilities operated by MidAmerican Energy are fueled by low-sulfur, western coal from the Powder River Basin in northeast Wyoming. MidAmerican Energy's coal supply portfolio includes multiple suppliers and mines under short-term and multi-year agreements of varying terms and quantities through 2023. MidAmerican Energy believes supplies from these sources are presently adequate and available to meet MidAmerican Energy's needs. MidAmerican Energy's coal supply portfolio has substantially all of its expected 2021 requirements under fixed-price contracts. MidAmerican Energy regularly monitors the western coal market for opportunities to enhance its coal supply portfolio.
MidAmerican Energy has a multi-year long-haul coal transportation agreement with BNSF Railway Company ("BNSF"), an affiliate company, for the delivery of coal to all of the MidAmerican Energy-operated coal-fueled generating facilities other than the George Neal Energy Center. Under this agreement, BNSF delivers coal directly to MidAmerican Energy's Walter Scott, Jr. Energy Center and to an interchange point with Canadian Pacific Railway Company for short-haul delivery to the Louisa Energy Center. MidAmerican Energy has a multi-year long-haul coal transportation agreement with Union Pacific Railroad Company for the delivery of coal to the George Neal Energy Center.
Nuclear
MidAmerican Energy is a 25% joint owner of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station"), a nuclear power plant, which is currently licensed by the NRC for operation until December 14, 2032. Exelon Generation Company, LLC ("Exelon Generation"), a subsidiary of Exelon Corporation, is the 75% joint owner and the operator of Quad Cities Station. Approximately one-third of the nuclear fuel assemblies in each reactor core at Quad Cities Station is replaced every 24 months. MidAmerican Energy has been advised by Exelon Generation that the following requirements for Quad Cities Station can be met under existing supplies or commitments: uranium requirements through 2025 and partial requirements through 2030; uranium conversion requirements through 2028 and partial requirements through 2031; enrichment requirements through 2027 and partial requirements through 2031; and fuel fabrication requirements through 2028. MidAmerican Energy has been advised by Exelon Generation that it does not anticipate it will have difficulty in contracting for uranium, uranium conversion, enrichment or fabrication of nuclear fuel needed to operate Quad Cities Station during these time periods. In reaction to concerns about the profitability of Quad Cities Station and Exelon Generation's ability to continue its operation, 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 Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station.
Natural Gas and Other
MidAmerican Energy uses natural gas and oil as fuel for intermediate and peak demand electric generation, igniter fuel, transmission support and standby purposes. These sources are presently in adequate supply and available to meet MidAmerican Energy's needs.
Regional Transmission Organizations
MidAmerican Energy sells and purchases electricity and ancillary services related to its generation and load in wholesale markets pursuant to the tariffs in those markets. MidAmerican Energy participates predominantly in the MISO energy and ancillary service markets, which provide MidAmerican Energy with wholesale opportunities over a large market area. MidAmerican Energy can enter into wholesale bilateral transactions in addition to market activity related to its assets. MidAmerican Energy is authorized to participate in the Southwest Power Pool, Inc. and PJM Interconnection, L.L.C. ("PJM") markets and can contract with several other major transmission-owning utilities in the region. MidAmerican Energy can utilize both financial swaps and physical fixed-price electricity sales and purchases contracts to reduce its exposure to electricity price volatility.
MidAmerican Energy's decisions regarding additions to or reductions of its generation portfolio may be impacted by the MISO's minimum reserve margin requirement. The MISO requires each member to maintain a minimum reserve margin of its accredited generating capacity over its peak demand obligation based on the member's load forecast filed with the MISO each year. The MISO's reserve requirement was 8.9% for the summer of 2020 and will increase to 9.4% for the summer of 2021. MidAmerican Energy's owned and contracted capacity accredited for the 2020-2021 MISO capacity auction was 5,471 MWs compared to a peak demand obligation of 4,830 MWs, or a reserve margin of 13.3%. Accredited capacity represents the amount of generation available to meet the requirements of MidAmerican Energy's retail customers and consists of MidAmerican Energy-owned generation, interruptible retail customer load, certain customer private generation that MidAmerican Energy is contractually allowed to dispatch and the net amount of capacity purchases and sales, excluding sales into the MISO annual capacity auction. Accredited capacity may vary significantly from the nominal, or design, capacity ratings, particularly for wind turbines whose output is dependent upon wind levels at any given time. Additionally, the actual amount of generating capacity available at any time may be less than the accredited capacity due to regulatory restrictions, transmission constraints, fuel restrictions and generating units being temporarily out of service for inspection, maintenance, refueling, modifications or other reasons.
Transmission and Distribution
MidAmerican Energy's transmission and distribution systems included 4,600 circuit miles of transmission lines in four states, 25,000 circuit miles of distribution lines and 340 substations as of December 31, 2020. Electricity from MidAmerican Energy's generating facilities and purchased electricity is delivered to wholesale markets and its retail customers via the transmission facilities of MidAmerican Energy and others. MidAmerican Energy participates in the MISO capacity, energy and ancillary services markets as a transmission-owning member and, accordingly, operates its transmission assets at the direction of the MISO. The MISO manages its energy and ancillary service markets using reliability-constrained economic dispatch of the region's generation. For both the day-ahead and real-time (every five minutes) markets, the MISO analyzes generation commitments to provide market liquidity and transparent pricing while maintaining transmission system reliability by minimizing congestion and maximizing efficient energy transmission. Additionally, through its FERC-approved OATT, the MISO performs the role of transmission service provider throughout the MISO footprint and administers the long-term planning function. MISO and related costs of the participants are shared among the participants through a number of mechanisms in accordance with the MISO tariff.
Regulated Natural Gas Operations
MidAmerican Energy is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. MidAmerican Energy purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the gas to MidAmerican Energy's service territory and for storage and balancing services. MidAmerican Energy sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for end-use customers who have independently secured their supply of natural gas. During 2020, 58% of the total natural gas delivered through MidAmerican Energy's distribution system was associated with transportation service.
Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of MidAmerican Energy included 24,100 miles of natural gas main and service lines as of December 31, 2020.
Customer Usage and Seasonality
The percentages of natural gas sold to MidAmerican Energy's retail customers by jurisdiction for the years ended December 31 were as follows:
The percentages of natural gas sold to MidAmerican Energy's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
(1)Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers that use natural gas principally for heating. Industrial customers are non-residential customers that use natural gas principally for their manufacturing processes.
(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.
There are seasonal variations in MidAmerican Energy's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 50-60% of MidAmerican Energy's regulated retail natural gas revenue is reported in the months of January, February, March and December.
On January 29, 2019, MidAmerican Energy recorded its all-time highest peak-day delivery through its distribution system of 1,314,526 Dths. This peak-day delivery consisted of 68% traditional retail sales service and 32% transportation service. MidAmerican Energy's 2020/2021 winter heating season peak-day delivery as of February 23, 2021, was 1,243,237 Dths, reached on February 14, 2021. This preliminary peak-day delivery consisted of 72% traditional retail sales service and 28% transportation service.
Natural Gas Supply and Capacity
MidAmerican Energy uses several strategies designed to maintain a reliable natural gas supply and reduce the impact of volatility in natural gas prices on its regulated retail natural gas customers. These strategies include the purchase of a geographically diverse supply portfolio from producers and third-party energy marketing companies, the use of interstate pipeline storage services and MidAmerican Energy's LNG peaking facilities, and the use of financial derivatives to fix the price on a portion of the anticipated natural gas requirements of MidAmerican Energy's customers. Refer to "General Regulation" in Item 1 of this Form 10-K for a discussion of the PGAs.
MidAmerican Energy contracts for firm natural gas pipeline capacity to transport natural gas from key production areas and liquid market centers to its service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Northern Natural Gas, an affiliate company. MidAmerican Energy has multiple pipeline interconnections into several larger markets within its distribution system. Multiple pipeline interconnections create competition among pipeline suppliers for transportation capacity to serve those markets, thus reducing costs. In addition, multiple pipeline interconnections increase delivery reliability and give MidAmerican Energy the ability to optimize delivery of the lowest cost supply from the various production areas and liquid market centers into these markets. Benefits to MidAmerican Energy's distribution system customers are shared among all jurisdictions through a consolidated PGA.
At times, the natural gas pipeline capacity available through MidAmerican Energy's firm capacity portfolio may exceed the requirements of retail customers on MidAmerican Energy's distribution system. Firm capacity in excess of MidAmerican Energy's system needs can be released to other companies to achieve optimum use of the available capacity. Past IUB and South Dakota Public Utilities Commission ("SDPUC") rulings have allowed MidAmerican Energy to retain 30% of the respective jurisdictional revenue on the resold capacity, with the remaining 70% being returned to customers through the PGAs.
MidAmerican Energy utilizes interstate pipeline natural gas storage services to meet retail customer requirements, manage fluctuations in demand due to changes in weather and other usage factors and manage variation in seasonal natural gas pricing. MidAmerican Energy typically withdraws natural gas from storage during the heating season when customer demand is historically at its peak and injects natural gas into storage during off-peak months when customer demand is historically lower. MidAmerican Energy also utilizes its three LNG facilities to meet peak day demands during the winter heating season. Interstate pipeline storage services and MidAmerican Energy's LNG facilities reduce dependence on natural gas purchases during the volatile winter heating season and can deliver a significant portion of MidAmerican Energy's anticipated retail sales requirements on a peak winter day. For MidAmerican Energy's 2020/2021 winter heating season preliminary peak-day of February 14, 2021, supply sources used to meet deliveries to traditional retail sales service customers included 51% from purchases delivered on interstate pipelines, 33% from interstate pipeline storage services and 16% from MidAmerican Energy's LNG facilities.
MidAmerican Energy attempts to optimize the value of its regulated transportation capacity, natural gas supply and interstate pipeline storage services by engaging in wholesale transactions. IUB and SDPUC rulings have allowed MidAmerican Energy to retain 50% of the respective jurisdictional margins earned on certain wholesale sales of natural gas, with the remaining 50% being returned to customers through the PGAs.
MidAmerican Energy is not aware of any factors that would cause material difficulties in meeting its anticipated retail customer demand under normal operating conditions for the foreseeable future.
Energy Efficiency Programs
MidAmerican Energy has provided a comprehensive set of demand- and energy-reduction programs to its Iowa electric and natural gas customers since 1990. The programs, collectively referred to as energy efficiency programs, are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy engineering audits and information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, MidAmerican Energy offers rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. In Iowa, legislation passed in 2018 provides that projected cumulative average annual costs for a natural gas energy efficiency plan cannot exceed 1.5% of expected Iowa natural gas retail revenue and, for an electric demand response plan and separately for an electric energy efficiency plan other than demand response, cannot exceed 2.0% of expected annual Iowa electric retail revenue. Although subject to prudence reviews, state regulations allow for contemporaneous recovery of costs incurred for energy efficiency programs through state-specific energy efficiency service charges paid by all retail electric and natural gas customers. In 2020, $40 million was expensed for MidAmerican Energy's energy efficiency programs, which resulted in estimated first-year energy savings of 136,000 MWhs of electricity and 189,000 Dths of natural gas and an estimated peak load reduction of 345 MWs of electricity and 4,558 Dths per day of natural gas.
Human Capital
Employees
All of MidAmerican Funding's employees are employed by MidAmerican Energy. As of December 31, 2020, MidAmerican Energy had approximately 3,400 employees, of which approximately 1,400 were covered by union contracts. MidAmerican Energy has three separate contracts with locals of the International Brotherhood of Electrical Workers ("IBEW") and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union. A contract with the IBEW covering substantially all of the union employees expires April 30, 2022. For more information regarding MidAmerican Funding's and MidAmerican Energy's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.
NV ENERGY (NEVADA POWER AND SIERRA PACIFIC)
General
NV Energy, an indirect wholly owned subsidiary of BHE, is an energy holding company headquartered in Nevada whose principal subsidiaries are Nevada Power and Sierra Pacific. Nevada Power and Sierra Pacific are indirect consolidated subsidiaries of Berkshire Hathaway. Nevada Power is a United States regulated electric utility company serving 1.0 million retail customers primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. Sierra Pacific is a United States regulated electric and natural gas utility company serving 0.4 million retail electric customers and 0.2 million retail and transportation natural gas customers in northern Nevada. The Nevada Utilities are principally engaged in the business of generating, transmitting, distributing and selling electricity and, in the case of Sierra Pacific, in distributing, selling and transporting natural gas. Nevada Power and Sierra Pacific have electric service territories covering approximately 4,500 square miles and 41,200 square miles, respectively. Sierra Pacific has a natural gas service territory covering approximately 900 square miles in Reno and Sparks. Principal industries served by the Nevada Utilities include gaming, recreation, warehousing, manufacturing and governmental services. Sierra Pacific also serves the mining industry. The Nevada Utilities buy and sell electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants to balance and optimize economic benefits of electricity generation, retail customer loads and wholesale transactions.
The Nevada Utilities' electric and natural gas operations are conducted under numerous nonexclusive franchise agreements, revocable permits and licenses obtained from federal, state and local authorities. The franchise agreements, with various expiration dates, are typically for 20- to 25-year terms. The Nevada Utilities operate under certificates of public convenience and necessity as regulated by the PUCN, and as such the Nevada Utilities have an obligation to provide electricity service to those customers within their service territory. In return, the PUCN has established rates on a cost-of-service basis, which are designed to allow the Nevada Utilities an opportunity to recover all prudently incurred costs of providing services and an opportunity to earn a reasonable return on their investment.
NV Energy's monthly net income is affected by the seasonal impact of weather on electricity and natural gas sales and seasonal retail electricity prices from the Nevada Utilities'. For 2020, 76% of NV Energy annual net income was recorded in the months of June through September.
Regulated electric utility operations is Nevada Power's only segment while regulated electric utility operations and regulated natural gas operations are the two segments of Sierra Pacific.
The percentages of Sierra Pacific's operating revenue and operating income derived from the following business activities for the years ended December 31 were as follows:
Nevada Power was incorporated under the laws of the state of Nevada in 1929 and its principal executive offices are located at 6226 West Sahara Avenue, Las Vegas, Nevada 89146, its telephone number is (702) 402-5000 and its internet address is www.nvenergy.com.
Sierra Pacific was incorporated under the laws of the state of Nevada in 1912 and its principal executive offices are located at 6100 Neil Road, Reno, Nevada 89511, its telephone number is (775) 834-4011 and its internet address is www.nvenergy.com.
Regulated Electric Operations
Customers
The Nevada Utilities' sell electricity to retail customers in a single state jurisdiction. Electricity sold to the Nevada Utilities' retail and wholesale customers by class of customer and the average number of retail customers for the years ended December 31 were as follows:
Variations in weather, economic conditions, particularly for gaming, mining and wholesale customers and various conservation, energy efficiency and private generation measures and programs can impact customer usage. Wholesale sales are impacted by market prices for energy relative to the incremental cost to generate power.
There are seasonal variations in the Nevada Utilities' electric business that are principally related to weather and the related use of electricity for air conditioning. Typically, 48-52% of Nevada Power's and 36-38% of Sierra Pacific's regulated electric revenue is reported in the months of June through September.
The annual hourly peak customer demand on the Nevada Utilities' electric systems occurs as a result of air conditioning use during the cooling season. Peak demand represents the highest demand on a given day and at a given hour. On August 18, 2020, customer usage of electricity caused an hourly peak demand of 5,965 MWs on Nevada Power's electric system, which is 159 MWs less than the record hourly peak demand of 6,124 MWs set July 28, 2016. On July 29, 2020, customer usage of electricity caused an hourly peak demand of 1,906 MWs on Sierra Pacific's electric system, which is 46 MWs more than the previous record hourly peak demand of 1,860 MWs set July 19, 2018.
Generating Facilities and Fuel Supply
The Nevada Utilities have ownership interest in a diverse portfolio of generating facilities. The following table presents certain information regarding the Nevada Utilities' owned generating facilities as of December 31, 2020:
(1)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates Nevada Power or Sierra Pacific's ownership of Facility Net Capacity.
The following table shows the percentages of the Nevada Utilities' total energy supplied by energy source for the years ended December 31:
(1) 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, (b) sold to third parties in the form of RECs or other environmental commodities, or (c) excluded from energy purchased.
The Nevada Utilities are required to have resources available to continuously meet their customer needs and reliably operate their electric systems. The percentage of the Nevada Utilities' energy supplied by energy source varies from year-to-year and is subject to numerous operational and economic factors such as planned and unplanned outages; fuel commodity prices; fuel transportation costs; weather; environmental considerations; transmission constraints; and wholesale market prices of electricity. The Nevada Utilities evaluate these factors continuously in order to facilitate economical dispatch of their generating facilities. When factors for one energy source are less favorable, the Nevada Utilities place more reliance on other energy sources. As long as the Nevada Utilities' purchases are deemed prudent by the PUCN, through their annual prudency review, the Nevada Utilities are permitted to recover the cost of fuel and purchased power. The Nevada Utilities also have the ability to reset quarterly the BTERs, with PUCN approval, based on the last twelve months fuel costs and purchased power and to reset quarterly DEAA.
The Nevada Utilities have adopted an approach to managing the energy supply function that has three primary elements. The first element is a set of management guidelines for procuring and optimizing the supply portfolio that is consistent with the requirements of a load serving entity with a full requirements obligation, and with the growth of private generation serving a small but growing group of customers with partial requirements. The second element is an energy risk management and control approach that ensures clear separation of roles between the day-to-day management of risks and compliance monitoring and control and ensures clear distinction between policy setting (or planning) and execution. Lastly, the Nevada Utilities pursue a process of ongoing regulatory involvement and acknowledgment of the resource portfolio management plans.
The Nevada Utilities have entered into multiple long-term power purchase contracts (three or more years) with suppliers that generate electricity utilizing renewable resources, natural gas and coal. Nevada Power has entered into contracts with a total capacity of 3,612 MWs with contract termination dates ranging from 2022 to 2067. Included in these contracts are 3,352 MWs of capacity from renewable energy, of which 2,068 MWs of capacity are under development or construction and not currently available. Sierra Pacific has entered into contracts with a total capacity of 1,178 MWs with contract termination dates ranging from 2022 to 2046. Included in these contracts are 992 MWs of capacity from renewable energy, of which 401 MWs of capacity are under development or construction and not currently available.
The Nevada Utilities manage certain risks relating to their supply of electricity and fuel requirements by entering into various contracts, which may be accounted for as derivatives, including forwards, futures, options, swaps and other agreements. Refer to NV Energy's "General Regulation" section in Item 1 of this Form 10-K for a discussion of energy cost recovery by jurisdiction and Nevada Power's Item 7A and Sierra Pacific's Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
Natural Gas
The Nevada Utilities rely on first-of-the-month indexed physical gas purchases for the majority of natural gas needed to operate their generating facilities. To secure natural gas supplies for the generating facilities, the Nevada Utilities execute purchases pursuant to a PUCN approved four season laddering strategy. In 2020, natural gas supply net purchases averaged 320,382 and 169,522 Dths per day with the winter period contracts averaging 273,504 and 189,422 Dths per day and the summer period contracts averaging 353,678 and 155,439 Dths per day for Nevada Power and Sierra Pacific, respectively. The Nevada Utilities believe supplies from these sources are presently adequate and available to meet its needs.
The Nevada Utilities contract for firm natural gas pipeline capacity to transport natural gas from production areas to their service territory through direct interconnects to the pipeline systems of several interstate natural gas pipeline systems, including Nevada Power who contracts with Kern River, an affiliated company. Sierra Pacific utilizes natural gas storage contracted from interstate pipelines to meet retail customer requirements and to manage the daily changes in demand due to changes in weather and other usage factors. The stored natural gas is typically replaced during off-peak months when the demand for natural gas is historically lower than during the heating season.
Coal
Sierra Pacific relies on spot market solicitations for coal supplies and will regularly monitor the western coal market for opportunities to meet these needs. Sierra Pacific has a transportation services contract with Union Pacific Railroad Company to ship coal from various origins in central Utah, western Colorado and Wyoming that expires December 31, 2025. Sierra Pacific has no commitments to purchase coal for 2021 or beyond. The Navajo Generating Station was shut down in November 2019 and Nevada Power has no coal requirements going forward.
Energy Imbalance Market
The Nevada Utilities participate in the EIM operated by the California ISO, which reduces costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrates renewables and enhances reliability through improved situational awareness and responsiveness. The EIM expands the real-time component of the California ISO's market technology to optimize and balance electricity supply and demand every five minutes across the EIM footprint. The EIM is voluntary and available to all balancing authorities in the western United States. EIM market participants submit bids to the California ISO market operator before each hour for each generating resource they choose to be dispatched by the market. Each bid is comprised of a dispatchable operating range, ramp rate and prices across the operating range. The California ISO market operator uses sophisticated technology to select the least-cost resources to meet demand and send simultaneous dispatch signals to every participating generator across the EIM footprint every five minutes. In addition to generation resource bids, the California ISO market operator also receives continuous real-time updates of the transmission grid network, meteorological and load forecast information that it uses to optimize dispatch instructions. Outside the EIM footprint, utilities in the western United States do not utilize comparable technology and are largely limited to transactions within the borders of their balancing authority area to balance supply and demand intra-hour using a combination of manual and automated dispatch. The EIM delivers customer benefits by leveraging automation and resource diversity to result in more efficient dispatch, more effective integration of renewables and improved situational awareness. Benefits are expected to increase further with renewable resource expansion and as more entities join the EIM bringing incremental diversity.
Transmission and Distribution
The Nevada Utilities' transmission system is part of the Western Interconnection, a regional grid in the United States. The Western Interconnection includes the interconnected transmission systems of 14 western states, two Canadian provinces and parts of Mexico. The Nevada Utilities' transmission system, together with contractual rights on other transmission systems, enables the Nevada Utilities to integrate and access generation resources to meet their customer load requirements. Nevada Power's transmission and distribution systems included approximately 1,900 miles of transmission lines, 14,000 miles of distribution lines and 210 substations as of December 31, 2020. Sierra Pacific's transmission and distribution systems included approximately 4,200 miles of transmission lines, 9,500 miles of distribution lines and 200 substations as of December 31, 2020.
ON Line is a 231-mile, 500-kV transmission line connecting Nevada Power's and Sierra Pacific's service territories. ON Line provides the ability to jointly dispatch energy throughout Nevada and provide access to renewable energy resources in parts of northern and eastern Nevada, which enhances the Nevada Utilities' ability to manage and optimize their generating facilities. ON Line provides between 600 MW northbound and 900 MW southbound of transfer capability with interconnection between the Robinson Summit substation on the Sierra Pacific system and the Harry Allen substation on the Nevada Power system. ON Line was a joint project between the Nevada Utilities and Great Basin Transmission, LLC. The Nevada Utilities own a 25% interest in ON Line and have entered into a long-term transmission use agreement with Great Basin Transmission, LLC for its 75% interest in ON Line until 2054. The Nevada Utilities share of its 25% interest in ON Line and the long-term transmission use agreement is split 75% for Nevada Power and 25% for Sierra Pacific, previously split 95% for Nevada Power and 5% for Sierra Pacific. In December 2019, the PUCN approved an order to update the split starting January 1, 2020 to 75% for Nevada Power and 25% for Sierra Pacific to more accurately reflect the benefits obtained from the transmission line. In August 2020, the FERC approved the amended agreement between the Nevada Utilities and Great Basin Transmission, LLC that reallocated the PUCN-approved, updated ownership percentage from Nevada Power to Sierra Pacific.
Future Generation, Conservation and Energy Efficiency
Energy Supply Planning
Within the energy supply planning process, there are four key components covering different time frames:
•IRPs are filed by the Nevada Utilities for approval by the PUCN every three years and the Nevada Utilities may, as necessary, file amendments to their IRPs. IRPs are prepared in compliance with Nevada laws and regulations and cover a 20-year period. Nevada law governing the IRP process was modified in 2017 and now requires joint filings by Nevada Power and Sierra Pacific. IRPs develop a comprehensive, integrated plan that considers customer energy requirements and propose the resources to meet those requirements in a manner that is consistent with prevailing market fundamentals. The ultimate goal of the IRPs is to balance the objectives of minimizing costs and reducing volatility while reliably meeting the electric needs of the Nevada Utilities' customers. Costs incurred to complete projects approved through the IRP process still remain subject to review for reasonableness by the PUCN.
•Energy Supply Plans ("ESP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The ESP has a one- to three-year planning horizon and is an intermediate-term resource procurement and risk management plan that establishes the supply portfolio strategies within which intermediate-term resource requirements will be met with PUCN approval required for executing contracts of longer than three years.
•Distributed Resource Plans ("DRP") are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP. The DRP establishes a formal process to aid in the cost-effective integration of distributed resources into the Nevada Utilities' distribution and transmission process and ultimately the NV Energy utilities' electricity grid.
•Action plans are filed with the PUCN for approval and operate in conjunction with the PUCN-approved 20-year IRP and PUCN-approved ESP. The action plan establishes tactical execution activities with a one-month to twelve-month focus.
In July 2020, the Nevada Utilities filed their fourth amendment to the IRP requesting approval of two new renewable energy power purchase agreements, a utility-owned renewable facility, a utility-owned community scale renewable facility and updates to the Transmission Plan. In July 2020, the Nevada Utilities also filed a joint petition requesting to defer the September 2020 filing of the Updated Distributed Resource Plans until its June 2021 Joint Integrated Resource Plan is filed. In September 2020, the PUCN issued an order granting the petition to defer the filing and ordered the Nevada Utilities to conduct an informal workshop in October 2020 to provide an update of the distributed resources plan and present information consistent with the statutory requirements. In November 2020, the Nevada Utilities filed a settlement stipulation for Phase I of the fourth amendment to the IRP, which was followed by a hearing. The settlement resolved all issues related to the load forecast, four renewable energy projects and certain transmission investments. The stipulation was approved by the PUCN in December 2020. Phase II hearing was scheduled in February 2021.
Emissions Reduction and Capacity Replacement Plan
In compliance with Senate Bill No. 123, Nevada Power retired 255 MWs of coal-fueled generation in 2019 in addition to the 557 MWs of coal-fueled generation retired in 2017. Consistent with the Emissions Reduction and Capacity Replacement Plan ("ERCR Plan"), between 2014 and 2016, Nevada Power acquired 536 MWs of natural gas generating resources, executed long-term power purchase agreements for 200 MWs of nameplate renewable energy capacity and constructed a 15-MW solar photovoltaic facility. Nevada Power has the option to acquire 35 MWs of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval.
Energy Efficiency Programs
The Nevada Utilities have provided a comprehensive set of energy efficiency, demand response and conservation programs to their Nevada electric customers. The programs are designed to reduce energy consumption and more effectively manage when energy is used, including management of seasonal peak loads. Current programs offer services to customers such as energy audits and customer education and awareness efforts that provide information on how to improve the efficiency of their homes and businesses. To assist customers in investing in energy efficiency, the Nevada Utilities have offered rebates or incentives encouraging the purchase and installation of high-efficiency equipment such as lighting, heating and cooling equipment, weatherization, motors, process equipment and systems, as well as incentives for efficient construction. Incentives are also paid to residential customers who participate in the air conditioner load control program and nonresidential customers who participate in the nonresidential load management program. Energy efficiency program costs are recovered through annual rates set by the PUCN, and adjusted based on the Nevada Utilities' annual filing to recover current program costs and any over or under collections from the prior filing, subject to prudence review. During 2020, Nevada Power spent $33 million on energy efficiency programs, resulting in an estimated 218,913 MWhs of electric energy savings and an estimated 207 MWs of electric peak load management. During 2020, Sierra Pacific spent $10 million on energy efficiency programs, resulting in an estimated 96,933 MWhs of electric energy savings and an estimated 32 MWs of electric peak load management.
Regulated Natural Gas Operations
Sierra Pacific is engaged in the distribution of natural gas to customers in its service territory and the related procurement, transportation and storage of natural gas for the benefit of those customers. Sierra Pacific purchases natural gas from various suppliers and contracts with interstate natural gas pipelines for transportation of the natural gas from the production areas to Sierra Pacific's service territory and for storage services to manage fluctuations in system demand and seasonal pricing. Sierra Pacific sells natural gas and delivery services to end-use customers on its distribution system; sells natural gas to other utilities, municipalities and energy marketing companies; and transports natural gas through its distribution system for a number of end-use customers who have independently secured their supply of natural gas. During 2020, 10% of the total natural gas delivered through Sierra Pacific's distribution system was for transportation service.
Natural gas property consists primarily of natural gas mains and service lines, meters, and related distribution equipment, including feeder lines to communities served from natural gas pipelines owned by others. The natural gas distribution facilities of Sierra Pacific included 3,500 miles of natural gas mains and service lines as of December 31, 2020.
Customer Usage and Seasonality
The percentages of natural gas sold to Sierra Pacific's retail and wholesale customers by class of customer, total Dths of natural gas sold, total Dths of transportation service and the average number of retail customers for the years ended December 31 were as follows:
(1)Commercial and industrial customers are classified primarily based on the nature of their business and natural gas usage. Commercial customers are non-residential customers with monthly gas usage less than 12,000 therms during five consecutive winter months. Industrial customers are non-residential customers that use natural gas in excess of 12,000 therms during one or more winter months.
(2)Wholesale sales are generally made to other utilities, municipalities and energy marketing companies for eventual resale to end-use customers.
There are seasonal variations in Sierra Pacific's regulated natural gas business that are principally due to the use of natural gas for heating. Typically, 47-56% of Sierra Pacific's regulated natural gas revenue is reported in the months of December through March.
On February 3, 2020, Sierra Pacific recorded its highest peak-day natural gas delivery of 141,416 Dths, which is 22,158 Dths less than the record peak-day delivery of 163,574 Dths set on December 9, 2013. This peak-day delivery consisted of 95% traditional retail sales service and 5% transportation service.
Fuel Supply and Capacity
The purchase of natural gas for Sierra Pacific's regulated natural gas operations is done in combination with the purchase of natural gas for Sierra Pacific's regulated electric operations. In response to energy supply challenges, Sierra Pacific has adopted an approach to managing the energy supply function that has three primary elements, as discussed earlier under Generating Facilities and Fuel Supply. Similar to Sierra Pacific's regulated electric operations, as long as Sierra Pacific's purchases of natural gas are deemed prudent by the PUCN, through its annual prudency review, Sierra Pacific is permitted to recover the cost of natural gas. Sierra Pacific also has the ability, with PUCN approval, to reset quarterly the BTERs, based on the last twelve months fuel costs, and to reset quarterly DEAA.
Human Capital
Employees
As of December 31, 2020, Nevada Power had approximately 1,400 employees, of which approximately 700 were covered by a union contract with the International Brotherhood of Electrical Workers.
As of December 31, 2020, Sierra Pacific had approximately 1,000 employees, of which approximately 500 were covered by a union contract with the International Brotherhood of Electrical Workers.
For more information regarding Nevada Power's and Sierra Pacific's human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.
NORTHERN POWERGRID
Northern Powergrid, an indirect wholly owned subsidiary of BHE, is a holding company which owns two companies that distribute electricity in Great Britain, Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc. In addition to the Northern Powergrid Distribution Companies, Northern Powergrid also owns a meter asset rental business that leases meters to energy suppliers in the United Kingdom, an engineering contracting business that provides electrical infrastructure contracting services primarily to third parties and a hydrocarbon exploration and development business that is focused on developing integrated upstream gas projects in Europe and Australia.
The Northern Powergrid Distribution Companies serve 3.9 million end-users and operate in the north-east of England from North Northumberland through Tyne and Wear, County Durham and Yorkshire to North Lincolnshire, an area covering 10,000 square miles. The principal function of the Northern Powergrid Distribution Companies is to build, maintain and operate the electricity distribution network through which the end-user receives a supply of electricity.
The Northern Powergrid Distribution Companies receive electricity from the national grid transmission system and from generators that are directly connected to the distribution network and distribute it to end-users' premises using their networks of transformers, switchgear and distribution lines and cables. Substantially all of the end-users in the Northern Powergrid Distribution Companies' distribution service areas are directly or indirectly connected to the Northern Powergrid Distribution Companies' networks and electricity can only be delivered to these end-users through their distribution systems, thus providing the Northern Powergrid Distribution Companies with distribution volumes that are relatively stable from year to year. The Northern Powergrid Distribution Companies charge fees for the use of their distribution systems to the suppliers of electricity.
The suppliers purchase electricity from generators, sell the electricity to end-user customers and use the Northern Powergrid Distribution Companies' distribution networks pursuant to an industry standard "Distribution Connection and Use of System Agreement." During 2020, RWE Npower PLC and certain of its affiliates and British Gas Trading Limited represented 15% and 12%, respectively, of the total combined distribution revenue of the Northern Powergrid Distribution Companies. Variations in demand from end-users can affect the revenues that are received by the Northern Powergrid Distribution Companies in any year, but such variations have no effect on the total revenue that the Northern Powergrid Distribution Companies are allowed to recover in a price control period. Under- or over-recoveries against price-controlled revenues are carried forward into prices for future years.
The Northern Powergrid Distribution Companies' combined service territory features a diverse economy with no dominant sector. The mix of rural, agricultural, urban and industrial areas covers a broad customer base ranging from domestic usage through farming and retail to major industry including automotives, chemicals, mining, steelmaking and offshore marine construction. The industry within the area is concentrated around the principal centers of Newcastle, Middlesbrough, Sheffield and Leeds.
The price controlled revenue of the Northern Powergrid Distribution Companies is set out in the special conditions of the licenses of those companies. The licenses are enforced by the regulator, GEMA, through the Ofgem and limit increases to allowed revenues (or may require decreases) based upon the rate of inflation, other specified factors and other regulatory action. Changes to the price controls can be made by the regulator, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority ("CMA"). It has been the convention in Great Britain for regulators to conduct periodic regulatory reviews before making proposals for any changes to the price controls. The current electricity distribution price control became effective April 1, 2015 and will continue through March 31, 2023.
GWhs and percentages of electricity distributed to the Northern Powergrid Distribution Companies' end-users and the total number of end-users as of and for the years ended December 31 were as follows:
(1) The increase in industrial and decrease in commercial is largely due to the Great Britain-wide customer reclassifications which are in progress (as a result of Ofgem approved industry changes), negatively impacting commercial volumes by 100 GWhs in 2018 compared to 2017.
As of December 31, 2020, the combined electricity distribution network of the Northern Powergrid Distribution Companies included approximately 17,300 miles of overhead lines, 42,800 miles of underground cables and 770 major substations.
BHE PIPELINE GROUP (EASTERN ENERGY GAS)
BHE GT&S
BHE GT&S is an indirect wholly owned subsidiary of BHE. BHE GT&S' operations, through its ownership of Eastern Energy Gas, includes three interstate natural gas pipeline systems, one of the nation's largest underground natural gas storage systems and one liquefied natural gas export, import and storage facility. BHE GT&S' operations also include two smaller liquefied natural gas facilities, one field service company, and one gathering and processing company.
Eastern Energy Gas' principal subsidiaries are EGTS and Carolina Gas Transmission, LLC ("CGT"). EGTS's operations include natural gas transmission and storage pipelines located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. CGT's operations include an interstate natural gas pipeline system located in South Carolina and southeastern Georgia. Eastern Energy Gas also owns a 50% equity interest in Iroquois Gas Transmission System L.P. ("Iroquois"). Iroquois owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut.
Eastern Energy Gas' LNG operations involve the export, import and storage of LNG at the Cove Point LNG Facility that is owned by Cove Point LNG, LP ("Cove Point"), located in Maryland, as well as the transportation of regasified LNG to the interstate pipeline grid and mid-Atlantic markets and the liquefaction of natural gas for export as LNG. Cove Point's LNG Facility has an operational peak regasification daily send-out capacity of approximately 1.8 million Dth and an aggregate LNG storage capacity of approximately 14.6 billions of cubic feet equivalent ("Bcfe"). In addition, Cove Point has a small liquefier that has the potential to produce approximately 15,000 Dth/day. The Liquefaction Facility consists of one LNG train with a nameplate outlet capacity of 5.25 million tonnes per annum ("Mtpa"). Cove Point has authorization from the Department of Energy ("DOE") to export up to 0.77 Bcfe/day (approximately 5.75 Mtpa) should the Liquefaction Facility perform better than expected. Cove Point's 36-inch diameter underground interstate natural gas pipelines are approximately 139 miles, with interconnections to Transcontinental Gas Pipeline, LLC in Fairfax County, Virginia, and with Columbia Gas Transmission, LLC and EGTS in Loudoun County, Virginia. Eastern Energy Gas operates, as the general partner, and owns a 25% limited partnership interest in the Cove Point liquefied natural gas export, import and storage facility. BHE GT&S also operates and has ownership interests in three smaller liquefied natural gas facilities in Alabama, Florida and Pennsylvania.
In total, Eastern Energy Gas operates approximately 5,400 miles of natural gas transmission, gathering and storage pipelines, of which approximately 5,300 miles are owned by Eastern Energy Gas, with a design capacity of 12.5 Bcf per day as well as approximately 100 miles of natural gas liquids pipelines operated by BHE GT&S. Eastern Energy Gas also operates 17 underground storage fields with a total operating storage design capacity of approximately 420 Bcf, of which approximately 306 Bcf relates to natural gas storage field capacity that Eastern Energy Gas owns.
BHE GT&S' pipeline system is configured with approximately 360 active receipt and delivery points. In 2020, BHE GT&S delivered over 2.0 trillion cubic feet ("Tcf") of natural gas to its customers.
BHE GT&S' natural gas transmission and storage earnings primarily result from rates established by FERC. Revenues derived from BHE GT&S' pipeline operations are primarily from reservation charges for firm transportation and storage services as provided for in their FERC-approved tariffs. Reservation charges are required to be paid regardless of volumes transported or stored. The profitability of these businesses is dependent on their ability, through the rates they are permitted to charge, to recover costs and earn a reasonable return on their capital investments. Approximately 91% of BHE GT&S' transmission capacity is subscribed including 88% under long-term contracts (two years or greater) and 3% on a year-to-year basis. BHE GT&S' storage services are 100% subscribed with long-term contracts. Additionally, BHE GT&S receives revenue from firm fee-based contractual arrangements, including negotiated rates, for certain pipeline transportation and LNG storage and terminal services. Variability in BHE GT&S' earnings results from changes in operating and maintenance expenditures, as well as changes in rates and the demand for services, which are dependent on weather, changes in commodity prices and the economy.
Except for quantities of natural gas owned and managed for operational and system balancing purposes, BHE GT&S does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes, sales from our field services company and sales of natural gas liquids accounts for the majority of the remaining operating revenue.
During 2020, BHE GT&S had two customers that each accounted for greater than 10% of its operating revenue and its ten largest customers accounted for 53% of its total operating revenue. BHE GT&S has agreements with terms through 2038 to retain the majority of its two largest customers' volumes. The loss of any of these significant customers, if not replaced, could have a material adverse effect on BHE GT&S.
Human Capital
Employees
As of December 31, 2020, Eastern Energy Gas had approximately 1,500 employees, consisting of approximately 1,100 natural gas operations employees and 400 corporate services employees. As of December 31, 2020, approximately 600 employees were covered by a union contract with the Utility Workers Union of America. For more information regarding Eastern Energy Gas' human capital disclosures, refer to Item 1. Business - General section of this Form 10-K.
Northern Natural Gas
Northern Natural Gas, an indirect wholly owned subsidiary of BHE, owns the largest interstate natural gas pipeline system in the United States, as measured by pipeline miles, which reaches from west Texas to Michigan's Upper Peninsula. Northern Natural Gas primarily transports and stores natural gas for utilities, municipalities, gas marketing companies and industrial and commercial users. Northern Natural Gas' pipeline system consists of two commercial segments. Its traditional end-use and distribution market area in the northern part of its system, referred to as the Market Area, includes points in Iowa, Nebraska, Minnesota, Wisconsin, South Dakota, Michigan and Illinois. Its natural gas supply and delivery service area in the southern part of its system, referred to as the Field Area, includes points in Kansas, Texas, Oklahoma and New Mexico. The Market Area and Field Area are separated at a Demarcation Point ("Demarc"). Northern Natural Gas' pipeline system consists of 14,500 miles of natural gas pipelines, including 6,000 miles of mainline transmission pipelines and 8,500 miles of branch and lateral pipelines, with a Market Area design capacity of 6.3 Bcf per day, a Field Area delivery capacity of 1.7 Bcf per day to the Market Area and 1.4 Bcf per day to the West Texas area and over 79 Bcf of firm service and operational storage cycle capacity in five storage facilities. Northern Natural Gas' pipeline system is configured with approximately 2,240 active receipt and delivery points which are integrated with the facilities of LDCs. Many of Northern Natural Gas' LDC customers are part of combined utilities that also use natural gas as a fuel source for electric generation. Northern Natural Gas delivered over 1.3 Tcf of natural gas to its customers in 2020.
Northern Natural Gas' transportation rates and most of its storage rates are cost-based. These rates are designed to provide Northern Natural Gas with an opportunity to recover its costs of providing services and earn a reasonable return on its investments. In addition, Northern Natural Gas has fixed rates that are market-based for certain of its firm storage contracts with contract terms that expire in 2028.
Northern Natural Gas' operating revenue for the years ended December 31 was as follows (in millions):
Substantially all of Northern Natural Gas' Market Area transportation revenue is generated from reservation charges, with the balance from usage charges. Northern Natural Gas transports natural gas primarily to local distribution markets and end-users in the Market Area. Northern Natural Gas provides service to 84 utilities, including MidAmerican Energy, an affiliate company, which serve numerous residential, commercial and industrial customers. Most of Northern Natural Gas' transportation capacity in the Market Area is committed to customers under firm transportation contracts, where customers pay Northern Natural Gas a monthly reservation charge for the right to transport natural gas through Northern Natural Gas' system. Reservation charges are required to be paid regardless of volumes transported or stored. As of December 31, 2020, approximately 75% of Northern Natural Gas' customers' entitlement in the Market Area have terms beyond 2022 and approximately 51% beyond 2024. As of December 31, 2020, the weighted average remaining contract term for Northern Natural Gas' Market Area firm transportation contracts is over six years.
Northern Natural Gas' Field Area customers consist primarily of energy marketing companies and midstream companies, which take advantage of the price spread opportunities created between Field Area supply points and Demarc. In addition, there are a growing number of midstream customers that are delivering gas south in the Field Area to the Waha Hub market. The remaining Field Area transportation service is sold to power generators connected to Northern Natural Gas' system in Texas and New Mexico that are contracted on a long-term basis with a weighted average remaining contract term of six years, and various LDCs, energy marketing companies and midstream companies for both connected and off-system markets.
Northern Natural Gas' storage services are provided through the operation of one underground natural gas storage field in Iowa and two underground natural gas storage facilities in Kansas. Additionally, Northern Natural Gas has two LNG storage peaking units, one in Iowa and one in Minnesota, that support its transportation service. The three underground natural gas storage facilities and two LNG storage peaking units have a total firm service and operational storage cycle capacity of over 79 Bcf and over 2.2 Bcf per day of peak delivery capability. These storage facilities provide operational flexibility for the daily balancing of Northern Natural Gas' system and provide services to customers for their winter peaking and year-round load swing requirements. Northern Natural Gas has 65.1 Bcf of firm storage contracts. Firm storage contracts at maximum tariff rates represent 54.4 Bcf, and the market-based rate contracts represent the remaining 10.7 Bcf. The average remaining contract term for firm storage contracts is five years.
Except for quantities of natural gas owned and managed for operational and system balancing purposes, Northern Natural Gas does not own the natural gas that is transported through its system. The sale of natural gas for operational and system balancing purposes accounts for the majority of the remaining operating revenue.
During 2020, Northern Natural Gas had two customers that each accounted for greater than 10% of its transportation and storage revenue and its ten largest customers accounted for 64% of its system-wide transportation and storage revenue. Northern Natural Gas has agreements with terms through 2029 and 2034 to retain the majority of its two largest customers' volumes. The loss of any of these significant customers, if not replaced, could have a material adverse effect on Northern Natural Gas.
Northern Natural Gas' extensive pipeline system, which is interconnected with many interstate and intrastate pipelines in the national grid system, has access to multiple major supply basins. Direct access is available from producers in the Anadarko, Permian and Hugoton basins, some of which have experienced increased production from shale and tight sands formations adjacent to Northern Natural Gas' pipeline. Since 2011, the pipeline has connected 2,395,000 Dths per day of supply access from the Midland and Delaware Basins within the Permian Basin area in west Texas and from the Granite Wash tight sands formations in the Texas panhandle and in Oklahoma. Additionally, Northern Natural Gas has interconnections with several interstate pipelines and several intrastate pipelines with receipt, delivery, or bi-directional capabilities. Because of Northern Natural Gas' location and multiple interconnections it is able to access natural gas from other key production areas, such as the Rocky Mountain, Williston, including the Bakken formation, and western Canadian basins. The Rocky Mountain basins are accessed through interconnects with Trailblazer Pipeline Company, Tallgrass Interstate Gas Transmission, LLC, Cheyenne Plains Gas Pipeline Company, LLC, Colorado Interstate Gas Company and Rockies Express Pipeline, LLC ("REX"). The western Canadian basins are accessed through interconnects with Northern Border Pipeline Company ("Northern Border"), Great Lakes Gas Transmission Limited Partnership ("Great Lakes") and Viking Gas Transmission Company ("Viking"). This supply diversity and access to both stable and growing production areas provides significant flexibility to Northern Natural Gas' system and customers.
Northern Natural Gas' system experiences significant seasonal swings in demand and revenue typically with approximately 60% of transportation revenue occurring during the months of November through March. This seasonality provides Northern Natural Gas with opportunities to deliver additional value-added services, such as firm and interruptible storage services. As a result of Northern Natural Gas' geographic location in the middle of the United States and its many interconnections with other pipelines, Northern Natural Gas has the opportunity to augment its steady end user and LDC revenue by capitalizing on opportunities for shippers to reach additional markets, such as Chicago, Illinois, other parts of the Midwest, and Texas, through interconnects.
Kern River
Kern River, an indirect wholly owned subsidiary of BHE, owns an interstate natural gas pipeline system that extends from supply areas in the Rocky Mountains to consuming markets in Utah, Nevada and California. Kern River operates 1,400 miles of mainline natural gas pipelines, with a design capacity of 2,166,575 Dths, or 2.2 Bcf, per day. The mainline pipeline extends from the system's point of origination near Opal, Wyoming, through the Central Rocky Mountains to Daggett, California. The mainline section consists of 1,300 miles of 36-inch diameter pipeline and 100 miles of various laterals that connect to the mainline. Except for quantities of natural gas owned for operational purposes, Kern River does not own the natural gas that is transported through its system. Kern River's transportation rates are cost-based. The rates are designed to provide Kern River with an opportunity to recover its costs of providing services and earn a reasonable return on its investments.
Kern River's rates are based on a levelized rate design with recovery of 70% of the original investment during the initial long-term contracts ("Period One rates"). After expiration of the initial term, eligible customers have the option to elect service at rates ("Period Two rates") that are lower than Period One rates because they are designed to recover the remaining 30% of the original investment. To the extent that eligible customers do not contract for service at Period Two rates, the volumes are turned back and sold at market rates for varying terms. As of December 31, 2020, initial Period One contracts total 331,921 Dths per day. Period Two contracts total 1,054,029 Dths per day and 569,631 Dths per day of total turned back volume has an average remaining contract term of more than two years. The remaining capacity is sold on a short-term basis at market rates.
As of December 31, 2020, approximately 76% of Kern River's design capacity of 2,166,575 Dths per day is contracted pursuant to long-term firm natural gas transportation service agreements, whereby Kern River receives natural gas on behalf of customers at designated receipt points and transports the natural gas on a firm basis to designated delivery points. In return for this service, each customer pays Kern River a fixed monthly reservation fee based on each customer's maximum daily quantity, which represents nearly 86% of total operating revenue, and a commodity charge based on the actual amount of natural gas transported pursuant to its long-term firm natural gas transportation service agreements and Kern River's tariff.
These long-term firm natural gas transportation service agreements expire between April 2022 and April 2033 and have a weighted-average remaining contract term of over eight years. Kern River's customers include electric and natural gas distribution utilities, major oil and natural gas companies or affiliates of such companies, electric generating companies, energy marketing and trading companies and financial institutions. As of December 31, 2020, 73% of the firm capacity under contract has primary delivery points in California, with the flexibility to access secondary delivery points in Nevada and Utah. In 2019, Kern River provided approximately 26% of California's demand for natural gas.
During 2020, Kern River had two customers, including Nevada Power Company, d/b/a NV Energy, that each accounted for greater than 10% of its revenue. The loss of these significant customers, if not replaced, could have a material adverse effect on Kern River.
Competition
The Pipeline Companies compete with other pipelines on the basis of cost, flexibility, reliability of service and overall customer service, with the customer's decision being made primarily on the basis of delivered price, which includes both the natural gas commodity cost and transportation costs. The Pipeline Companies also compete with midstream operators and gas marketers seeking to provide or arrange transportation, storage and other services to meet customer needs. Natural gas competes with alternative energy sources, including coal, nuclear energy, wind, geothermal, solar and fuel oil and the electricity generated from these alternative energy sources. Legislation and governmental regulations, weather, futures markets, production costs and other factors beyond the control of the Pipeline Companies, influence the price of the natural gas commodity. Additionally, natural gas demand could be adversely affected by laws mandating or incenting renewable power sources that produce fewer GHG emissions than natural gas.
The Pipeline Companies generate a substantial portion of their revenue from long-term firm contracts for transportation and storage services and are therefore insulated from competitive factors during the terms of the contracts. When these long-term contracts expire, the Pipeline Companies face competitive pressures from other natural gas pipeline facilities. The Pipeline Companies' ability to extend existing customer contracts, remarket expiring contracted capacity or market new capacity is dependent on competitive alternatives, the regulatory environment and the market supply and demand factors at the relevant dates these contracts are eligible to be renewed or extended. The duration of new or renegotiated contracts will be affected by current commodity and transportation prices, competitive conditions and customers' judgments concerning future market trends and volatility.
Subject to regulatory requirements, the Pipeline Companies attempt to recontract or remarket capacity at the maximum rates allowed under their tariffs, although at times the Pipeline Companies discount these rates to remain competitive. Historically, the Pipeline Companies have been able to provide competitively priced services because of access to a variety of relatively low cost supply basins, cost control measures and the relatively high level of firm entitlement that is sold on a seasonal and annual basis, which lowers the per unit cost of transportation. To date, the Pipeline Companies have avoided significant pipeline system bypasses.
BHE GT&S' natural gas transmission operations compete with domestic and Canadian pipeline companies. The combination of reliable and flexible services, access to highly liquid and attractive pricing locations, significant storage capability, availability of numerous receipt and delivery points along its pipeline system and capacity rights held on third party pipelines enable BHE GT&S to tailor its services to meet the needs of individual customers.
Northern Natural Gas needs to compete aggressively to serve existing load and add new load. Northern Natural Gas' attractive competitive position relative to other pipelines in the upper Midwest is reinforced each winter as customers expect, and receive, reliable deliveries of natural gas for their critical markets. Northern Natural Gas provides customers access to multiple supply basins that allow customers to obtain reliable supplies at competitive prices, not subject to the natural gas grid dynamics from pipeline competition that would limit customers to a singular supply source. Northern Natural Gas has been successful in competing for a significant amount of the increased demand related to residential and commercial needs and the construction of new power plants and new fertilizer or other industrial plants.
Other than the short-term transportation associated with the Permian business, Northern Natural Gas expects the current level of Field Area contracting to Demarc to continue in the foreseeable future, as Market Area customers presently need to purchase competitively-priced supplies from the Field Area to support their existing and growth demand requirements. However, the revenue received from these Field Area contracts is expected to decrease due to construction of new pipeline facilities.
Kern River is the only interstate pipeline that presently delivers natural gas directly from the Rocky Mountain gas supply region to end-users in the Southern California market. Kern River's levelized rate structure and access to upstream pipelines, storage facilities and economic Rocky Mountain gas reserves increase its competitiveness and attractiveness to end-users. Kern River believes it has an advantage relative to other interstate pipelines serving Southern California because its relatively new pipeline can be economically expanded and has required significantly less capital expenditures and ongoing maintenance than other systems.
Cove Point's gas transportation, LNG import and storage operations, as well as the Liquefaction Facility's capacity, are contracted primarily under long-term fixed reservation fee agreements. However, in the future Cove Point may compete with other independent terminal operators as well as major oil and gas companies on the basis of terminal location, services provided and price. In addition, the Liquefaction Facility may face competition on a global scale as international customers explore other options to meet their energy needs.
BHE TRANSMISSION
BHE Canada
BHE Canada, an indirect wholly owned subsidiary of BHE, primarily owns AltaLink, a regulated electric transmission-only utility company headquartered in Alberta, Canada serving approximately 85% of Alberta's population. AltaLink's high voltage transmission lines and related facilities transmit electricity from generating facilities to major load centers, cities and large industrial plants throughout its 87,000 square mile service territory, which covers a diverse geographic area including most major urban centers in central and southern Alberta. AltaLink's transmission facilities, consisting of approximately 8,200 miles of transmission lines and approximately 310 substations as of December 31, 2020, are an integral part of the Alberta Interconnected Electric System ("AIES"). BHE Canada also owns MATL Canada L.P., a company headquartered in Alberta, Canada, which operates 82 miles of the 230 kV Montana Alberta Tie Line located in Canada (the entire transmission line runs from Lethbridge, Alberta, Canada to Great Falls, Montana, and connects power grids in the two jurisdictions).
The AIES is a network or grid of transmission facilities operating at high voltages ranging from 69 kVs to 500 kVs. The grid delivers electricity from generating units across Alberta, Canada through approximately 16,000 miles of transmission lines. The AIES is interconnected to British Columbia's transmission system that links Alberta with the North American western interconnected system, interconnection with Saskatchewan's transmission system and interconnection with Montana's transmission system.
AltaLink is a transmission facility owner within the electricity industry in Alberta and is permitted to charge a tariff rate for the use of its transmission facilities. Such tariff rates are established on a cost-of-service regulatory model, which is designed to allow AltaLink an opportunity to recover its costs of providing services and to earn a reasonable return on its investments. Transmission tariffs are approved by the AUC and are collected from the AESO.
The electricity industry in Alberta consists of four principal segments. Generators sell wholesale power into the power pool operated by the AESO and through direct contractual arrangements. Alberta's transmission system or grid is composed of high voltage power lines and related facilities that transmit electricity from generating facilities to distribution networks and directly connected end-users. Distribution facility owners are regulated by the AUC and are responsible for arranging for, or providing, regulated rate and regulated default supply services to convey electricity from transmission systems and distribution-connected generators to end-use customers. Retailers can procure energy through the power pool, through direct contractual arrangements with energy suppliers or ownership of generation facilities and arrange for its distribution to end-use customers.
The AESO mandate is defined in the Electric Utilities Act (Alberta) and its regulations, and requires the AESO to assess both current and future needs of Alberta's interconnected electrical system. In September 2019, the AESO released the 2019 Long-term Outlook, which is the AESO's forecast of Alberta's load and generation over the next 20 years, and is used as one input to guide the AESO in planning Alberta's transmission system. The 2019 Long-term Outlook includes a Reference Case Scenario, which is the AESO's main corporate forecast for long-term load growth and generation development in Alberta, and a set of alternative scenarios that are developed to understand future uncertainties. The Reference Case Scenario forecasts Alberta's electricity demand to grow at an annual rate of 0.9% over the next 20 years and a total of approximately 13 gigawatts of new generation capacity to be added for the same period. Other scenarios are developed based on modifying assumptions used in the Reference Case Scenario to reflect higher cogeneration development, alternative renewable policy, higher economic growth, lower economic growth, and a more diversified Alberta economy. The AESO indicates that it will continue monitoring economic, policy and industry development and if a scenario becomes more likely, the AESO may adopt it as its main forecast.
In January 2020, the AESO released the 2020 Long-term Transmission Plan. Developed based on a set of broad scenarios, the 2020 Long-term Transmission Plan seeks to optimize the use of Alberta's existing transmission system, and plan development of new transmission in a timely manner to provide for the safe, dependable and efficient delivery of electricity across Alberta. The AESO recognizes that the electricity industry is changing and therefore it continues to evolve its approach to planning. The 2020 Long-term Transmission Plan identifies 20 transmission developments proposed over the next five years, valued at approximately C$1.4 billion. These developments are estimated to increase average transmission rates by about C$0.50-C$0.70 per MW hour, starting in 2025. Approximately C$1.0 billion of the transmission developments are in AltaLink's service territory. Each of these developments will still require detailed needs analysis and regulatory approval prior to proceeding.
BHE U.S. Transmission
BHE U.S. Transmission, a wholly owned subsidiary of BHE, is engaged in various joint ventures to develop, own and operate transmission assets and is pursuing additional investment opportunities in the United States. Currently, BHE U.S. Transmission has two joint ventures with transmission assets that are operational. In May 2020, BHE U.S. Transmission acquired the general partner and limited partner interests in MATL LLP, a U.S based company with 132 line miles in the U.S. of the total 214 mile 230 kV line running from Lethbridge, Alberta, Canada to Great Falls, Montana.
BHE U.S. Transmission indirectly owns a 50% interest in ETT, along with subsidiaries of American Electric Power Company, Inc. ("AEP"). ETT owns and operates electric transmission assets in the ERCOT and, as of December 31, 2020, had total assets of $3.2 billion. ETT's transmission system includes approximately 1,900 miles of transmission lines and 38 substations as of December 31, 2020.
BHE U.S. Transmission also indirectly owns a 25% interest in Prairie Wind Transmission, LLC, a joint venture with AEP and Westar Energy, Inc., to build, own and operate a 108-mile, 345-kV transmission project in Kansas. The project had total assets of $136 million as of December 31, 2020.
BHE RENEWABLES
The subsidiaries comprising the BHE Renewables reportable segment own interests in several independent power projects in the United States and one in the Philippines. The following table presents certain information concerning these independent power projects as of December 31, 2020:
(1)San Diego Gas & Electric Company ("SDG&E"); Pacific Gas and Electric Company ("PG&E"), Ameren Illinois Company ("Ameren"), Southern California Edison ("SCE"), the Philippine National Irrigation Administration ("NIA"); Hawaii Electric Light Company, Inc. ("HELCO"); Austin Energy ("AE"); Omaha Public Power District ("OPPD"); Kimberly-Clark Corporation ("KC"); City of Denton, TX ("CODTX"); MidAmerican Energy Services, LLC ("MES"); U.S. General Services Administration ("USGSA"); Missouri Joint Municipal Electric Commission ("MJMEC"); Kansas Power Pool ("KPP"); Kansas Municipal Energy Agency ("KMEA"); City of Independence, MO ("COIMO"); and CPS Energy ("CPS").
(2)Facility Net Capacity represents the lesser of nominal ratings or any limitations under applicable interconnection, power purchase, or other agreements for intermittent resources and the total net dependable capability available during summer conditions for all other units. An intermittent resource's nominal rating is the manufacturer's contractually specified capability (in MWs) under specified conditions. Net Owned Capacity indicates BHE Renewables' ownership of Facility Net Capacity.
(3)Approximately 12% of the Company's interests in the Imperial Valley Projects' Contract Capacity are currently sold to Southern California Edison Company under a long-term power purchase agreement expiring in 2026. Certain long-term power purchase agreement renewals for 252 MWs have been entered into with other parties at fixed prices that expire from 2028 to 2039, of which 202 MWs mature in 2039.
(4)Under the terms of the agreement with the NIA, CalEnergy Philippines will own and operate the Casecnan project for a 20-year cooperation period which ends December 11, 2021, after which ownership and operation of the project will be transferred to the NIA at no cost on an "as-is" basis. NIA also pays CalEnergy Philippines for delivery of water pursuant to the agreement.
(5)The power purchasers are commercial, industrial and not-for-profit organizations.
(6)The community solar gardens project is consolidated in the table above for convenience as it consists of 98 distinct entities that each own an approximately 1-MW solar garden with independent but substantially similar terms and conditions.
Additionally, BHE Renewables has invested $6.2 billion in 32 wind projects sponsored by third parties, commonly referred to as tax equity investments.
The percentages of BHE Renewables' operating revenue derived from the following business activities for the years ended December 31 were as follows:
HOMESERVICES
HomeServices, a wholly-owned subsidiary of BHE, is the largest residential real estate brokerage firm in the United States. In addition to providing traditional residential real estate brokerage services, HomeServices offers other integrated real estate services, including mortgage originations and mortgage banking; title and closing services; property and casualty insurance; home warranties; relocation services; and other home-related services. HomeServices' real estate brokerage business is subject to seasonal fluctuations because more home sale transactions tend to close during the second and third quarters of the year. As a result, HomeServices' operating results and profitability are typically higher in the second and third quarters relative to the remainder of the year. HomeServices' owned brokerages currently operate in nearly 900 offices in 30 states and the District of Columbia with over 43,000 real estate agents under 46 brand names. The United States residential real estate brokerage business is subject to the general real estate market conditions, is highly competitive and consists of numerous local brokers and agents in each market seeking to represent sellers and buyers in residential real estate transactions.
HomeServices' franchise network currently includes approximately 370 franchisees primarily in the United States and internationally in over 1,600 brokerage offices with over 53,000 real estate agents under two brand names. In exchange for certain fees, HomeServices provides the right to use the Berkshire Hathaway HomeServices or Real Living brand names and other related service marks, as well as providing orientation programs, training and consultation services, advertising programs and other services.
OTHER ENERGY BUSINESSES
Effective January 1, 2016, MidAmerican Energy Company transferred its nonregulated energy operations to MES, a subsidiary of BHE. MES is a nonregulated energy business consisting of competitive electricity and natural gas retail sales. MES' electric operations predominantly include sales to retail customers in Illinois, Ohio, Texas, Pennsylvania, Maryland and other states that allow customers to choose their energy supplier. MES' natural gas operations predominantly include sales to retail customers in Iowa and Illinois. Electricity and natural gas are purchased from producers and third-party energy marketing companies and sold directly to commercial, industrial and governmental end-users. MES does not own electricity or natural gas production assets but hedges its contracted sales obligations either with physical supply arrangements or financial products. As of December 31, 2020, MES' contracts in place for the sale of electricity totaled 16,549 GWhs with an average term of 2.7 years and for the sale of natural gas totaled 20,655,206 Dths with an average term of 1.2 years. In addition, MES manages natural gas supplies for a number of smaller commercial end-users, which includes the sale of natural gas to these customers to meet their supply requirements. Refer to Item 7A in this Form 10-K for a discussion of commodity price risk and derivative contracts.
GENERAL REGULATION
BHE's regulated subsidiaries and certain affiliates are subject to comprehensive governmental regulation, which significantly influences their operating environment, prices charged to customers, capital structure, costs and, ultimately, their ability to recover costs and earn a reasonable return on invested capital. In addition to the discussion contained herein regarding general regulation, refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion regarding certain regulatory matters.
Domestic Regulated Public Utility Subsidiaries
The Utilities are subject to comprehensive regulation by various state, federal and local agencies. The more significant aspects of this regulatory framework are described below.
State Regulation
Historically, state regulatory commissions have established retail electric and natural gas rates on a cost-of-service basis, which are designed to allow a utility the opportunity to recover what each state regulatory commission deems to be the utility's reasonable costs of providing services, including a fair opportunity to earn a reasonable return on its investments based on its cost of debt and equity. In addition to return on investment, a utility's cost of service generally reflects a representative level of prudent expenses, including cost of sales, operating expense, depreciation and amortization and income and other tax expense, reduced by wholesale electricity and other revenue. The allowed operating expenses are typically based on actual historical costs adjusted for known and measurable or forecasted changes. State regulatory commissions may adjust cost of service for various reasons, including pursuant to a review of: (a) the utility's revenue and expenses during a defined test period, (b) the utility's level of investment and (c) changes in income tax laws. State regulatory commissions typically have the authority to review and change rates on their own initiative; however, they may also initiate reviews at the request of a utility, utility customers or organizations representing groups of customers. In certain jurisdictions, the utility and such parties, however, may agree with one another not to request a review of or changes to rates for a specified period of time.
The retail electric rates of the Utilities are generally based on the cost of providing traditional bundled services, including generation, transmission and distribution services. The Utilities have established ECAMs and other cost recovery mechanisms in certain states, which help mitigate their exposure to changes in costs from those assumed in establishing base rates.
With certain limited exceptions, the Utilities have an exclusive right to serve retail customers within their service territories and, in turn, have an obligation to provide service to those customers. In some jurisdictions, certain classes of customers may choose to purchase all or a portion of their energy from alternative energy suppliers, and in some jurisdictions retail customers can generate all or a portion of their own energy. Under Oregon law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, nonresidential customers have the right to choose an alternative provider of energy supply. The impact of this right on PacifiCorp's consolidated financial results has not been material. In Washington, state law does not provide for exclusive service territory allocation. PacifiCorp's service territory in Washington is surrounded by other public utilities with whom PacifiCorp has from time to time entered into service area agreements under the jurisdiction of the WUTC. Under California law, PacifiCorp has the exclusive right and obligation to provide electricity distribution services to all residential and nonresidential customers within its allocated service territory; however, cities, counties and certain other public agencies have the right to choose to generate energy supply or elect an alternative provider of energy supply through the formation of a Community Choice Aggregator ("CCA"). To date, no CCA activity has occurred in PacifiCorp's California service territory. If a CCA is formed, PacifiCorp would continue to provide CCA customers transmission, distribution, metering and billing services and the CCA would provide generation supply. In addition, PacifiCorp would likely be able to collect costs from CCA customers for the generation-related costs that PacifiCorp incurred while they were customers of PacifiCorp. PacifiCorp would remain the electricity provider of last resort for these customers. In Illinois, state law has established a competitive environment so that all Illinois customers are free to choose their retail service supplier. For customers that choose an alternative retail energy supplier, MidAmerican Energy continues to have an ongoing obligation to deliver the supplier's energy to the retail customer. MidAmerican Energy bills the retail customer for such delivery services. MidAmerican Energy also has an obligation to serve customers at regulated cost-based rates and has a continuing obligation to serve customers who have not selected a competitive electricity provider. The impact of this right on MidAmerican Energy's financial results has not been material. In Nevada, Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file a letter of intent and application with the PUCN to acquire electric energy and ancillary services from another energy supplier. The law requires customers wishing to choose a new supplier to receive the approval of the PUCN to meet public interest standards. In particular, departing customers must secure new energy resources that are not under contract to the Nevada Utilities, the departure must not burden the Nevada Utilities with increased costs or cause any remaining customers to pay increased costs and the departing customers must pay their portion of any deferred energy balances, all as determined by the PUCN. Also, the Utilities and the state regulatory commissions are individually evaluating how best to integrate private generation resources into their service and rate design, including considering such factors as maintaining high levels of customer safety and service reliability, minimizing adverse cost impacts and fairly allocating costs among all customers.
In Nevada, large natural gas customers using 12,000 therms per month with fuel switching capability are allowed to participate in the incentive natural gas rate tariff. Once a service agreement has been executed, a customer can compare natural gas prices under this tariff to alternative energy sources and choose its source of natural gas. In addition, natural gas customers using greater than 1,000 therms per day have the ability to secure their own natural gas supplies under the gas transportation tariff.
PacifiCorp
Rate Filings
Under Utah law, the UPSC must issue a written order within 240 days of a public utility's application for a general rate change. Absent an order, the proposed rates go into effect as filed and are not subject to refund, the UPSC may allow interim rates to take effect within 45 days of an application, subject to refund or surcharge, if an adequate prima facie showing is established in hearing that the interim rate change is justified.
The OPUC has the authority to suspend proposed new rates for a period not to exceed more than six months, with an additional three-month extension, beyond the 30-day time period when the new rates would otherwise go into effect. Absent suspension or other action from the OPUC, new rates automatically go into effect 30 days from filing by the utility. Upon suspension by the OPUC, the OPUC is authorized to allow collection of an interim rate, subject to refund, during the pendency of the OPUC's review of the rate request.
In Wyoming, the WPSC can allow interim rates to go into effect 30 days after the initial application but may require a bond to secure a refund for the amount. The WPSC may suspend the rates for final approval for a period not to exceed 10 months.
The WUTC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 10 months beyond the 30-day time period when the new rate would otherwise go into effect.
Under Idaho law, the IPUC can suspend a filing for an initial period not to exceed five months, and an additional extension of 60 days with a showing of good cause.
The CPUC has the authority to suspend proposed new rates, subject to hearing, for a period not to exceed 18 months. The CPUC may extend the suspension period on a case-by-case period.
Adjustment Mechanisms
In addition to recovery through base rates, PacifiCorp also achieves recovery of certain costs through various adjustment mechanisms as summarized below.
(1)PacifiCorp has relied on both historical test periods with known and measurable adjustments, as well as forecasted test periods.
MidAmerican Energy
Rate Filings
Under Iowa law, there are two options for temporary collection of higher rates following the filing of a request for a base rate increase. Collection can begin, subject to refund, either (1) within 10 days of filing, without IUB review, or (2) 90 days after filing, with approval by the IUB, depending upon the ratemaking principles and precedents utilized. In either case, if the IUB has not issued a final order within ten months after the filing date, the temporary rates become final and any difference between the requested rate increase and the temporary rates may then be collected subject to refund until receipt of a final order. Under Illinois law, new base rates may become effective 45 days after the filing of a request with the ICC, or earlier with ICC approval. The ICC has authority to suspend the proposed new rates, subject to hearing, for a period not to exceed approximately eleven months after filing. South Dakota law authorizes the South Dakota Public Utilities Commission to suspend new base rates for up to six months during the pendency of rate proceedings; however, a utility may implement all or a portion of the proposed new rates six months after the filing of a request for a rate increase subject to refund pending a final order in the proceeding.
Iowa law also permits rate-regulated utilities to seek ratemaking principles with the IUB prior to the construction of certain types of new generating facilities. Pursuant to this law, MidAmerican Energy has applied for and obtained IUB ratemaking principles orders for a 484-MW (MidAmerican Energy's share) coal-fueled generating facility, a 495-MW combined cycle natural gas-fueled generating facility and 6,639 MWs (nominal ratings) of wind-powered generating facilities as of December 31, 2020. These ratemaking principles established cost caps for the projects, below which such costs are deemed prudent by the IUB, and authorized a fixed rate of return on equity for the respective generating facilities over the regulatory life of the facilities in any future Iowa rate proceeding. As of December 31, 2020, the generating facilities in service totaled $8.4 billion, or 43%, of MidAmerican Energy's regulated property, plant and equipment, net and were subject to these ratemaking principles at a weighted average return on equity of 11.4% with a weighted average remaining life of 33 years.
Ratemaking principles for several wind-powered generation projects have established mechanisms in Iowa where electric rate base may be reduced. The current revenue sharing mechanism originates from Wind XI and Wind XII ratemaking principles proceedings and reduces rate base for Iowa electric returns on equity exceeding an established benchmark. For 2018, sharing was triggered by MidAmerican Energy's actual equity return being above a threshold calculated annually in accordance with the IUB's 2016 Wind XI order. The threshold, not to exceed 11%, was the weighted average equity return of rate base with returns authorized via ratemaking principles proceedings and all other rate base. For all other rate base, the return is based on interest rates on 30-year A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%. In 2018 pursuant to this mechanism, MidAmerican Energy shared with customers 100% of the revenue in excess of the trigger. In December 2018, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's Wind XII project. The ratemaking principles continued the revenue sharing mechanism for 2019 and beyond, maintaining the return on equity threshold for sharing and reducing the customer sharing percentage from 100% to 90%. A second mechanism, the retail customer benefit mechanism, reduces electric rate base for the value of higher cost retail energy displaced by covered wind-powered production and applies to the wind-powered generating facilities placed in-service in 2016 under the Wind X project and facilities constructed under the Wind XII project approved by the IUB in 2018. Rate base reductions under these mechanisms are applied to coal and other generation facilities in specified orders.
Adjustment Mechanisms
Under its current Iowa, Illinois and South Dakota electric tariffs, MidAmerican Energy is allowed to recover fluctuations in electric energy costs for its retail electric sales through fuel, or energy, cost adjustment mechanisms. The Iowa mechanism also includes PTCs associated with wind-powered generating facilities placed in-service prior to 2013, except for PTCs earned by repowered facilities. Eligibility for PTCs associated with MidAmerican Energy's earliest projects began expiring in 2014. Facilities currently earning PTCs that benefit customers through the Iowa energy adjustment clause totaled 1,000 MWs (nominal ratings) as of December 31, 2020, with the eligibility of those facilities to earn PTCs expiring by the end of 2022. Additionally, MidAmerican Energy has transmission adjustment clauses to recover certain transmission charges related to retail customers in all jurisdictions. The transmission adjustment mechanisms recover costs billed by the MISO for regional transmission service. The Illinois adjustment mechanism additionally recovers MidAmerican Energy's entire transmission revenue requirement attributable to Illinois. The adjustment mechanisms reduce the regulatory lag for the recovery of energy and transmission costs related to retail electric customers in these jurisdictions and accomplish, with limited timing differences, a pass-through of the related costs to these customers. Recoveries through these adjustment mechanisms are reflected in operating revenue, and the related costs are reflected in cost of fuel and energy, operations and maintenance expense or income tax benefit, as applicable.
Of the wind-powered generating facilities placed in-service as of December 31, 2020, 4,670 MWs (nominal ratings) have not been included in the determination of MidAmerican Energy's Iowa retail electric base rates. In accordance with the related ratemaking principles, until such time as these generation assets are reflected in base rates and ceasing thereafter, MidAmerican Energy will continue to reduce its revenue from Iowa energy adjustment clause recoveries by $12 million each calendar year.
MidAmerican Energy's cost of natural gas purchased for resale is collected for each jurisdiction through a uniform PGA, which is updated monthly to reflect changes in actual costs. Subject to prudence reviews, the PGA accomplishes a pass-through of MidAmerican Energy's cost of natural gas purchased for resale to its customers and, accordingly, has no direct effect on net income.
MidAmerican Energy's electric and natural gas energy efficiency program costs are collected through bill riders that are adjusted annually based on actual and expected costs in accordance with the energy efficiency plans filed with and approved by the respective state regulatory commission. As such, the energy efficiency program costs, which are reflected in operations and maintenance expense, and related recoveries, which are reflected in operating revenue, have no direct impact on net income.
MidAmerican Energy has income tax rider mechanisms in Iowa and Illinois that were established in response to 2017 Tax Reform, which enacted significant changes to the Internal Revenue Code, including, among other things, a reduction in the United States federal corporate income tax rate from 35% to 21%. South Dakota implemented changes to base rates in response to 2017 Tax Reform. As a result of 2017 Tax Reform, MidAmerican Energy re-measured its accumulated deferred income tax balances at the 21% rate and increased regulatory liabilities pursuant to the approved mechanisms. In December 2018, the IUB approved in final form a tax expense revision mechanism that reduces customer electric rates for the impact of the lower income tax rate on current operations, as calculated annually, and defers the amortization of excess accumulated deferred income taxes created by their re-measurement at the 21% income tax rate to a regulatory liability, the disposition of which will be determined in MidAmerican Energy's next rate case. In 2018, Iowa Senate File 2417 was signed into law, which, among other items, reduces the state of Iowa corporate tax rate from 12% to 9.8% effective in 2021, at which time, the impacts of Iowa Senate File 2417 will be included in the Iowa tax expense revision mechanism.
NV Energy (Nevada Power and Sierra Pacific)
Rate Filings
Nevada statutes require the Nevada Utilities to file electric general rate cases at least once every three years with the PUCN. Sierra Pacific may also file natural gas general rate cases with the PUCN. The Nevada Utilities are also subject to a two-part fuel and purchased power adjustment mechanism. The Nevada Utilities make quarterly filings to reset the BTERs, based on the last 12 months of fuel and purchased power costs. The difference between actual fuel and purchased power costs and the revenue collected in the BTERs is deferred into a balancing account. The DEAA rate clears amounts deferred into the balancing account. Nevada regulations allow an electric or natural gas utility that adjusts its BTERs on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. During required annual DEAA proceedings, the prudence of fuel and purchased power costs is reviewed, and if any costs are disallowed on such grounds, the disallowances will be incorporated into the next quarterly BTERs change. Also, on an annual basis, the Nevada Utilities (a) seek a determination that energy efficiency program expenditures were reasonable, (b) request that the PUCN reset base and amortization EEPR, and (c) request that the PUCN reset base and amortization EEIR.
EEPR and EEIR
EEPR was established to allow the Nevada Utilities to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by the Nevada Utilities and approved by the PUCN in the IRP proceedings. When the Nevada Utilities' regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, they are obligated to refund energy efficiency implementation revenue previously collected for that year.
Net Metering
Nevada enacted Assembly Bill 405 ("AB 405") on June 15, 2017. The legislation, among other things, established net metering crediting rates for private generation customers with installed net metering systems less than 25 kilowatts. Under AB 405, private generation customers will be compensated at 95% of the rate the customer would have paid for a kilowatt-hour of electricity supplied by the Nevada Utilities for the first 80 MWs of cumulative installed capacity of all net metering systems in Nevada, 88% of the rate for the next 80 MWs, 81% of the rate for the next 80 MWs and 75% of the rate for any additional private generation capacity. As of December 31, 2020, the cumulative installed and applied-for capacity of net metering systems under AB 405 in Nevada was 300 MWs.
Natural Disaster Protection Plan
Senate Bill 329 ("SB 329"), Natural Disaster Mitigation Measures, was signed into law on May 22, 2019. The legislation requires the Nevada Utilities to submit a natural disaster protection plan to the PUCN. The PUCN adopted natural disaster protection plan regulations on January 29, 2020, that require the Nevada Utilities to file their natural disaster protection plan for approval on or before March 1 of every third year. The regulations also require annual updates to be filed on or before September 1 of the second and third years of the plan. The plan must include procedures, protocols and other certain information as it relates to the efforts of the Nevada Utilities to prevent or respond to a fire or other natural disaster. The expenditures incurred by the Nevada Utilities in developing and implementing the natural disaster protection plan are required to be held in a regulatory asset account, with the Nevada Utilities filing an application for recovery on or before March 1 of each year. The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures on February 28, 2020.
Federal Regulation
The FERC is an independent agency with broad authority to implement provisions of the Federal Power Act, the Natural Gas Act ("NGA"), the Energy Policy Act of 2005 ("Energy Policy Act") and other federal statutes. The FERC regulates rates for wholesale sales of electricity; transmission of electricity, including pricing and regional planning for the expansion of transmission systems; electric system reliability; utility holding companies; accounting and records retention; securities issuances; construction and operation of hydroelectric facilities; and other matters. The FERC also has the enforcement authority to assess civil penalties of up to $1.3 million per day per violation of rules, regulations and orders issued under the Federal Power Act. The Utilities have implemented programs and procedures that facilitate and monitor compliance with the FERC's regulations described below. MidAmerican Energy is also subject to regulation by the NRC pursuant to the Atomic Energy Act of 1954, as amended ("Atomic Energy Act"), with respect to its ownership interest in the Quad Cities Station.
Wholesale Electricity and Capacity
The FERC regulates the Utilities' rates charged to wholesale customers for electricity and transmission capacity and related services. Much of the Utilities' wholesale electricity sales and purchases occur under market-based pricing allowed by the FERC and are therefore subject to market volatility. The Utilities are precluded from selling at market-based rates in the PacifiCorp-East, PacifiCorp-West, Nevada Utilities, Idaho Power Company and NorthWestern Energy balancing authority areas. Wholesale electricity sales in those specific balancing authority areas are permitted at cost-based rates. PacifiCorp and the Nevada Utilities have been granted the authority to bid into the California EIM at market-based rates.
The Utilities' authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the Utilities are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. PacifiCorp, the Nevada Utilities and certain affiliates, representing the BHE Northwest Companies, file together for market power study purposes. The BHE Northwest Companies' most recent triennial filing was made in June 2019 and an order accepting it was issued in June 2020. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2020 and is under review by the FERC. MidAmerican Energy and certain affiliates file together for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2020 and is under review by the FERC. Under the FERC's market-based rules, the Utilities must also file with the FERC a notice of change in status when there is a change in the conditions that the FERC relied upon in granting market-based rate authority.
Transmission
PacifiCorp's and the Nevada Utilities' wholesale transmission services are regulated by the FERC under cost-based regulation subject to PacifiCorp's and the Nevada Utilities' OATT. These services are offered on a non-discriminatory basis, which means that all potential customers are provided an equal opportunity to access the transmission system. PacifiCorp's and the Nevada Utilities' transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC's Standards of Conduct. PacifiCorp and the Nevada Utilities have made several required compliance filings in accordance with these rules.
In December 2011, PacifiCorp adopted a cost-based formula rate under its OATT for its transmission services. Cost-based formula rates are intended to be an effective means of recovering PacifiCorp's investments and associated costs of its transmission system without the need to file rate cases with the FERC, although the formula rate results are subject to discovery and challenges by the FERC and intervenors. A significant portion of these services are provided to PacifiCorp's energy supply management function.
MidAmerican Energy participates in the MISO as a transmission-owning member. Accordingly, the MISO is the transmission provider under its FERC-approved OATT. While the MISO is responsible for directing the operation of MidAmerican Energy's transmission system, MidAmerican Energy retains ownership of its transmission assets and, therefore, is subject to the FERC's reliability standards discussed below. MidAmerican Energy's transmission business is managed and operated independently from its wholesale marketing business in accordance with the FERC Standards of Conduct.
MidAmerican Energy constructed and owns four Multi-Value Projects ("MVPs") located in Iowa and Illinois that added approximately 250 miles of 345-kV transmission line to MidAmerican Energy's transmission system since 2012. The MISO OATT allows for broad cost allocation for MidAmerican Energy's MVPs, including similar MVPs of other MISO participants. Accordingly, a significant portion of the revenue requirement associated with MidAmerican Energy's MVP investments is shared with other MISO participants based on the MISO's cost allocation methodology, and a portion of the revenue requirement of the other participants' MVPs is allocated to MidAmerican Energy. The transmission assets and financial results of MidAmerican Energy's MVPs are excluded from the determination of its retail electric rates.
The FERC has established an extensive number of mandatory reliability standards developed by the NERC and the WECC, including planning and operations, critical infrastructure protection and regional standards. Compliance, enforcement and monitoring oversight of these standards is carried out by the FERC; the NERC; and the WECC for PacifiCorp, Nevada Power, and Sierra Pacific; and the Midwest Reliability Organization for MidAmerican Energy.
Hydroelectric
The FERC licenses and regulates the operation of hydroelectric systems, including license compliance and dam safety programs. Most of PacifiCorp's hydroelectric generating facilities are licensed by the FERC as major systems under the Federal Power Act, and certain of these systems are licensed under the Oregon Hydroelectric Act. Under the Federal Power Act, 20 developments associated with PacifiCorp's hydroelectric generating facilities licensed with the FERC are classified as "high hazard potential," meaning it is probable in the event of a dam failure that loss of human life in the downstream population could occur. The FERC provides guidelines utilized by PacifiCorp in development of public safety programs consisting of a dam safety program and emergency action plans.
For an update regarding PacifiCorp's Klamath River hydroelectric system, refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K.
Nuclear Regulatory Commission
General
MidAmerican Energy is subject to the jurisdiction of the NRC with respect to its license and 25% ownership interest in Quad Cities Station. Exelon Generation, the operator and 75% owner of Quad Cities Station, is under contract with MidAmerican Energy to secure and keep in effect all necessary NRC licenses and authorizations.
The NRC regulates the granting of permits and licenses for the construction and operation of nuclear generating stations and regularly inspects such stations for compliance with applicable laws, regulations and license terms. Current licenses for Quad Cities Station provide for operation until December 14, 2032. The NRC review and regulatory process covers, among other things, operations, maintenance and environmental and radiological aspects of such stations. The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the terms of such licenses.
Federal regulations provide that any nuclear operating facility may be required to cease operation if the NRC determines there are deficiencies in state, local or utility emergency preparedness plans relating to such facility, and the deficiencies are not corrected. Exelon Generation has advised MidAmerican Energy that an emergency preparedness plan for Quad Cities Station has been approved by the NRC. Exelon Generation has also advised MidAmerican Energy that state and local plans relating to Quad Cities Station have been approved by the Federal Emergency Management Agency.
The NRC also regulates the decommissioning of nuclear-powered generating facilities, including the planning and funding for the eventual decommissioning of the facilities. In accordance with these regulations, MidAmerican Energy submits a biennial report to the NRC providing reasonable assurance that funds will be available to pay its share of the costs of decommissioning Quad Cities Station. MidAmerican Energy has established a trust for the investment of funds collected for nuclear decommissioning of Quad Cities Station.
Under the Nuclear Waste Policy Act of 1982 ("NWPA"), the United States DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Exelon Generation, as required by the NWPA, signed a contract with the DOE under which the DOE was to receive spent nuclear fuel and high-level radioactive waste for disposal beginning not later than January 1998. The DOE did not begin receiving spent nuclear fuel on the scheduled date and remains unable to receive such fuel and waste. The costs to be incurred by the DOE for disposal activities were previously being financed by fees charged to owners and generators of the waste. In accordance with a 2013 ruling by the D.C. Circuit, the DOE, in May 2014, provided notice that, effective May 16, 2014, the spent nuclear fuel disposal fee would be zero. In 2004, Exelon Generation, reached a settlement with the DOE concerning the DOE's failure to begin accepting spent nuclear fuel in 1998. As a result, Quad Cities Station has been billing the DOE, and the DOE is obligated to reimburse the station for all station costs incurred due to the DOE's delay. Exelon Generation has constructed an interim spent fuel storage installation ("ISFSI") at Quad Cities Station consisting of two pads to store spent nuclear fuel in dry casks in order to free space in the storage pool. The first dry cask was placed in-service in 2005. As of December 31, 2020, the first pad at the ISFSI is full, and the second pad is in operation. The first and second pads at the ISFSI are expected to facilitate storage of casks to support operations at Quad Cities Station through the end of its operating licenses.
Nuclear Insurance
MidAmerican Energy maintains financial protection against catastrophic loss associated with its interest in Quad Cities Station through a combination of insurance purchased by Exelon Generation, insurance purchased directly by MidAmerican Energy, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988 ("Price-Anderson"), which was amended and extended by the Energy Policy Act. The general types of coverage maintained are: nuclear liability, property damage or loss and nuclear worker liability, as discussed below.
Exelon Generation purchases private market nuclear liability insurance for Quad Cities Station in the maximum available amount of $450 million, which includes coverage for MidAmerican Energy's ownership. In accordance with Price-Anderson, excess liability protection above that amount is provided by a mandatory industry-wide Secondary Financial Protection program under which the licensees of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, MidAmerican Energy's aggregate maximum potential share of an assessment for Quad Cities Station is approximately $69 million per incident, payable in installments not to exceed $10 million annually.
The insurance for nuclear property damage losses covers property damage, stabilization and decontamination of the facility, disposal of the decontaminated material and premature decommissioning arising out of a covered loss. For Quad Cities Station, Exelon Generation purchases primary property insurance protection for the combined interests in Quad Cities Station, with coverage limits for nuclear damage losses up to $1.5 billion and non-nuclear damage losses up to $500 million. MidAmerican Energy also directly purchases extra expense coverage for its share of replacement power and other extra expenses in the event of a covered accidental outage at Quad Cities Station. The property and related coverages purchased directly by MidAmerican Energy and by Exelon Generation, which includes the interests of MidAmerican Energy, are underwritten by an industry mutual insurance company and contain provisions for retrospective premium assessments to be called upon based on the industry mutual board of directors' discretion for adverse loss experience. Currently, the maximum retrospective amounts that could be assessed against MidAmerican Energy from industry mutual policies for its obligations associated with Quad Cities Station total $7 million.
The master nuclear worker liability coverage, which is purchased by Exelon Generation for Quad Cities Station, is an industry-wide guaranteed-cost policy with an aggregate limit of $450 million for the nuclear industry as a whole, which is in effect to cover tort claims of workers in nuclear-related industries.
United States Mine Safety
PacifiCorp's mining operations are regulated by the Federal Mine Safety and Health Administration, which administers federal mine safety and health laws and regulations, and state regulatory agencies. The Federal Mine Safety and Health Administration has the statutory authority to institute a civil action for relief, including a temporary or permanent injunction, restraining order or other appropriate order against a mine operator who fails to pay penalties or fines for violations of federal mine safety standards. Federal law requires PacifiCorp to have a written emergency response plan specific to each underground mine it operates, which is reviewed by the Federal Mine Safety and Health Administration every six months, and to have at least two mine rescue teams located within one hour of each mine. Information regarding PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
Interstate Natural Gas Pipeline Subsidiaries
The Pipeline Companies are regulated by the FERC, pursuant to the NGA and the Natural Gas Policy Act of 1978. Under this authority, the FERC regulates, among other items, (a) rates, charges, terms and conditions of service, (b) the construction and operation of interstate pipelines, storage and related facilities, including the extension, expansion or abandonment of such facilities and (c) the construction and operation of LNG import/export facilities. The Pipeline Companies hold certificates of public convenience and necessity and LNG facility authorizations issued by the FERC, which authorize them to construct, operate and maintain their pipeline and related facilities and services.
FERC regulations and the Pipeline Companies' tariffs allow each of the Pipeline Companies to charge approved rates for the services set forth in their respective tariffs. Generally, these rates are a function of the cost of providing services to customers, including prudently incurred operations and maintenance expenses, taxes, depreciation and amortization and a reasonable return on invested capital. Tariff rates for each of the Pipeline Companies have been developed under a rate design methodology whereby substantially all fixed costs, including a return on invested capital and income taxes, are collected through reservation charges, which are paid by firm transportation and storage customers regardless of volumes shipped. Commodity charges, which are paid only with respect to volumes actually shipped, are designed to recover the remaining, primarily variable, costs. Kern River's reservation rates have historically been approved using a "levelized" cost-of-service methodology so that the rate remains constant over the levelization period. This levelized cost of service has been achieved by using a FERC-approved depreciation schedule in which depreciation increases as the cost of capital decreases on declining rate base. Each of the Pipeline Companies also hold authority to negotiate rates for their services, subject to requirements to offer cost-based rate alternatives, and to publish such negotiated rates. In addition, for services that are not subject to FERC rate jurisdiction pursuant to Section 3 of the Natural Gas Act, Cove Point charges rates that are established by contract.
The Pipeline Companies' rates are subject to change in future general rate proceedings. Rates for natural gas pipelines are changed by filings under either Section 5 or Section 4 of the Natural Gas Act. Section 5 proceedings are initiated by the FERC or the pipeline's customers for a potential reduction to rates that the FERC finds are no longer just and reasonable. In a Section 5 proceeding, the initiating party has the burden of demonstrating that the currently effective rates of the pipeline are no longer just and reasonable, and of demonstrating alternative just and reasonable rates. Any rate decrease as a result of a Section 5 proceeding is implemented prospectively upon the issuance of a final FERC order adopting the new just and reasonable rates. Section 4 rate proceedings are initiated by the natural gas pipeline, who must demonstrate that the new proposed rates are just and reasonable. The new rates as a result of a Section 4 proceeding are typically implemented six months after the Section 4 filing and are subject to refund upon issuance of a final order by the FERC.
The FERC-regulated natural gas companies may not grant undue preference to any customer. FERC regulations require that certain information be made public for market access, through standardized internet websites. These regulations also restrict each pipeline's marketing affiliates' access to certain non-public information that could affect price or availability of service.
Interstate natural gas pipelines are also subject to regulations administered by the Office of Pipeline Safety within the Pipeline and Hazardous Materials Safety Administration, an agency of the United States Department of Transportation ("DOT"). Federal pipeline safety regulations are issued pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), which establishes safety requirements in the design, construction, operation and maintenance of interstate natural gas facilities, and requires an entity that owns or operates pipeline facilities to comply with such plans. Major amendments to the NGPSA include the Pipeline Safety Improvement Act of 2002 ("2002 Act"), the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 ("2006 Act"), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Act") and the Protecting Our Infrastructure Of Pipelines And Enhancing Safety Act Of 2016 ("2016 Act").
The 2002 Act established additional safety and pipeline integrity regulations for all natural gas pipelines in high-consequence areas. The 2002 Act imposed major new requirements in the areas of operator qualifications, risk analysis and integrity management. The 2002 Act mandated more frequent periodic inspection or testing of natural gas pipelines in high-consequence areas, which are locations where the potential consequences of a natural gas pipeline accident may be significant or may do considerable harm to persons or property. Pursuant to the 2002 Act, the DOT promulgated regulations that require natural gas pipeline operators to develop comprehensive integrity management programs, to identify applicable threats to natural gas pipeline segments that could impact high-consequence areas, to assess these segments and to provide ongoing mitigation and monitoring. The regulations require recurring inspections of high-consequence area segments every seven years after the initial baseline assessment.
The 2006 Act required pipeline operators to institute human factors management plans for personnel employed in pipeline control centers. DOT regulations published pursuant to the 2006 Act required development and implementation of written control room management procedures.
The 2011 Act was a response to natural gas pipeline incidents, most notably the San Bruno natural gas pipeline explosion that occurred in September 2010 in California. The 2011 Act increased the maximum allowable civil penalties for violations, directs operator assistance for Federal authorities conducting investigations and authorized the DOT to hire additional inspection and enforcement personnel. The 2011 Act also directed the DOT to study several topics, including the definition of high-consequence areas, the use of automatic shutoff valves in high-consequence areas, expansion of integrity management requirements beyond high-consequence areas and cast iron pipe replacement. The studies are complete, and a number of notices of proposed rulemaking have been issued. The Pipeline and Hazardous Materials Safety Administration issued the Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments final rule in October 2019. The primary change is the expansion of the pipeline integrity assessment requirements to cover moderate-consequence areas and reconfirming maximum allowable operating pressures. Pipeline operators must develop procedures to address assessment requirements and define and map locations by mid-2021 and complete 50% of the required integrity testing by 2028 and the remaining testing by 2034. The BHE Pipeline Group is assessing the impact of the rule. This is the first of three parts of the anticipated new rules. Additional final rules are expected in 2021.
The 2016 Act required the Pipeline and Hazardous Materials Safety Administration to set federal minimum safety standards for underground natural gas storage facilities and authorized emergency order authority. In February 2020, the Pipeline and Hazardous Materials Safety Administration issued a final rule regarding underground natural gas storage facilities that incorporates by reference the American Petroleum Institute's Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs", clarifies certain aspects of the mandatory nature of the standard and defines regulatory completion dates for underground storage facility risk assessments. EGTS has 17 underground natural gas storage fields that fall under this regulation and does not expect the impact of complying with the final rule to be significant. Northern Natural Gas has three underground natural gas storage fields that fall under this regulation and is complying with the final rule. Kern River, Carolina Gas and Cove Point do not have underground natural gas storage facilities.
The DOT and related state agencies routinely audit and inspect the pipeline facilities for compliance with their regulations. The Pipeline Companies conduct internal audits of their facilities every four years with more frequent reviews of those deemed higher risk. The Pipeline Companies also conduct preliminary audits in advance of agency audits. Compliance issues that arise during these audits or during the normal course of business are addressed on a timely basis. The Pipeline Companies believe their pipeline systems comply in all material respects with the NGPSA and with DOT regulations issued pursuant to the NGPSA.
Northern Powergrid Distribution Companies
The Northern Powergrid Distribution Companies, as holders of electricity distribution licenses, are subject to regulation by GEMA. GEMA regulates distribution network operators ("DNOs") within the terms of the Electricity Act 1989 and the terms of DNO licenses, which are revocable with 25 years notice. Under the Electricity Act 1989, GEMA has a duty to ensure that DNOs can finance their regulated activities and DNOs have a duty to maintain an investment grade credit rating. GEMA discharges certain of its duties through its staff within Ofgem. Each of fourteen licensed DNOs distributes electricity from the national grid transmission system and distribution-connected generators to end users within its respective distribution services area.
DNOs are subject to price controls, enforced by Ofgem, that limit the revenue that may be recovered and retained from their electricity distribution activities. The regulatory regime that has been applied to electricity distributors in Great Britain encourages companies to look for efficiency gains in order to improve profits. The distribution price control formula also adjusts the revenue received by DNOs to reflect a number of factors, including, but not limited to, the rate of inflation (as measured by the United Kingdom's Retail Prices Index) and the quality of service delivered by the licensee's distribution system. The current price control, Electricity Distribution 1 ("ED1"), has been set for a period of eight years, starting April 1, 2015, although the formula has been, and may be, reviewed by the regulator following public consultation. The procedure and methodology adopted at a price control review are at the reasonable discretion of Ofgem. Ofgem's judgment of the future allowed revenue of licensees is likely to take into account, among other things:
•the actual operating and capital costs of each of the licensees;
•the operating and capital costs that each of the licensees would incur if it were as efficient as, in Ofgem's judgment, the more efficient licensees;
•the actual value of certain costs which are judged to be beyond the control of the licensees;
•the taxes that each licensee is expected to pay;
•the regulatory value ascribed to the expenditures that have been incurred in the past and the efficient expenditures that are to be incurred in the forthcoming regulatory period;
•the rate of return to be allowed on expenditures that make up the regulatory asset value;
•the financial ratios of each of the licensees and the license requirement for each licensee to maintain investment grade status;
•an allowance in respect of the repair of the pension deficits in the defined benefit pension schemes sponsored by each of the licensees; and
•any under- or over-recoveries of revenues, relative to allowed revenues, in the previous price control period.
A number of incentive schemes also operate within the current price control period to encourage DNOs to provide an appropriate quality of service to end users. This includes specified payments to be made for failures to meet prescribed standards of service. The aggregate of these guaranteed standards payments is uncapped, but may be excused in certain prescribed circumstances that are generally beyond the control of the DNOs.
A new price control can be implemented by GEMA without the consent of the DNOs, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's CMA, as can certain other parties. Any appeals must be notified within 20 working days of the license modification by GEMA. If the CMA determines that the appellant has relevant standing, then the statute requires that the CMA complete its process within six months, or in some exceptional circumstances seven months. The Northern Powergrid Distribution Companies appealed Ofgem's proposals for the resetting of the formula that commenced April 1, 2015, as did one other party, and the CMA subsequently revised GEMA's decision.
The current eight-year electricity distribution price control period runs from April 1, 2015 through March 31, 2023. The current price control was the first to be set for electricity distribution in Great Britain since Ofgem completed its review of network regulation (known as the RPI-X @ 20 project). The key changes to the price control calculations, compared to those used in previous price controls are that:
•the period over which new regulatory assets are depreciated is being gradually lengthened, from 20 years to 45 years, with the change being phased over eight years;
•allowed revenues will be adjusted during the price control period, rather than at the next price control review, to partially reflect cost variances relative to cost allowances;
•the allowed cost of debt will be updated within the price control period by reference to a long-run trailing average based on external benchmarks of utility debt costs;
•allowed revenues will be adjusted in relation to some new service standard incentives, principally relating to speed and service standards for new connections to the network; and
•there was scope for a mid-period review and adjustment to revenues in the latter half of the period for any changes in the outputs required of licensees for certain specified reasons, although GEMA made no adjustments under this provision.
Under the current price control, as revised by the CMA, and excluding the effects of incentive schemes and any deferred revenues from the prior price control, the opening base allowed revenue of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc remains constant in all subsequent years within the price control period (ED1) through 2022-23, before the addition of inflation. Nominal opening base allowed revenues will increase in line with inflation. Adjustments are made annually to recognize the effect of factors such as changes in the allowed cost of debt, performance on incentive schemes and catch up of prior year under- or over- recoveries.
Ofgem also monitors DNO compliance with license conditions and enforces the remedies resulting from any breach of condition. License conditions include the prices and terms of service, financial strength of the DNO, the provision of information to Ofgem and the public, as well as maintaining transparency, non-discrimination and avoidance of cross-subsidy in the provision of such services. Ofgem also monitors and enforces certain duties of a DNO set out in the Electricity Act 1989, including the duty to develop and maintain an efficient, coordinated and economical system of electricity distribution. Under changes to the Electricity Act 1989 introduced by the Utilities Act 2000, GEMA is able to impose financial penalties on DNOs that contravene any of their license duties or certain of their duties under the Electricity Act 1989, as amended, or that are failing to achieve a satisfactory performance in relation to the individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the licensee's revenue.
AltaLink
AltaLink is regulated by the AUC, pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Alberta Utilities Commission Act (Alberta) and the Hydro and Electric Energy Act (Alberta). The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems. The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing.
The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements, capital expenditure prudency and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable, and approval of the transmission tariff rates of regulated transmission providers paid by the AESO, which is the independent transmission system operator in Alberta, Canada that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulation and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
AltaLink's tariffs are regulated by the AUC under the provisions of the Electric Utilities Act (Alberta) in respect of rates and terms and conditions of service. The Electric Utilities Act (Alberta) and related regulations require the AUC to consider that it is in the public interest to provide consumers the benefit of unconstrained transmission access to competitive generation and the wholesale electricity market. In regulating transmission tariffs, the AUC must facilitate sufficient investment to ensure the timely upgrade, enhancement or expansion of transmission facilities, and foster a stable investment climate and a continued stream of capital investment for the transmission system.
Under the Electric Utilities Act (Alberta), AltaLink prepares and files applications with the AUC for approval of tariffs to be paid by the AESO for the use of its transmission facilities, and the terms and conditions governing the use of those facilities. The AUC reviews and approves such tariff applications based on a cost-of-service regulatory model under a forward test year basis. Under this model, the AUC provides AltaLink with a reasonable opportunity to (i) earn a fair return on equity; and (ii) recover its forecast costs, including operating expenses, depreciation, borrowing costs and taxes (including deemed income taxes) associated with its regulated transmission business. The AUC must approve tariffs that are just, reasonable and not unduly preferential, arbitrary or unjustly discriminatory. AltaLink's transmission tariffs are not dependent on the price or volume of electricity transported through its transmission system.
The AESO is an independent system operator in Alberta, Canada that oversees the Alberta Interconnected Electric System ("AIES") and wholesale electricity market. The AESO is responsible for directing the safe, reliable and economic operation of the AIES, including long-term transmission system planning. AltaLink and the other transmission facility owners receive substantially all of their transmission tariff revenues from the AESO. The AESO, in turn, charges wholesale tariffs, approved by the AUC, in a manner that promotes fair and open access to the AIES and facilitates a competitive market for the purchase and sale of electricity. The AESO monitors compliance with approved reliability standards, which are enforced by the Market Surveillance Administrator, which may impose penalties on transmission facility owners for non-compliance with the approved reliability standards.
The AESO determines the need and plans for the expansion and enhancement of the transmission system in Alberta in accordance with applicable law and reliability standards. The AESO's responsibilities include long-term transmission planning and management, including assessing the current and future transmission system capacity needs of market participants. When the AESO determines an expansion or enhancement of the transmission system is needed, with limited exceptions, it submits an application to the AUC for approval of the proposed expansion or enhancement. The AESO then determines which transmission provider should submit an application to the AUC for a permit and license to construct and operate the designated transmission facilities. Generally the transmission provider operating in the geographic area where the transmission facilities expansion or enhancement is to be located is selected by the AESO to build, own and operate the transmission facilities. In addition, Alberta law provides that certain transmission projects may be subject to a competitive process open to qualified bidders.
Independent Power Projects
The Yuma, Cordova, Saranac, Power Resources, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Jumbo Road, Marshall, Grande Prairie, Walnut Ridge, Pinyon Pines, Santa Rita, Alamo 6 and Pearl independent power projects are Exempt Wholesale Generators ("EWG") under the Energy Policy Act, while the Community Solar Gardens, Imperial Valley and Wailuku independent power projects are currently certified as Qualifying Facilities ("QF") under the Public Utility Regulatory Policies Act of 1978. Both EWGs and QFs are generally exempt from compliance with extensive federal and state regulations that control the financial structure of an electric generating plant and the prices and terms at which electricity may be sold by the facilities.
The Yuma, Cordova, Saranac, Imperial Valley, Topaz, Agua Caliente, Solar Star, Bishop Hill II, Marshall, Grande Prairie, Walnut Ridge and Pinyon Pines independent power projects have obtained authority from the FERC to sell their power using market-based rates. This authority to sell electricity in wholesale electricity markets at market-based rates is subject to triennial reviews conducted by the FERC. Accordingly, the respective independent power projects are required to submit triennial filings to the FERC that demonstrate a lack of market power over sales of wholesale electricity and electric generation capacity in their respective market areas. The Pinyon Pines, Solar Star, Topaz and Yuma independent power projects and power marketer CalEnergy, LLC file together for market power study purposes of the FERC-defined Southwest Region. The most recent triennial filing for the Southwest Region was made in June 2019 and an order accepting it was issued in March 2020. The Cordova and Saranac independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Northeast Region. The most recent triennial filing for the Northeast Region was made in June 2020 and is awaiting FERC action. The Bishop Hill II and Walnut Ridge independent power projects and power marketer CalEnergy, LLC file together with MidAmerican Energy and certain affiliates for market power study purposes of the FERC-defined Central Region. The most recent triennial filing for the Central Region was made in December 2020 and is awaiting FERC action. The Marshall and Grande Prairie independent power projects and power marketer CalEnergy, LLC file together for market power study purposes in the FERC-defined Southwest Power Pool Region. The most recent triennial filing for the Southwest Power Pool Region was made in December 2018 and an order accepting it was issued July 2019.
The entire output of Jumbo Road, Santa Rita, Alamo 6, Pearl and Power Resources is within the Electric Reliability Council of Texas ("ERCOT") and market-based authority is not required for such sales solely within ERCOT as the ERCOT market is not a FERC-jurisdictional market. Similarly, Wailuku sells its output solely to the Hawaii Electric Light Company within the Hawaii electric grid, which is not a FERC-jurisdictional market and therefore, Wailuku does not require market-based rate authority.
EWGs are permitted to sell capacity and electricity only in the wholesale markets, not to end users. Additionally, utilities are required to purchase electricity produced by QFs at a price that does not exceed the purchasing utility's "avoided cost" and to sell back-up power to the QFs on a non-discriminatory basis, unless they have successfully petitioned the FERC for an exemption from this purchase requirement. Avoided cost is defined generally as the price at which the utility could purchase or produce the same amount of power from sources other than the QF on a long-term basis. The Energy Policy Act eliminated the purchase requirement for utilities with respect to new contracts under certain conditions. New QF contracts are also subject to FERC rate filing requirements, unlike QF contracts entered into prior to the Energy Policy Act. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates other than the utilities' avoided cost.
The Philippine Congress has passed the Electric Power Industry Reform Act of 2001 ("EPIRA"), which is aimed at restructuring the Philippine power industry, privatizing the National Power Corporation ("NPC") and introducing a competitive electricity market, among other initiatives. Under the EPIRA, Power Sector Assets and Liabilities Management Corporation ("PSALM") is tasked, among others, to dispose of and privatize the assets of NPC. PSALM recently issued statements that public bidding of the administration and management of the contracted energy of the Casecnan Project's energy conversion and power purchase agreement to interested parties will be made in 2021. It is still not known what impact, if any, the implementation of this change in independent power producer administrator may have on the Casecnan Project's future operations.
Residential Real Estate Brokerage Company
HomeServices and its operating subsidiaries are regulated by the United States Consumer Financial Protection Bureau which enforces the Truth In Lending Act ("TILA"), the Equal Credit Opportunity Act ("ECOA") and the Real Estate Settlement Procedures Act ("RESPA"); by the United States Federal Trade Commission with respect to certain franchising activities; by the United States Department of Housing and Urban Development, which enforces the Fair Housing Act ("FHA"); and by state agencies where its subsidiaries operate. TILA and ECOA regulate lending practices. FHA prohibits housing-related discrimination on the basis of race, color, national origin, religion, sex, familial status, and disability. RESPA regulates real estate settlement services including real estate closing practices, lender servicing and escrow account practices and business relationships among settlement service providers and third parties to the transaction.
REGULATORY MATTERS
In addition to the discussion contained herein regarding regulatory matters, refer to "General Regulation" in Item 1 of this Form 10-K for further information regarding the general regulatory framework.
PacifiCorp
Multi-State Process
In November 2019, PacifiCorp completed negotiations with the Multi-State Process Workgroup, a working group of stakeholders consisting of utility regulatory agencies, customers, and certain others potentially affected by inter-jurisdictional allocation procedures, resulting in a new cost allocation agreement, the 2020 Protocol. The agreement establishes a common allocation method to be used in Utah, Oregon, Wyoming, Idaho and California through 2023 and a separate method for Washington during the same time period that is based on a system approach for cost allocations and provides a path forward for Washington to achieve compliance with Washington's Clean Energy Transformation Act. The agreement establishes a process for the 2020 Protocol signatories to resolve remaining outstanding cost-allocations to be implemented in a new, permanent and long-term allocation method at the end of the four years. In December 2019, PacifiCorp submitted the 2020 Protocol to the UPSC, the OPUC, the WPSC and the IPUC for approval. WUTC approval of the agreement was sought in the general rate case filing also submitted in December 2019. In 2020, PacifiCorp received approval of the 2020 Protocol from the UPSC, the OPUC, the WPSC, the IPUC and the WUTC. Approval from the CPUC will be requested in a future general rate case.
Depreciation Rate Study
In September 2018, PacifiCorp filed applications for depreciation rate changes with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC based on PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Based on the proposed depreciation rates, annual depreciation expense would have increased approximately $300 million. Updates since September 2018 include the filing of PacifiCorp's 2020 decommissioning studies in which a third-party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and removal of Cholla Unit 4. Depreciation rates based on the outcomes described below were effective January 1, 2021, resulting in an estimated increase in depreciation expense of $176 million in 2021, based on historical balances.
In March 2020, PacifiCorp filed a partial settlement stipulation with the UPSC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and established a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal-fueled generating facilities and equipment replaced as a result of PacifiCorp's wind repowering projects. In April 2020, the UPSC approved the stipulation as filed. In December 2020, the UPSC issued an order regarding the secondary phase which approved PacifiCorp's proposed accounting treatment related to the retired wind assets and supports recovery of incremental decommissioning costs reflected in the third-party study over the remaining depreciable lives of the coal-fueled generating facilities as proposed in the general rate case.
In August 2020, PacifiCorp filed an all-party stipulation with the OPUC regarding the depreciation study with depreciation rates for coal-fueled generating facilities and associated incremental decommissioning costs reflected in the third-party study to be addressed separately in the general rate case proceeding. In December 2020, the OPUC approved the stipulation effective January 1, 2021. The OPUC's December 2020 general rate case order accepted PacifiCorp's proposed depreciable lives for the coal-fueled generating facilities but deferred a decision on rate treatment of the incremental decommissioning costs.
In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The stipulation was approved by the WPSC during a hearing in August 2020 and a subsequent written order in December 2020. The general rate case hearing was rescheduled for February 2021. As a result of the hearing date change, PacifiCorp filed an application in October 2020 with the WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application is scheduled to occur in July 2021.
In July 2020, PacifiCorp filed a full settlement stipulation with the WUTC resolving all issues in the proceeding. The WUTC approved the stipulation in December 2020, excluding aspects related to certain coal-fueled generating facilities that were separately addressed in the general rate case. The general rate case settlement authorizes accelerated depreciation of certain coal-fueled generating facilities, as well as recovery of incremental decommissioning costs reflected in the third-party study over a ten-year period.
In June 2020, PacifiCorp filed a partial settlement stipulation with the IPUC to which all but one intervening party agreed. The partial settlement adopts certain aspects of the 2018 depreciation rate study as filed for coal-fueled generating facilities and proposes a secondary phase to the proceeding be established in order to address decommissioning costs for PacifiCorp's coal-fueled generating facilities. In August 2020, the IPUC approved the stipulation and authorized a secondary phase to the proceeding to address decommissioning costs for PacifiCorp's coal-fueled generating facilities.
As a result of delaying the general rate case filing in Idaho for 2021 for an anticipated effective date of January 1, 2022, PacifiCorp reached a separate agreement with parties to defer the incremental depreciation expense from the 2018 depreciation study for one year, during 2021. In October 2020, a settlement stipulation was filed with the IPUC related to the secondary phase of the depreciation study to defer the incremental decommissioning expense from the 2020 decommissioning studies for one year, during 2021, consistent with the stipulated treatment of the incremental depreciation expense from the 2018 depreciation study, as a result of delaying the general rate case filing. The IPUC approved the stipulation as filed in December 2020.
Retirement Plan Settlement Charge
During 2018, the PacifiCorp Retirement Plan incurred a settlement charge as a result of excess lump sum distributions over the defined threshold for the year ended December 31, 2018. In December 2018, PacifiCorp submitted filings with the UPSC, the OPUC, the WPSC and the WUTC seeking approval to defer the settlement charge. Also in December 2018, an advice letter was filed with the CPUC requesting a memorandum account to track the costs associated with pension and postretirement settlements and curtailments. In October 2019, the request for a memorandum account was re-filed as an application with the CPUC. In 2019, the WUTC approved the requested deferral, while the UPSC and the WPSC denied the request. In January 2020, the OPUC issued an order denying PacifiCorp's request. In April 2020, the CPUC approved the request to establish a memorandum account effective December 31, 2018.
In its December 2020 generate rate case order, the UPSC ordered PacifiCorp to initiate a proceeding by March 2021 to establish a balancing account for pension settlement losses. While the OPUC did not authorize specific treatment for pension settlement losses in its December 2020 general rate case order, it did indicate that it is receptive to PacifiCorp filing a deferral request, should a pension settlement loss be triggered in the 2021 test period for the general rate case proceeding.
COVID-19
In March and April 2020, PacifiCorp filed applications requesting authorization to defer costs associated with COVID-19 with the UPSC, the OPUC, the WPSC, the WUTC and the IPUC. In April 2020, as ordered by the CPUC, PacifiCorp filed to establish the COVID-19 Pandemic Protections Memorandum Account. The memorandum account was approved in September 2020, retroactive to March 4, 2020. In April 2020, the WPSC approved PacifiCorp's application to defer costs associated with COVID-19, subject to a public notice period, and required associated benefits arising from COVID-19 to be offset against the deferred costs. During the public notice period, one party to the proceeding filed a petition for a rehearing of the matter. The WPSC scheduled a hearing for this matter in April 2021. In July, September and October 2020, the IPUC, the UPSC and the OPUC, respectively, approved PacifiCorp's applications to defer costs associated with COVID-19, requiring associated benefits arising from COVID-19 to be offset against the deferred costs. In November 2020, PacifiCorp filed a revised petition consistent with the requirements set forth in the WUTC's adopted term sheet in its generic COVID-19 proceeding. In December 2020, the WUTC approved PacifiCorp's revised petition. In February 2021, PacifiCorp filed a motion to withdraw the application from the WPSC, after reaching an agreement with parties to the proceeding.
Utah
In March 2019, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $24 million, or 1.1%, of deferred net power costs from customers for the period January 1, 2018 through December 31, 2018, reflecting the difference between base and actual net power costs in the 2018 deferral period. The rate change was approved by the UPSC effective May 1, 2019 on an interim basis. Following a decision from the Utah Supreme Court in June 2019 that found the UPSC did not have authority to approve interim rates in conjunction with the EBA, the UPSC directed PacifiCorp to terminate the interim rate change pending final approval in the proceeding. The hearing on final approval was held in February 2020, and the UPSC issued an order approving full recovery of the 2018 deferred costs beginning April 1, 2020.
In May 2019, Utah House Bill 411 went into effect. The legislation, among other things, authorizes the UPSC to approve a renewable energy program for communities seeking 100% renewable electricity. Participating cities were required to adopt a resolution with a goal to be on 100% renewable electricity by 2030 before December 31, 2019. Twenty-four communities in Utah, including Salt Lake City, passed the resolution before December 31, 2019. Customers within a participating community may opt out of the program and maintain existing rates. Rates approved for the program may not result in any shift of costs or benefits to nonparticipating customers. The program details, including costs, are being developed with the communities for a future filing with the UPSC.
In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million, or 1.0%, of deferred power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. A hearing was held in February 2021 for rates effective March 1, 2021.
In March 2020, Utah's governor signed Utah House Bill 66, Wildland Fire Planning and Cost Recovery Amendments, which requires PacifiCorp to prepare a wildfire protection plan to be approved by the UPSC. All investments, including the cost of capital, made to implement an approved plan are recoverable in rates. The bill also provides a potential liability safe harbor if PacifiCorp is in compliance with its approved wildfire mitigation plan. In addition, the legislation clarifies the standard for real property losses and eliminates the current standard of treble damages awarded for tree losses. The first wildland fire protection plan was filed with the UPSC in June 2020 and was approved by the UPSC in October 2020. As part of the 2020 general rate case, the UPSC approved a Wildland Fire Mitigation Balancing Account to track and defer costs associated with the implementation of the wildland fire protection plan that are not recovered through base rates.
In March 2020, Utah's governor signed Utah House Bill 396, Electric Vehicle Charging Infrastructure Amendments, which directs the UPSC to enable PacifiCorp to recover in rates up to $50 million of electric vehicle infrastructure. The legislation also prohibits a third-party from generating electricity onsite to directly resell to customers through electric vehicle charging infrastructure.
In May 2020, PacifiCorp filed a general rate case with the UPSC requesting an increase in base rates of $96 million, or 4.8%, which PacifiCorp proposed to be implemented over a three-year period with 2.6% effective January 1, 2021, 1.1% effective January 1, 2022 and 1.1% effective January 1, 2023 reflecting the refunding of a portion of 2017 Tax Reform benefits in 2021 and 2022. The proposed increase reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled generating facilities, a wildland fire mitigation cost tracking mechanism to implement Utah House Bill 66, and rate design modernization proposals. The application also requested authorization to recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflected several rate mitigation measures that included use of the balance in the Utah Sustainable Transportation and Energy Plan ("STEP") regulatory accounts to accelerate depreciation of the undepreciated plant balance of certain coal-fueled generation units, including Cholla Unit 4, and the use of a portion of the excess deferred income taxes associated with 2017 Tax Reform to accelerate recognition of certain regulatory assets and further depreciate the Dave Johnston plant balance. In October 2020, PacifiCorp filed rebuttal testimony, modifying its request to an increase in base rates of $72 million, or 3.6%, primarily due to a reduction to the requested return on equity. In December 2020, the UPSC issued an order approving an increase in base rates of $31 million, or 1.6%, effective January 1, 2021 reflecting a reduction in PacifiCorp's requested return on equity and before considering refunds of remaining 2017 Tax Reform benefits. The UPSC approved PacifiCorp's proposed rate mitigation strategy to refund remaining 2017 Tax Reform benefits over two years, resulting in an overall net decrease of $15 million, or 0.7%, effective January 1, 2021 followed by a 1.1% increase on January 1, 2022 and another 1.1% increase on January 1, 2023. The order accepted PacifiCorp's proposal to use Utah STEP regulatory balances and excess deferred income taxes associated with 2017 Tax Reform to accelerate depreciation of Cholla Unit 4 and portions of other coal-fueled generating plant balances, as well as to accelerate recognition of certain regulatory asset balances. The order also authorized PacifiCorp to establish a deferral account for costs associated with the early retirement of Cholla Unit 4 and a Wildland Fire Mitigation Balancing Account as described under "Adjustment Mechanisms" in Item 1 of this Form 10-K. In addition, the UPSC ordered PacifiCorp to initiate a proceeding by March 2021 to establish a balancing account for pension settlement losses.
Oregon
In December 2018, PacifiCorp filed a 2019 RAC application requesting recovery of costs associated with repowering of approximately 900 MWs of company-owned and installed wind facilities expected to be completed in 2019. The associated net power cost and PTC benefits were previously included in the 2019 TAM. An all-party settlement was approved by the OPUC in September 2019, providing for a total rate increase of $24 million, or 1.8%, subject to final cost updates. The first rate increase of $9 million, or 0.7%, was effective October 1, 2019 for four repowered facilities, the second rate increase of $1 million, or 0.1%, was effective December 1, 2019 for one repowered facility and the third rate increase of $5 million, or 0.4%, was effective January 1, 2020 for two repowered facilities. A final rate increase of $5 million, or 0.4%, was effective April 1, 2020 for the two remaining repowered facilities that were placed in service by the end of March 2020. As part of the settlement, parties agreed that depreciation of the Oregon-allocated net book value of certain undepreciated equipment replaced as a result of the applicable repowering projects would be accelerated and offset with excess deferred income taxes resulting from 2017 Tax Reform. In 2020, accelerated depreciation of $40 million and offsetting amortization of excess deferred income taxes was recognized associated with the two remaining repowered facilities included in the 2019 RAC. In October 2020, PacifiCorp filed its annual update for plants placed into service in 2019 requesting an overall rate increase of $2 million, or 0.2%, effective November 1, 2020. The rate was in effect through December 31, 2020 when new rates from the general rate case reset the RAC rates to zero.
In October 2019, the OPUC approved the all-party settlement in the 2020 TAM, effective January 1, 2020. In December 2020, the Cedar Springs II wind facility was placed in service. In compliance with the terms of the settlement adopted by the OPUC, in December 2020, PacifiCorp filed to include the net power costs and PTCs in rates which resulted in a rate decrease of approximately $1 million, or 0.1%, effective December 11, 2020. In December 2020, PacifiCorp also filed an application with the OPUC requesting authorization to defer the revenue requirement associated with the Cedar Springs II wind resource and associated transmission through December 31, 2020, for later inclusion in rates.
In November 2019, PacifiCorp filed a 2020 RAC application requesting an annual increase in rates of $1 million, or 0.1%, associated with repowering the Glenrock III wind facility effective April 1, 2020 and an annual increase in rates of $3 million, or 0.3%, associated with repowering the Dunlap wind facility effective October 15, 2020. As part of its application, PacifiCorp proposed to offset the Oregon-allocated net book value of the replaced wind equipment in this filing with PacifiCorp's OATT revenue related deferral from 2017 through 2019. An all-party settlement was filed in January 2020 supporting the filed request and was approved by the OPUC in March 2020. Based on a final cost update for the Glenrock III wind facility, and including the net power cost and PTC benefits, a 0.02% rate decrease became effective April 1, 2020. In September 2020, PacifiCorp filed for a rate change after the repowered Dunlap wind facility was placed in service. Based on the final cost update for the Dunlap wind facility, and including the net power cost and PTC benefits, an additional rate increase of $2 million, or 0.1%, became effective September 18, 2020. As a result of the settlement, accelerated depreciation of $34 million and offsetting amortization of the OATT deferral was recognized during 2020 associated with undepreciated equipment replaced as a result of the repowering of the Glenrock III and Dunlap wind facilities.
In November 2019, PacifiCorp requested authorization to establish an automatic adjustment clause and rate schedule for the costs and revenues related to the Oregon Corporate Activity Tax ("OCAT") that applies to tax years beginning on or after January 1, 2020. Concurrent with this filing, PacifiCorp also requested authorization to defer the OCAT expense. In January 2020, the OPUC authorized the automatic adjustment clause, rate schedule and application for deferral. PacifiCorp began recovering the estimated OCAT expense effective February 1, 2020. The recovery adjustment for 2020 is 0.41% and the rate is being applied as a percentage surcharge on customers' bills.
In February 2020, PacifiCorp filed a general rate case in Oregon requesting a net rate increase of $71 million, or 5.4%, effective January 1, 2021. The request included a separate tariff rider to recover costs associated with the early retirement of Cholla Unit 4 for an increase of $17 million annually from January 2021 through April 2025 and an annual credit to customers of $25 million for amortization of remaining deferred income tax benefits associated with 2017 Tax Reform over a three-year period beginning January 2021. The request for the increase in base rates reflected recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs and other closure costs associated with coal-fueled facilities and rate design modernization proposals. Net power costs are addressed separately in the Oregon TAM, discussed below. In June 2020, PacifiCorp filed reply testimony requesting a revised net rate increase of $67 million, or 5.0%, effective on January 1, 2021. The revised net rate increase reflected a proposal to offset the costs associated with the early retirement of Cholla Unit 4 with a portion of the deferred income tax benefits associated with 2017 Tax Reform rather than recovering these costs through a separate tariff as proposed in the initial filing. The revised net rate increase also included PacifiCorp's proposal to provide an annual credit to customers of $6 million for amortization of the remaining deferred income tax benefits associated with 2017 Tax Reform over a two-year period beginning January 2021. In August 2020, PacifiCorp filed its surrebuttal testimony requesting a revised net rate increase of $41 million, or 3.1%, effective January 1, 2021. This included a decrease in the requested return on equity, an update to depreciation rates consistent with the settled depreciation study and the proposed annual credit to customers of the remaining deferred income tax benefits associated with 2017 Tax Reform that was modified to $7 million. PacifiCorp also filed a partial stipulation that would settle all rate design and rate spread issues in the general rate case. In PacifiCorp's closing brief filed in October 2020, PacifiCorp modified the requested net rate increase to $40 million, or 3.0%, to accept the OPUC staff's adjustment correcting the ongoing advanced meter infrastructure operating costs reflected in the case. In December 2020, the OPUC approved a net rate decrease of approximately $24 million, or 1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. The new rates approved by the OPUC reflect a modified capital structure for ratemaking purposes and a lower return on equity than proposed by PacifiCorp. The new rates also exclude approximately $27 million in incremental decommissioning costs and other closure costs associated with coal-fueled generating facilities that will be addressed through a separate process in 2021. The order also authorizes an Annual Wildfire Mitigation and Vegetation Management Cost Recovery Mechanism for three years as described under "Adjustment Mechanisms" in Item 1 of this Form 10-K. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to the exclusion of the impacts of repowered wind facilities, new wind facilities and certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings will be made to include these investments in rates concurrent when they are placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021.
In February 2020, PacifiCorp submitted its annual TAM filing in Oregon requesting a decrease of $49 million, or 3.7%, effective January 1, 2021, based on forecast net power costs and loads for the calendar year 2021. The filing includes the customer benefits of new and repowered wind resources, including an increase in PTCs. In June 2020, PacifiCorp filed reply testimony in its annual TAM with updated forecast net power costs resulting in a rate decrease of $47 million, or 3.6%, effective January 1, 2021. In August 2020, PacifiCorp filed a stipulation with the OPUC settling all issues in the proceeding. In October 2020, the OPUC approved the stipulation. In November 2020, the final cost update was filed resulting in an annual rate decrease of $41 million, or 3.1%, effective January 1, 2021.
Wyoming
In July 2019, Wyoming Senate Enrolled Act No. 74 ("SEA 74") went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fueled generation facility in Wyoming before it can receive recovery in rates for capital costs associated with new generation facilities built, in whole or in part, to replace the retiring coal-fueled generation facility. The electric utility is obligated to purchase the electricity from the facility through a power purchase agreement at a price that is no greater than the utility's avoided cost as determined by the WPSC. Costs associated with an approved power purchase agreement are expected to be recoverable in rates from Wyoming customers. In March 2020, the Wyoming governor signed Senate Enrolled Act No. 23, which allows a 1 MW or greater customer to purchase electricity from a coal-fueled generation facility purchased from an electric utility under SEA 74. The WPSC approved new administrative rules to implement the legislation in November 2020, which are expected to go into effect in early 2021. The overall impacts of the legislation and the new administrative rules cannot be determined at this time.
In March 2020, PacifiCorp filed a general rate case with the WPSC requesting an increase in base rates of $7 million, or 1.1%, effective January 1, 2021. The increase reflects recovery of Energy Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requests a revision to the ECAM to eliminate the sharing band and requests authorization to discontinue operations and recover costs associated with the early retirement of Cholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the recovery of the depreciation of certain coal-fueled generation units over time periods that extend beyond the depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million and reflected an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and will resume March 2021. PacifiCorp has requested a rate effective date of July 1, 2021.
In March 2020, the Wyoming governor signed House of Representatives Enrolled Act No. 79, which requires the WPSC to adopt a standard to specify a percentage of an electric utility's electricity to be generated from coal-fueled generation utilizing carbon capture technology by no later than 2030. The bill allows electric utilities to implement a surcharge not to exceed 2% of customer bills to recover costs to comply with the standard. PacifiCorp is working with the WPSC and other stakeholders on rules to implement the legislation. The overall impacts of this legislation cannot be determined at this time.
In April 2020, PacifiCorp filed its annual ECAM and RRA application with the WPSC requesting recovery of $7 million, or 1.0% of deferred net power costs from customers for the period January 1, 2019 through December 31, 2019, reflecting the difference between base and actual net power costs in the 2019 deferral period. The rate change went into effect on an interim basis June 15, 2020. This increase will be offset in part by continued rate credits associated with 2017 Tax Reform benefits and bonus depreciation for which minor adjustments are proposed to go into effect in the same timeframe. The hearing was held and the WPSC issued a bench decision in December 2020, reducing the requested recovery by $1 million.
Washington
In November 2019, PacifiCorp submitted its 2019 decoupling filing with the WUTC for the twelve months ended June 30, 2019. In January 2020, the WUTC approved PacifiCorp's 2019 decoupling filing, which resulted in a $12 million surcredit to customers effective February 1, 2020.
In December 2019, PacifiCorp submitted its 2021 Washington general rate case requesting an overall decrease to rates of $4 million, or 1.1%, effective January 1, 2021. The case includes a proposed ten-year annual surcredit of $7 million to customers primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The case also includes a request for approval of a new cost allocation methodology, updated depreciation rates, incremental decommissioning costs and other closure costs associated with certain coal-fueled facilities, recovery of Energy Vision 2020 investments, and rate design modernization proposals. In April 2020, PacifiCorp submitted supplemental testimony and exhibits to incorporate the impacts of the recently completed decommissioning studies for PacifiCorp's coal-fueled generating resources and updated net power costs. The updates resulted in a revised request for an overall increase to rates of $11 million, or 3.2%. The parties subsequently reached a settlement in principle. In July 2020, the resulting all-party settlement was filed reflecting a rate decrease of $4 million or 1.2%. The settlement adjusts the current $8 million annual surcredit associated with 2017 Tax Reform that was set to expire January 1, 2021 to a five-year annual surcredit of $12 million, primarily associated with the amortization of excess deferred income taxes from 2017 Tax Reform. The settlement also includes approval of the new cost allocation methodology, updated depreciation rates, incremental decommissioning costs and other closure costs associated with certain coal-fueled facilities and rate design modernization proposals. While recovery of the Energy Vision 2020 investments is reflected in the settlement, revenue associated with those investments placed into service after May 1, 2020 will be subject to a prudency review in a separate filing in 2021 to address the cost recovery. In October 2020, PacifiCorp filed a petition for rehearing and motion to amend the settlement stipulation to reflect an increase to net power costs. In the settlement, parties had agreed to offset any increase to net power costs in the October update with the power cost adjustment mechanism deferral account balance. The October update resulted in an increase greater than the balance in the deferral account. To maintain the intent of the settlement to update net power costs and decrease rates for customers, PacifiCorp and the parties to the settlement reached an agreement to reflect this difference in the deferral account for future ratemaking. In November 2020, PacifiCorp and parties filed joint testimony supporting the amended settlement. The settlement was approved by the WUTC in December 2020.
In December 2020, PacifiCorp submitted its 2020 decoupling filing with the WUTC for the twelve months ended June 30, 2020. In January 2021, the WUTC approved PacifiCorp's 2020 decoupling filing, which resulted in a $3 million surcharge to customers over two years effective February 1, 2021.
Idaho
In April 2020, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $21 million, or 3.0%, for deferred costs in 2019. This filing includes recovery of the difference in actual net power costs to the base level in rates, an adder for recovery of the Lake Side 2 resource, changes in PTCs, RECs, and a resource tracking mechanism to match costs with the benefits of wind repowering projects until they are reflected in base rates. This deferral is partially offset by $3 million related to amortization of excess deferred income taxes stemming from 2017 Tax Reform and net of recovery for a regulatory asset related to the prior depreciation study. In May 2020, the IPUC issued an order approving the application as filed with rates effective June 1, 2020.
In March 2020, PacifiCorp filed a notice of intent to file a general rate case with the IPUC. However, in June 2020, PacifiCorp negotiated a settlement with parties that allowed PacifiCorp to avoid filing a general rate case in 2020. The parties will support PacifiCorp's proposal to defer the incremental depreciation expense from the 2018 depreciation study during 2021, request deferred accounting treatment for unrecovered investment and closure costs when Cholla Unit 4 is retired, use a portion of the deferred income tax benefits associated with 2017 Tax Reform to accelerate the depreciation of Cholla Unit 4 and offset future rate increases, and include the Pryor Mountain wind facility and the repowering of the Foote Creek I wind facility in the resource tracking mechanism. In return, PacifiCorp will delay filing a general rate case until 2021 with rates effective January 1, 2022. In July 2020, PacifiCorp filed a settlement stipulation allowing the delay of the general rate case and the related application for an accounting order. In December 2020, the IPUC issued an order approving the application and associated stipulation as filed.
California
In April 2018, PacifiCorp filed a general rate case with the CPUC for an overall rate increase of $1 million, or 0.9%, effective January 1, 2019. A CPUC decision was issued in February 2020, resulting in a $6 million, or 5.1%, rate decrease effective February 6, 2020. The CPUC's final order also resulted in an additional rate decrease of $6 million, or 5.1%, over the next three years due to the amortization of excess deferred income taxes attributed to 2017 Tax Reform.
California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. In January 2020, the CPUC approved the resolution establishing procedural rules for the review and disposition of 2020 Wildfire Mitigation Plans. PacifiCorp submitted its 2020 Wildfire Mitigation Plan in February 2020 for which it received approval in June 2020.
In December 2019, PacifiCorp filed an application notifying the CPUC of the early retirement of the Cholla Unit 4 generating facility and requesting authorization to establish a memorandum account associated with the retirement and decommissioning of Cholla Unit 4. The memorandum account would be used to track costs associated with the unrecovered plant balance, decommissioning and other closure-related costs until PacifiCorp requests recovery in its next general rate case or other proceeding. In July 2020, the CPUC issued a decision approving the requested memorandum account with an effective date of December 27, 2019.
In August 2020, PacifiCorp filed an application with the CPUC to address California energy costs and GHG Allowance costs. The application includes a $7 million, or 6.7% decrease in energy costs, which is largely attributed to PTCs for new and repowered Energy Vision 2020 resources, and an increase of $1 million, or 0.8%, to recover costs for purchasing GHG allowances as required by the state's Cap-and-Trade Program. If this application is approved, this would result in an overall decrease of $6 million, or 5.9% effective January 1, 2021.
MidAmerican Energy
COVID-19
In May 2020, the IUB issued an order authorizing MidAmerican Energy to use a regulatory asset account to record and track increased costs and other financial impacts associated with COVID-19. As of December 31, 2020, MidAmerican Energy has $2 million in a regulatory asset for certain uncollectible customer accounts. At such time as MidAmerican Energy deems appropriate, it may initiate a proceeding with the IUB to seek recovery of such costs and other financial impacts. MidAmerican Energy cannot predict at this time the amount of such financial impacts from COVID-19 or when it will seek recovery of such costs with the IUB.
Iowa Transmission Legislation
In June 2020, Iowa enacted legislation that grants incumbent electric transmission owners the right to construct, own and maintain electric transmission lines that have been approved for construction in a federally registered planning authority's transmission plan and that connect to the incumbent electric transmission owner's facility. Also known as the Right of First Refusal, the law ensures MidAmerican Energy, as an incumbent electric transmission owner, has the legal right to construct, own and maintain transmission lines that have been approved by the MISO (or another federally registered planning authority) in MidAmerican Energy's service territory. To exercise the legal right, MidAmerican Energy must notify the IUB within 90 days of any such approval for construction that it intends to construct, own and maintain the electric transmission line. The law still requires an incumbent electric transmission owner to obtain a state franchise from the IUB to construct, erect, maintain or operate an electric transmission line and, upon issuance of a franchise, the incumbent electric transmission owner provide the IUB an estimate of the cost to construct the electric transmission line and, until the construction is complete, a quarterly report updating the estimated cost to construct the electric transmission line. Legal challenges have been brought against similar laws in other states, but courts that have ruled on such cases have upheld the states' laws. In October 2020, a lawsuit challenging the law was filed in Iowa by national transmission interests. The suit raises issues specific to Iowa law, and the State of Iowa is defending the law in the suit.
Renewable Subscription Program
In December 2020, MidAmerican Energy filed with the IUB a proposed Renewable Subscription Program tariff. If approved, the program will provide qualified industrial customers with the opportunity to meet their future energy growth above baseline levels with renewable energy from specific MidAmerican Energy wind-powered generation additions and 100 MWs of planned solar generation for 20 years at fixed prices based on the cost of such facilities. Under the program, MidAmerican Energy would own the facilities, retain PTCs and other tax benefits associated with the facilities and include all revenues and costs from the program in its Iowa-jurisdictional results of operation, but renewable attributes from the project would be specifically assigned to subscribing customers. Approval by the IUB is pending.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Reviews
In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. In September 2019, Sierra Pacific filed an all-party settlement for the electric regulatory rate review. The settlement resolves all cost of capital and revenue requirement issues and provides for an annual revenue reduction of $5 million and requires Sierra Pacific to share 50% of regulatory earnings above 9.7% with its customers. The rate design portion of the regulatory rate review was not a part of the settlement and a hearing on rate design was held in November 2019. In December 2019, the PUCN issued an order approving the stipulation but made some adjustments to the methodology for the weather normalization component of historical sales in rates, which resulted in an additional annual revenue reduction of $3 million. The new rates were effective January 1, 2020. In January 2020, Sierra Pacific filed a petition for rehearing challenging the PUCN's adjustments to the weather normalization methodology. In February 2020, the PUCN issued an order granting the petition for rehearing. In April 2020, the PUCN issued a final order approving a weather normalization methodology that changed the additional annual revenue reduction from $3 million to $2 million with an effective date of January 1, 2020. Customers billed under rates using the initial revenue reduction were issued credits in the fourth quarter of 2020.
In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative rate-making ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.
In June 2020, Sierra Pacific filed a petition with the PUCN, which was later changed to an application, to adjudicate and establish the cost recovery mechanism for the One Nevada Transmission Line ("ON Line") addressing the reallocated portion of the ON Line revenue requirement. This filing was made concurrent with the Nevada Power regulatory rate review application, which addresses the ON Line reallocated revenue requirement related to Nevada Power. In December 2020, the PUCN issued a final order deferring the ON Line reallocated revenue and regulatory amortization until Sierra Pacific's next regulatory rate review.
2017 Tax Reform
In February 2018, the Nevada Utilities made filings with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by the Nevada Utilities. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing the Nevada Utilities to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, the Nevada Utilities filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, the Nevada Utilities filed a petition for judicial review with the district court. The district court issued an order in March 2020 denying the petition and affirming the PUCN's order. In May 2020, the Nevada Utilities filed a notice of appeal to the Nevada Supreme Court of the district court's order. The Nevada Utilities have agreed to withdraw the notice of appeal as a part of the Nevada Power electric regulatory rate review settlement. In December 2020, the PUCN issued a final order accepting the settlement. In January 2021, the Nevada Utilities filed their withdrawal and the matter was dismissed by the court.
Price Stability Tariff
In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option for renewable resources. The CPST provides for an energy rate that would replace the BTER and deferred energy accounting adjustment. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and other intervenors and a hearing was held in September 2020. In November 2020, the PUCN issued an order approving the tariff with modified pricing and directing the Nevada Utilities to develop a methodology by which all eligible participants may have the opportunity to participate in the CPST program up to a limit with the same proportion of governmental entities' and non-governmental entities' MWh reserved for potentially interested customers as filed. In December 2020, the Nevada Utilities filed a petition for reconsideration of the pricing ordered by the PUCN.
Natural Disaster Protection Plan
The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of 2019 expenditures in February 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the joint application, made adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. The Bureau of Consumer Protection filed a petition for judicial review with the district court in November 2020. In December 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on SB 329 to address rate design issues raised by intervenors. The comment period for the reopened investigation and rulemaking ended in early February 2021 and the matter is ongoing.
COVID-19
In March 2020, the PUCN issued an emergency order for the Nevada Utilities to establish regulatory asset accounts related to the costs of maintaining service to customers affected by COVID-19 whose services would have been terminated or disconnected under normally-applicable terms of service. The Nevada Utilities may incur significant costs as a result of COVID-19, including, but not limited to, higher credit loss expenses resulting from a higher than average level of write-offs of uncollectible accounts associated with the suspension of disconnections and late payment fees to assist customers facing unprecedented economic pressures. The Nevada Utilities also expect to incur additional costs that cannot currently be predicted given the unprecedented nature of COVID-19.
Northern Powergrid Distribution Companies
GEMA, through the Ofgem, published its final determinations for the next set of price controls for transmission and gas distribution networks in Great Britain in December 2020. These determinations do not apply to Northern Powergrid but aspects of the proposals are capable of application to Northern Powergrid's next price control, ("ED2"), which will begin in April 2023.
Regarding allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs, CPIH). When placed on a comparable footing, by adjusting for differences in the assumed equity ratio and the measure of inflation used, the determination for transmission and gas distribution is approximately 200 basis points lower than the current cost of equity for electricity distribution.
In December 2020, in respect of electricity distribution, GEMA published its decision on the methodology it will use to set the ED2 price control and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution. It did not cover financial aspects, including the allowed return on capital, which will be covered by a separate decision in Q1 2021, with confirmation not expected until final determinations in late 2022.
BHE Pipeline Group
BHE GT&S
During 2018, BHE GT&S filed informational filings on FERC Form No. 501-G for EGTS and Carolina Gas. FERC terminated those proceedings without additional action. Also in 2018, BHE GT&S requested a waiver from filing the FERC Form No. 501-G filing requirement for Cove Point. The waiver request was granted.
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of approximately $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of approximately $4 million and a decrease in annual depreciation expense of approximately $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021, which is subject to final approval by the FERC.
Northern Natural Gas
In October 2018, Northern Natural Gas filed an informational filing on FERC Form No. 501-G and a Statement Demonstrating Why No Rate Adjustment is Necessary. In January 2019, FERC initiated a Section 5 investigation to determine whether the rates currently charged by Northern Natural Gas are just and reasonable. As required by the FERC Section 5 order, Northern Natural Gas filed a cost and revenue study in April 2019. In July 2019, Northern Natural Gas filed a Section 4 rate case requesting increases in its transportation and storage rates. In January 2020, the FERC approved Northern Natural Gas' filing to implement its interim rates subject to refund, effective January 1, 2020. In June 2020, a settlement agreement was filed with the FERC, resolving the Section 5 investigation and Section 4 rate case and providing for increased service rates and depreciation rates. Market Area transportation reservation rates increased 28.5% and storage reservation rates increased 67.0% from the rates that were in effect in 2019. Depreciation rates are 2.3% for onshore transmission plant, 2.95% for LNG storage plant, 13.0% for intangible plant, and 2.75% for general plant. The settlement also provides for a Section 4 and Section 5 rate action moratorium through June 30, 2022, subject to certain exceptions, as well as provides for minimum annual maintenance capital spending. The settlement rates were implemented May 1, 2020, and the Company's provision for rate refunds for January 2020 through April 2020 totaled $69 million. The FERC approved the settlement in September 2020, and rate refunds to customers were processed in early October 2020.
Kern River
In October 2018, Kern River filed an informational filing on FERC Form No. 501-G and a Statement Explaining Why No Rate Adjustment is Necessary, along with a Tax Reform Credit Rate Settlement in a companion docket. Kern River's Tax Reform Credit Rate Settlement offered an 11% rate credit against the Maximum Base Tariff Rates for firm service and any one-part rate that includes fixed costs which would result in an expected annual rate credit of $13 million. In November 2018, FERC approved Kern River's Tax Reform Credit effective November 15, 2018.
BHE Transmission
AltaLink
Rate Relief Application
In January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to 2023. The tariff relief measures consist of a proposed refund to customers of C$150 million of previously collected future income taxes and C$200 million of surplus accumulated depreciation. The future income tax refund will be evenly distributed over the two-year period, 2021 to 2022, with C$75 million included in each year. The accumulated depreciation surplus will be refunded over the three-year period, 2021 to 2023, with C$60 million included in 2021 and 2022, and C$80 million in 2023. If approved by the AUC, these tariff relief measures will save customers an estimated C$317 million over the three-year period, 2021 to 2023.
General Tariff Application
In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide a further tariff reduction over the three year period by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In April 2019, AltaLink filed an update to its 2019-2021 GTA primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.
In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the three year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The 2019-2021 negotiated settlement agreement excluded certain matters related to the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.
In October 2019, AltaLink filed a letter with the AUC to request the continuation of the monthly interim refundable transmission tariff effective January 1, 2020, until a final tariff is approved. In October 2019, the AUC confirmed the interim refundable transmission tariff at C$74 million per month, until otherwise directed by the AUC.
In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.
In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and C$898 million for 2021, exclusive of the assets transferred to the PiikaniLink Limited Partnership and the KainaiLink Limited Partnership. The AUC also approved a revised monthly tariff of C$71 million for September 2020 to December 2020 and a monthly tariff of C$74 million for 2021. The 2021 revenue requirement is based on 8.5% return on equity and 37% deemed equity set by the AUC as placeholders.
The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July 2020, AltaLink filed an application with the AUC for the review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. In November 2020, the AUC issued its decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology will decrease the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.
2022 Generic Cost of Capital Proceeding
In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding will consider the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the existing uncertainty as a result of the ongoing COVID-19 pandemic, before establishing a process schedule, the commission has requested participants to submit comments that address the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.
In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there is insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.
2021 Generic Cost of Capital Proceeding
In December 2018, the AUC initiated the 2021 GCOC proceeding to consider returning to a formula-based approach in determining the return on equity for a given year, starting with 2021. In April 2019, after receiving comments from interested parties, the AUC expanded the scope of the proceeding to include a traditional non-formulaic GCOC inquiry as well as the consideration of returning to a formula-based approach.
In January 2020, AltaLink filed company and expert evidence, recommending a range of 8.75% to 10.5% return on equity, on a recommended equity ratio of 40% for 2021 and 2022. The Consumers' Coalition of Alberta, the Utilities Consumer Advocate and the City of Calgary filed intervenor evidence recommending a range of 5.0% to 6.9% return on equity and an AltaLink common equity ratio of 35% to 37% for 2021 and 2022.
In March 2020, as a result of COVID-19, the AUC suspended the proceeding for an indefinite period. This decision was subject to review and reassessment by the AUC every 30 to 60 days. In May 2020, the AUC proposed a method to determine fair cost of capital parameters for 2021 given the circumstances presented by the COVID-19 pandemic. The AUC outlined four options for utilities and interested parties to consider and subsequently added a fifth option that set the 2021 return on equity at 8.3% as a balance between certainty and economic conditions.
In July 2020, AltaLink requested that the AUC continue to hold the proceeding in abeyance and revisit the issue in another 30 to 60 days. AltaLink also requested that if the AUC determined the proceeding should resume, the AUC should set a date for the filing of evidence by all parties in the first quarter of 2021 and that the proceeding should address return on equity for 2021 and 2022 only.
In August 2020, the AUC issued a letter indicating that it had decided not to resume the GCOC proceeding at that time and would continue to assess when, and under what conditions, the proceeding could resume.
In October 2020, the AUC issued its decision and set the final approved return on equity and deemed equity ratio for AltaLink by extending the current approved 8.5% and 37%, respectively, for the duration of 2021.
2014-2015 Deferral Accounts Reconciliation Application
In December 2018 and January 2019, the AUC issued decisions approving C$3,833 million out of the C$4,017 million capital project additions included in the application. Project costs of C$155 million were deferred to a future hearing. The AUC disallowed capital additions of approximately C$29 million including applicable AFUDC, pending receipt of additional supporting documentation for certain items.
AltaLink filed compliance filings in February and September 2019 reflecting the AUC's directives, and AUC approval was received in November 2019. However, the AUC had previously ruled that it would put in placeholder amounts for the approved costs of the assets in the 2014-2015 Deferral Accounts Reconciliation Application proceeding until the AUC-initiated proceeding to consider the issue of transmission asset utilization.
In January 2021, the AUC approved the placeholder amounts as final, noting that the transmission asset utilization proceeding was not initiated and the AUC has no immediate plans to do so.
2016-2018 Deferral Accounts Reconciliation Application
In July 2019, AltaLink filed its 2016-2018 Deferral Accounts Reconciliation Application with the AUC. The application included 116 projects with total gross capital additions, including AFUDC, of C$976 million. In December 2019, the AUC announced a series of technical meetings to address AltaLink's responses to certain information requests.
In March 2020, the AUC issued a letter indicating that it would provide further process steps after AltaLink submitted its remaining responses to information requests and the Consumers' Coalition of Alberta filed its intervener evidence. In May 2020, AltaLink provided additional responses to information requests as directed by the AUC. In accordance with the AUC's revised process schedule, the Consumers' Coalition of Alberta filed its intervener evidence in June 2020, and AltaLink subsequently filed information requests on the intervener evidence in June 2020 and filed its rebuttal evidence in July 2020.
In August 2020, the AUC determined that a hearing was not required and issued a proceeding schedule to provide for argument, reply argument and the close of record by September 2020. In September 2020, AltaLink and interveners filed written argument and reply argument.
In December 2020, the AUC issued its decision approving C$941 million out of the C$947 million capital project additions included in the application. The AUC disallowed capital additions of approximately C$6 million. As part of this proceeding, the AUC also approved the following: AltaLink's deferral accounts for taxes other than income taxes, long-term debt, and annual structure payments; placeholder treatment for project trailing costs associated with two ongoing disputes; and canceled project costs incurred in 2017 and 2018. AltaLink filed compliance filings in January 2021 reflecting the AUC's directives.
2019 Deferral Accounts Reconciliation Application
In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of C$129 million, including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written arguments and AltaLink filed reply arguments.
Alberta Electric System Operator Tariff Decision
In September 2019, the AUC issued its decision with respect to the 2018 AESO tariff. As part of this decision, the AUC approved AltaLink's proposal to refund contributions made by distribution facility owners relative to transmission projects built and owned by transmission facility owners. The proposal would benefit distribution customers by flowing through the lower cost of capital of the transmission facility owner rather than the higher cost of capital of the distribution facility owner. As directed by the AUC, AltaLink would pay FortisAlberta the unamortized contribution balance of approximately C$375 million as of December 2017 and add the amount to AltaLink's rate base if the decision was upheld. The AUC directed the AESO to consult with AltaLink to provide a joint proposal to implement AltaLink's contribution proposal effective in January 2018. In September 2019, FortisAlberta filed a review and variance application with the AUC requesting the AUC re-evaluate its findings with respect to AltaLink's customer contribution proposal relative to distribution facility owners. In October 2019, the AUC granted FortisAlberta's request to proceed to a review and variance with the record closed in November 2019 after submissions from FortisAlberta, AltaLink, and other interested parties. FortisAlberta also filed for permission to appeal the decision with the Court of Appeal, which would not be heard until after the AUC's review proceeding.
In December 2019, the AUC reopened the record of the review and variance proceeding and, in January 2020, issued specific information requests to FortisAlberta and AltaLink to clarify the evidence previously filed. AltaLink and FortisAlberta filed responses to the AUC information requests in January 2020. In February 2020, FortisAlberta filed a motion with the AUC requesting the appointment of a review panel to convene an oral hearing.
In March 2020, as a result of COVID-19, the AUC advised that it would be immediately deferring all public hearings, consultations or information sessions until further notice and requested FortisAlberta to advise the AUC whether it wished to amend its motion. In April 2020, FortisAlberta filed its response requesting an oral hearing, to commence in 105 days.
In May 2020, the AUC denied FortisAlberta's request for an oral hearing but requested expert tax evidence on three areas of disagreement between AltaLink and FortisAlberta. AltaLink and FortisAlberta filed expert evidence in July 2020. The AUC set a further process of information requests and responses and written submissions, which were scheduled to be completed in September 2020.
In September 2020, AltaLink and FortisAlberta filed a written argument and a reply argument. In November 2020, the AUC issued its decision with respect to FortisAlberta's review and variance proceeding. In its decision, the AUC rescinded its earlier findings from the original September 2019 decision which (i) directed FortisAlberta to transfer the unamortized contribution balance of approximately C$375 million to AltaLink and (ii) ruled the new contribution policy proposed by AltaLink be applied. The AUC's decision was based on two main areas: (i) if the original decision was confirmed, FortisAlberta would incur incremental income tax, carrying costs and debt restructuring costs of at least C$117 million that would be required to be recovered from ratepayers and (ii) the AUC determined that a majority of the approximately C$40 million in savings to ratepayers, which the hearing panel relied on as the basis for their original decision, could be achieved by directing FortisAlberta to adjust the applicable amortization rate for its AESO contributions to match the service lives of the transmission assets.
In November 2020, the AUC initiated a separate proceeding to (i) examine the legal basis of the current AESO customer contribution policy as it pertains to all transmission facility owners and distribution facility owners, (ii) consider whether there is a need for a new policy, including consideration of AltaLink's proposed policy and (iii) if approved, set the date on which any new policy would commence.
In December 2020, AltaLink filed its submissions in this proceeding, stating that the current customer contribution policy is contrary to business principles as it allows a distribution facility owner to earn a return on assets that are owned, operated and maintained by a transmission facility owner who has all the risk of ownership and is also contrary to the legislative scheme in Alberta, which delineates the ownership of transmission and distribution assets. AltaLink also stated it disagrees with the AUC's decision and it intends to file an appeal.
In December 2020, AltaLink filed its application for permission to appeal the AUC's review and variance decision with the Court of Appeal. The permission to appeal application is scheduled to be heard in May 2021.
BHE U.S. Transmission
A significant portion of ETT's revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base regulatory rate review scheduled for no later than February 1, 2023. In January 2021, the Public Utilities Commission of Texas ("PUCT") approved ETT's request to suspend a base regulatory rate review filing scheduled for February 2021. Results of a base regulatory rate review would be prospective except for any deemed disallowance by the PUCT of the transmission investment since the initial base regulatory rate review in 2007. In June 2018, the PUCT approved ETT's application to reduce its transmission revenue by $28 million to reflect the lower federal income tax rate due to 2017 Tax Reform with the amortization of excess accumulated deferred federal income taxes expected to be addressed in the next base rate case.
ENVIRONMENTAL LAWS AND REGULATIONS
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The Company has cumulative investments in wind, solar, geothermal and biomass generating facilities of approximately $34 billion and plans to spend an additional $3 billion on the construction of wind-powered generating facilities, repowering certain existing wind-powered generating facilities and funding of wind tax equity investments through 2021. Refer to "Liquidity and Capital Resources" of each respective Registrant in Item 7 of this Form 10-K for discussion of each Registrant's renewable generation-related capital expenditures.
Climate Change
In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021.
GHG Performance Standards
Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and 1,400 pounds of carbon dioxide per MWh for new coal-fueled generating facilities with the "Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through the introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be quickly revisited by the Biden administration. Because the significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will be required to meet the GHG new source performance standards.
Affordable Clean Energy Rule
In June 2014, the EPA released proposed regulations to address GHG emissions from existing fossil-fueled generating facilities, referred to as the Clean Power Plan, under Section 111(d) of the Clean Air Act. The EPA's proposal calculated state-specific emission rate targets to be achieved based on the "Best System of Emission Reduction." In August 2015, the final Clean Power Plan was released, which established the Best System of Emission Reduction as including: (a) heat rate improvements; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities; and (c) increased deployment of new and incremental non-carbon generation placed in-service after 2012. The Clean Power Plan was stayed by the United States Supreme Court in February 2016 while litigation proceeded. On October 10, 2017, the EPA issued a proposal to repeal the Clean Power Plan, which was intended to achieve an overall reduction in carbon dioxide emissions from existing fossil-fueled electric generating units of 32% below 2005 levels. On June 19, 2019, the EPA repealed the Clean Power Plan and issued the Affordable Clean Energy rule, which fully replaced the Clean Power Plan. In the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled power plants is limited to actions that can be taken at a point source facility, specifically heat rate improvements and identified a set of candidate technologies and measures that could improve heat rates. Measures taken to meet the standards of performance must be achieved at the source itself. States have until July 2022 to submit compliance plans to the EPA. The Affordable Clean Energy rule was challenged by environmental and health groups in the D.C. Circuit. On January 19, 2021, the D.C. Circuit vacated and remanded the Affordable Clean Energy rule to the EPA, finding that the rule "rested critically on a mistaken reading of the Clean Air Act" that limited the best system of emission reduction to actions taken at a facility. Until the EPA indicates its course of action in response to this decision, the full impacts on the Registrants cannot be determined. PacifiCorp, MidAmerican Energy, Nevada Power and Sierra Pacific have historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of their generating fleets to include deployment of renewable and lower carbon generating resources, and advanced customer energy efficiency programs.
New Source Performance Standards for Methane Emissions
In August 2020, the EPA finalized regulations to rescind standards for methane emissions from the oil and gas sector. The changes eliminate requirements to regulate methane emissions from the production, processing, transmission and storage of oil and gas. The rule was immediately challenged by environmental and tribal groups, as well as numerous states. In January 2021, the D.C. Circuit lifted an administrative stay and allowed the rule to take effect, finding that groups challenging the rule had not met the standard for a long-term stay. Until such time as litigation is exhausted, the relevant Registrants cannot determine whether additional action may be required.
Regional and State Activities
Several states have promulgated or otherwise participate in state-specific or regional laws or initiatives to report or mitigate GHG emissions. These are expected to impact the relevant Registrant, and include:
•In June 2013, Nevada Senate Bill 123 ("SB 123") was signed into law. Among other things, SB 123 and regulations thereunder required Nevada Power to file with the PUCN an emission reduction and capacity replacement plan by May 1, 2014. In May 2014, Nevada Power filed its emissions reduction capacity replacement plan. The plan provided for the retirement or elimination of 300 MWs of coal-fueled generating capacity by December 31, 2014, another 250 MWs of coal-fueled generating capacity by December 31, 2017, and another 250 MWs of coal generating capacity by December 31, 2019, along with replacement of such capacity with a mixture of constructed, acquired or contracted renewable and non-technology specific generating units. The plan also sets forth the expected timeline and costs associated with decommissioning coal-fueled generating units that will be retired or eliminated pursuant to the plan. The PUCN has the authority to approve or modify the emission reduction and capacity replacement plan filed by Nevada Power. The PUCN may approve variations to Nevada Power's resource plans relative to requirements under SB 123. Refer to Nevada Power's Note 13 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the ERCR Plan.
•Under the authority of California's Global Warming Solutions Act, which includes a series of policies aimed at returning California GHG emissions to 1990 levels by 2020, the California Air Resources Board adopted a GHG cap-and-trade program with an effective date of January 1, 2012; compliance obligations were imposed on entities beginning in 2013. PacifiCorp is subject to the cap-and-trade program as a retail service provider in California and an importer of wholesale energy into California. In 2015, Governor Jerry Brown issued an executive order to reduce emissions to 40% below 1990 levels by 2030 and 80% by 2050. In September 2016, California Senate Bill 32 was signed into law establishing GHG emissions reduction targets of 40% below 1990 levels by 2030.
•The states of California, Washington and Oregon have adopted GHG emissions performance standards for base load electricity generating resources. Under the laws in California and Oregon, the emissions performance standards provide that emissions must not exceed 1,100 pounds of carbon dioxide per MWh. In September 2018, the Washington Department of Commerce amended the emissions performance standards to provide that GHG emissions for base load electricity generating resources must not exceed 925 pounds of carbon dioxide per MWh. These GHG emissions performance standards generally prohibit electric utilities from entering into long-term financial commitments (e.g., new ownership investments, upgrades, or new or renewed contracts with a term of five or more years) unless any base load generation supplied under long-term financial commitments comply with the GHG emissions performance standards.
•In September 2016, the Washington State Department of Ecology issued a final rule regulating GHG emissions from sources in Washington. The rule regulates GHG including carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride beginning in 2017 with three-year compliance periods thereafter (i.e., 2017-2019, 2020-2022, etc.). Under the rule, the Washington State Department of Ecology established GHG emissions reduction pathways for all covered entities. Covered entities may use emission reduction units, which may be traded with other covered entities, to meet their compliance requirements. PacifiCorp's resources that are covered under the rule include the Chehalis generating facility, which is a natural gas combined-cycle plant located in Washington state. PacifiCorp received its baseline emission order on December 17, 2017, which specified the emission reduction requirements for the Chehalis generating facility every three years beginning in 2017. The reduction requirements average 1.7% per year. However, the Washington State Department of Ecology suspended the compliance obligations of the Clean Air Rule after a Thurston County Superior Court judge ruled the state lacks authority to mandate reductions from indirect emitters. On January 16, 2020, the Washington Supreme Court affirmed that the rule limits the applicability of emission standards to actual emitters and cannot be expanded to non-emitters. The court also found that the rule itself is severable, so that the Washington State Department of Ecology may continue to enforce the rule as it applies to emitters. The case was remanded for further proceedings. Pending further action by the lower court, the rule itself remains suspended, but entities subject to the rule are required to continue reporting emissions.
•The Regional Greenhouse Gas Initiative, a mandatory, market-based effort to cap and reduce power sector GHG emissions in eleven Eastern states, required, beginning in 2009, the reduction of carbon dioxide emissions from the power sector of 10% by 2018. Following a program review in 2012, the nine Regional Greenhouse Gas Initiative states implemented a new 2014 cap which was approximately 45% lower than the 2012-2013 cap. The cap is reduced each year by 2.5% from 2015 to 2020. In December 2017, an updated model rule was released by the Regional Greenhouse Gas Initiative states which includes an additional 30% regional cap reduction between 2020 and 2030.
Renewable Portfolio Standards
Each state's RPS described below could significantly impact the relevant Registrant's consolidated financial results. Resources that meet the qualifying electricity requirements under each RPS vary from state to state. Each state's RPS requires some form of compliance reporting and the relevant Registrant can be subject to penalties in the event of noncompliance. Each Registrant believes it is in material compliance with all applicable RPS laws and regulations.
In 1983, Iowa became the first state in the United States to adopt a RPS requiring the state utilities to own or to contract for a combined total of 105 MWs of renewable generating capacity and associated energy production. The IUB allocated the 105-MW requirement between the two utilities in Iowa based on each utility's percentage of their combined estimated Iowa retail peak demand in 1990 resulting in MidAmerican Energy being allocated a RPS requirement of 55.2 MWs. The utility must meet its RPS obligation by either owning renewable energy production facilities located in Iowa or entering into long-term contracts to purchase or wheel electricity from renewable production facilities located in the utility's service area.
Since 1997, NV Energy has been required to comply with a RPS. In November 2020, Nevada voters approved a constitution amendment that requires the state to get at least half its electricity from renewable sources by 2030. Beginning in 2022, the state must get 22% of its electricity from renewable sources. That percentage is increased incrementally over eight years up to the 50% threshold by 2030. The state's previous RPS required utilities to get 25% of their electricity from renewable sources by 2025.
Utah's Energy Resource and Carbon Emission Reduction Initiative provides that, beginning in the year 2025, 20% of adjusted retail electric sales of all Utah utilities be supplied by renewable energy, if it is cost effective. Retail electric sales will be adjusted by deducting the amount of generation from sources that produce zero or reduced carbon emissions, and for sales avoided as a result of energy efficiency and DSM programs. Qualifying renewable energy sources can be located anywhere within the WECC, and RECs can be used.
The Oregon Renewable Energy Act ("OREA") provides a comprehensive renewable energy policy and RPS for Oregon. Subject to certain exemptions and cost limitations established in the law, PacifiCorp and other qualifying electric utilities must meet minimum qualifying electricity requirements for electricity sold to retail customers of at least 5% in 2011 through 2014, 15% in 2015 through 2019, and 20% in 2020 through 2024. In March 2016, Oregon Senate Bill 1547-B ("SB 1547-B"), the Clean Electricity and Coal Transition Plan, was signed into law. SB 1547-B requires coal-fueled resources be eliminated from Oregon's allocation of electricity by January 1, 2030 and increases the current RPS target from 25% in 2025 to 50% by 2040. SB 1547-B also implements new REC banking provisions, as well as the following interim RPS targets: 27% in 2025 through 2029, 35% in 2030 through 2034, 45% in 2035 through 2039, and 50% by 2040 and subsequent years. As required by the OREA, the OPUC has approved an automatic adjustment clause to allow an electric utility, including PacifiCorp, to recover prudently incurred costs of its investments in renewable energy generating facilities and associated transmission costs.
Washington's Energy Independence Act establishes a renewable energy target for qualifying electric utilities, including PacifiCorp. The requirements are 3% of retail sales by January 1, 2012 through 2015, 9% of retail sales by January 1, 2016 through 2019 and 15% of retail sales by January 1, 2020 and each year thereafter. In April 2013, Washington State Senate Bill 5400 ("SB 5400") was signed into law. SB 5400 expands the geographic area in which eligible renewable resources may be located to beyond the Pacific Northwest, allowing renewable resources located in all states served by PacifiCorp to qualify. SB 5400 also provides PacifiCorp with additional flexibility and options to meet Washington's renewable mandates. In May 2019, the state of Washington enacted Senate Bill 5116, the Clean Energy Transformation Act. The legislation, among other things, requires Washington utilities to be carbon neutral by January 1, 2030 and institutes a planning target of 100% non-emitting generation by 2045. Electric utilities must also eliminate from rates coal-fueled resources by December 31, 2025.
The California RPS required all California retail sellers to procure an average of 20% of retail load from renewable resources by December 31, 2013, 25% by December 31, 2016 and 33% by December 31, 2020. In October 2015, California Senate Bill No. 350 became law and increased the RPS target to 50% by December 31, 2030. The state's RPS was further expanded in September 2018, when California Senate Bill 100 ("SB 100"), the 100 Percent Clean Energy Act of 2018 was signed into law. In addition to requiring retail sellers to meet a RPS target of 60% by 2030, SB 100 enabled a longer-term planning target for 100% of total California retail sales to come from eligible renewable energy resources and zero-carbon resources by December 31, 2045. In December 2011, the CPUC adopted a decision confirming that multi-jurisdictional utilities, such as PacifiCorp, are not subject to the percentage limits within the three product content categories of RPS-eligible resources established by the legislation that have been imposed on other California retail sellers.
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, EPA published final designations for much of the United States. 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 will be 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. 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. Until the EPA takes final action consistent with this ruling, impacts to the relevant Registrants cannot be determined.
In January 2010, the EPA finalized a one-hour air quality standard for nitrogen dioxide at 100 parts per billion. In February 2012, the EPA published final designations indicating that based on air quality monitoring data, all areas of the country are designated as "unclassifiable/attainment" for the 2010 nitrogen dioxide NAAQS. On April 6, 2018, EPA issued a decision to retain the 2010 nitrogen dioxide NAAQS without revision.
In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, EPA issued a decision to retain the 2010 SO2 NAAQS without revision.
The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and Des Moines and Wapello Counties were unclassifiable/attainment.
In December 2012, the EPA finalized more stringent fine particulate matter NAAQS, reducing the annual standard from 15 micrograms per cubic meter to 12 micrograms per cubic meter and retaining the 24-hour standard at 35 micrograms per cubic meter. The EPA did not set a separate secondary visibility standard, choosing to rely on the existing secondary 24-hour standard to protect against visibility impairment. In December 2014, the EPA issued final area designations for the 2012 fine particulate matter standard. Based on these designations, the areas in which the relevant Registrant operates generating facilities have been classified as "unclassifiable/attainment." Unless additional monitoring suggests otherwise, the relevant Registrant does not anticipate that any impacts of the revised standard will be significant. In December 2020, the EPA finalized its decision to retain, without revision, the existing primary and secondary standards for particulate matter. In June 2020, the EPA proposed a determination of attainment for the 2006 24-hour fine particulate matter for Salt Lake City and Provo serious nonattainment areas. The determination is based upon quality-assured, quality controlled and certified ambient air monitoring data showing that the area has attained the 2006 standard based on the 2017-2019 monitoring. The comment period for the proposal ended in August 2020. Until the rule is finalized, the relevant Registrants cannot determine the impact on their operations.
In December 2014, the Utah SIP for fine particulate matter was adopted by the Utah Air Quality Board. PacifiCorp's Lake Side, Lake Side 2, Gadsby Steam and Gadsby Peakers generating facilities operate within nonattainment areas for fine particulate matter; however, the SIP did not impose significant new requirements on PacifiCorp's impacted generating facilities, nor did the EPA's comments on the Utah SIP identify requirements for PacifiCorp's existing generating facilities that would have a material impact on its consolidated financial results.
Mercury and Air Toxics Standards
In March 2011, the EPA proposed a rule that requires coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards. The final MATS became effective on April 16, 2012 and required that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources were required to comply with the new standards by April 16, 2015 with the potential for individual sources to obtain an extension of up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The relevant Registrants have completed emission reduction projects to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants.
MidAmerican Energy retired certain coal-fueled generating units as the least-cost alternative to comply with the MATS. Walter Scott, Jr. Energy Center Units 1 and 2 were retired in 2015, and George Neal Energy Center Units 1 and 2 were retired in April 2016. A fifth unit, Riverside Generating Station, was limited to natural gas combustion in March 2015.
Numerous lawsuits have been filed in the D.C. Circuit challenging the MATS. In April 2014, the D.C. Circuit upheld the MATS requirements. In November 2014, the United States Supreme Court agreed to hear the MATS appeal on the limited issue of whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric utilities. Oral argument in the case was held before the United States Supreme Court in March 2015, and a decision was issued by the United States Supreme Court in June 2015, which reversed and remanded the MATS rule to the D.C. Circuit for further action. The United States Supreme Court held that the EPA had acted unreasonably when it deemed cost irrelevant to the decision to regulate generating facilities, and that cost, including costs of compliance, must be considered before deciding whether regulation is necessary and appropriate. The United States Supreme Court's decision did not vacate or stay implementation of the MATS rule. In December 2015, the D.C. Circuit issued an order remanding the rule to the EPA, without vacating the rule. As a result, the relevant Registrants continue to have a legal obligation under the MATS rule and the respective permits issued by the states in which each respective Registrant operates to comply with the MATS rule, including operating all emissions controls or otherwise complying with the MATS requirements.
In December 2018, the EPA issued a proposed revised supplemental cost finding for the MATS, as well as the required risk and technology review under Clean Air Act Section 112. The EPA proposed to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, the EPA proposed to retain the emission standards and other requirements of the MATS rule, because the EPA did not propose to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. In May 2020, the EPA published its decision to repeal the appropriate and necessary findings in the MATS rule and retain the overall emission standards. The rule took effect in July 2020. A number of petitions for review were filed in the D.C. Circuit by parties challenging and supporting the EPA's decision to rescind the appropriate and necessary finding. Until litigation over the rule is exhausted, the relevant Registrants cannot fully determine the impacts of the changes to the MATS rule.
In March 2020, the D.C. Circuit issued an opinion in Chesapeake Climate Action Network v. EPA regarding consolidated challenges to the EPA's startup and shutdown provisions contained in the 2012 MATS rule. The MATS rule's provisions governing startup and shutdown require electric generating units comply with work practice standards as opposed to numerical limits during these periods. The EPA denied petitions for reconsideration of these provisions in 2016 and environmentalists challenged this denial. The D.C. Circuit vacated the reconsideration denials, remanding the petition to the EPA for further action. The court did not make a determination on the merits of the arguments concerning the EPA's legal authority to set work practice standards. The existing work practice standards and the alternate definition for when startup ends continue to be applicable. Until the EPA finalizes action to respond to the court's order, the relevant Registrants cannot fully determine the impacts of the remand.
Cross-State Air Pollution Rule
The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.
The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December 6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit Court. 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 Court issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power plants in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. Until the rule is finalized, the relevant Registrants cannot determine the impact on their operations.
The CSAPR provisions are not anticipated to have a material impact on the Registrants. MidAmerican Energy operates natural gas-fueled generating facilities in Iowa and BHE Renewables operates natural gas-fueled generating facilities in Texas, Illinois and New York, which are subject to the CSAPR. MidAmerican Energy has installed emissions controls at its coal-fueled generating facilities to comply with the CSAPR and may purchase emissions allowances to meet a portion of its compliance obligations. The cost of these allowances is subject to market conditions at the time of purchase and historically has not been material. MidAmerican Energy believes that the controls installed to date are consistent with the reductions to be achieved from implementation of the rule. None of PacifiCorp's, Nevada Power's or Sierra Pacific's generating facilities are subject to the CSAPR. However, in a Notice of Data Availability published in the January 6, 2017, Federal Register, the EPA provided preliminary estimates of which upwind states may have linkages to downwind states experiencing ozone levels at or exceeding the 2015 ozone NAAQS of 70 parts per billion, and, using similar methodology to that in the CSAPR, indicated that Utah and Wyoming could have an obligation under the "good neighbor" provisions of the Clean Air Act to reduce NOx emissions. Until such time as a rule is finalized, the relevant Registrants cannot determine whether additional action may be required.
Regional Haze
The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.
The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions ("CAMX") dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the EPA published its proposed approval of the Utah Regional Haze SIP Alternative, which makes the shutdown of the Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. On January 11, 2021, the Tenth Circuit dismissed the Utah regional haze petitions on the basis of the final rule approved Utah's revised SIP and withdrawing the EPA's FIP. 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.
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 is subject to a comment period which runs through March 5, 2021. Litigation in the Tenth Circuit remains stayed pending finalization of the settlement agreement. In June 2014, the Wyoming Department of Environmental Quality issued a revised BART permit allowing Naughton Unit 3 to operate on coal through 2017 and providing for natural gas conversion of the unit in 2018. In 2017, the department approved an extension of the compliance date for Naughton Unit 3 to align with the requirements of the Wyoming SIP extending the requirement to cease coal firing to no later than January 30, 2019. The EPA issued final approval of the Wyoming SIP, including the Naughton Unit 3 gas conversion on March 21, 2019. PacifiCorp removed the unit from coal-fueled service on January 30, 2019, and its 2019 IRP Action Plan incorporates completion of the gas conversion, including all required regulatory notices and filings, by the end of 2020. 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 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 grants 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. The EPA is reviewing the SIP revisions.
The state of Arizona issued a regional haze SIP requiring, among other things, the installation of SO2, NOx and particulate matter controls on Cholla Unit 4. The EPA approved in part, and disapproved in part, the Arizona SIP and issued a FIP for the disapproved portions requiring SCR controls on Cholla Unit 4. PacifiCorp filed an appeal in the United States Court of Appeals for the Ninth Circuit ("Ninth Circuit") regarding the FIP as it relates to Cholla Unit 4, and the Arizona Department of Environmental Quality and other affected Arizona utilities filed separate appeals of the FIP as it relates to their interests. The Ninth Circuit issued an order in February 2015, holding the matter in abeyance while the parties pursued an alternate compliance approach for Cholla Unit 4. The Arizona Department of Environmental Quality's revision of the draft permit and revision to the Arizona regional haze SIP were approved by the EPA through final action published in the Federal Register on March 27, 2017, with an effective date of April 26, 2017. The final action allows Cholla Unit 4 to utilize coal until April 30, 2025 and convert to gas or otherwise cease burning coal by June 30, 2025. Retirement of Cholla Unit 4 was completed in December 2020.
The state of Colorado regional haze SIP requires SCR controls at Craig Unit 2 and Hayden Units 1 and 2, in which PacifiCorp has ownership interests. Each of those regional haze compliance projects are either already in service or currently being constructed. In addition, in February 2015, the state of Colorado finalized an amendment to its regional haze SIP relating to Craig Unit 1, in which PacifiCorp has an ownership interest, to require the installation of SCR controls by 2021. In September 2016, the owners of Craig Units 1 and 2 reached an agreement with state and federal agencies and certain environmental groups that were parties to the previous settlement requiring SCR to retire Unit 1 by December 31, 2025, in lieu of SCR installation, or alternatively to remove the unit from coal-fueled service by August 31, 2021 with an option to convert the unit to natural gas by August 31, 2023, in lieu of SCR installation. The terms of the agreement were approved by the Colorado Air Quality Board in December 2016, incorporated into an amended Colorado regional haze SIP in 2017 and approved by the EPA in August 2018. PacifiCorp identified a December 31, 2025, retirement date for Craig Unit 1 in its 2017 and 2019 IRPs.
Until the EPA takes final action in each state and decisions have been made in the pending appeals, PacifiCorp cannot fully determine the impacts of the Regional Haze Rule on its respective generating facilities.
Water Quality Standards
The federal Water Pollution Control Act ("Clean Water Act") establishes the framework for maintaining and improving water quality in the United States through a program that regulates, among other things, discharges to and withdrawals from waterways. The Clean Water Act requires that cooling water intake structures reflect the "best technology available for minimizing adverse environmental impact" to aquatic organisms. After significant litigation, the EPA released a proposed rule under §316(b) of the Clean Water Act to regulate cooling water intakes at existing facilities. The final rule was released in May 2014, and became effective in October 2014. Under the final rule, existing facilities that withdraw at least 25% of their water exclusively for cooling purposes and have a design intake flow of greater than two million gallons per day are required to reduce fish impingement (i.e., when fish and other aquatic organisms are trapped against screens when water is drawn into a facility's cooling system) by choosing one of seven options. Facilities that withdraw at least 125 million gallons of water per day from waters of the United States must also conduct studies to help their permitting authority determine what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms (i.e., when organisms are drawn into the facility). PacifiCorp and MidAmerican Energy are assessing the options for compliance at their generating facilities impacted by the final rule and will complete impingement and entrainment studies. PacifiCorp's Dave Johnston generating facility and all of MidAmerican Energy's coal-fueled generating facilities, except Louisa, Ottumwa and Walter Scott, Jr. Unit 4, which have water cooling towers, withdraw more than 125 million gallons per day of water from waters of the United States for once-through cooling applications. PacifiCorp's Jim Bridger, Naughton, Gadsby, Hunter and Huntington generating facilities currently utilize closed cycle cooling towers but are designed to withdraw more than two million gallons of water per day. The standards are required to be met as soon as possible after the effective date of the final rule, but no later than eight years thereafter. The costs of compliance with the cooling water intake structure rule cannot be fully determined until the prescribed studies are conducted and the respective state environmental agencies review the studies to determine whether additional mitigation technologies should be applied. If PacifiCorp's or MidAmerican Energy's existing intake structures require modification, the costs are not anticipated to be significant to the consolidated financial statements. Nevada Power and Sierra Pacific do not utilize once-through cooling water intake or discharge structures at any of their generating facilities. All of the Nevada Power and Sierra Pacific generating stations are designed to have either minimal or zero discharge; therefore, they are not impacted by the §316(b) final rule.
In November 2015, the EPA published final effluent limitation guidelines and standards for the steam electric power generating sector which, among other things, regulate the discharge of bottom ash transport water, fly ash transport water, combustion residual leachate and non-chemical metal cleaning wastes. These guidelines, which had not been revised since 1982, were revised in response to the EPA's concerns that the addition of controls for air emissions has changed the effluent discharged from coal- and natural gas-fueled generating facilities. Under the originally promulgated guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal with the new limits to be met as soon as possible, beginning November 1, 2018 and fully implemented by December 31, 2023. On April 5, 2017, a request for reconsideration and administrative stay of the guidelines was filed with the EPA. The EPA granted the request for reconsideration on April 12, 2017, imposed an immediate administrative stay of compliance dates in the rule that had not passed judicial review and requested the court stay the pending litigation over the rule until September 12, 2017. On June 6, 2017, the EPA proposed to extend many of the compliance deadlines that would otherwise occur in 2018 and on September 18, 2017, the EPA issued a final rule extending certain compliance dates for flue gas desulfurization wastewater and bottom ash transport water limits until November 1, 2020. In a separate action, on April 12, 2019, the Fifth Circuit Court of Appeals vacated two aspects of the final effluent limitation guidelines, concerning discharge limits for (1) legacy wastewater from ash transport or treatment systems and (2) combustion residual leachate from landfills or settling ponds. The Fifth Circuit found that EPA's own data did not support the agency's conclusion that impoundments were the best technology available for these two waste streams. EPA must now complete a new effluent limitation guideline for these discharge limits. On November 22, 2019, the EPA proposed updates to the 2015 rule, specifically addressing flue gas desulfurization wastewater and bottom ash transport water. The rule was finalized in October 2020 and took effect December 14, 2020. EPA revised selenium limits on flue gas desulfurization wastewater and the zero-discharge requirements on bottom ash transport water associated with blowdown of ash handling systems and adjusted compliance dates to allow time to procure and install necessary technology. The rule does not address the wastestreams at issue in the Fifth Circuit Court of Appeal's April 2019 decision. While most of the issues raised by this rule are already being addressed through the CCR rule and are not expected to impose significant additional requirements on the facilities, the impact of the rule cannot be fully determined until any judicial review is conducted.
In April 2014, the EPA and the United States Army Corps of Engineers ("Corps of Engineers") issued a joint proposal to address "waters of the United States" to clarify protection under the Clean Water Act for streams and wetlands. The proposed rule comes as a result of United States Supreme Court decisions in 2001 and 2006 that created confusion regarding jurisdictional waters that were subject to permitting under either nationwide or individual permitting requirements. The final rule was released in May 2015 but is currently under appeal in multiple courts and a nationwide stay on the implementation of the rule was issued in October 2015. On January 13, 2017, the United States Supreme Court granted a petition to address jurisdictional challenges to the rule. The EPA plans to undertake a two-step process, with the first step to repeal the 2015 rule and the second step to carry out a notice-and-comment rulemaking in which a substantive re-evaluation of the definition of the "waters of the United States" will be undertaken. On July 27, 2017, the EPA and the Corps of Engineers issued a proposal to repeal the final rule and recodify the pre-existing rules pending issuance of a new rule, which was finalized September 12, 2019. On January 22, 2018, the United States Supreme Court issued its decision related to the jurisdictional challenges to the rule, holding that federal district courts, rather than federal appeals courts, have proper jurisdiction to hear challenges to the rule and instructed the Sixth Circuit Court of Appeals to dismiss the petitions for review for lack of jurisdiction, clearing the way for imposition of the rule in certain states barring final action by the EPA to formalize the extension of the compliance deadline. On December 11, 2018, the EPA and the Corps of Engineers proposed a revised definition of "waters of the United States" that is intended to further clarify jurisdictional questions, eliminate case-by-case determinations and narrow Clean Water Act jurisdiction to align with Justice Scalia's 2006 opinion in Rapanos v. United States. On January 23, 2020, the EPA and the Corps of Engineers signed the final rule narrowing the federal government's permitting authority under the Clean Water Act. The new Navigable Waters Protection Rule, which took effect 60 days after it was published in the Federal Register, redefines what waters qualify as navigable waters of the U.S. and are under Clean Water Act jurisdiction. Under the new rule, the Clean Water Act will be considered to cover territorial seas and traditional navigable waters; tributaries that flow into jurisdictional waters; wetlands that are directly adjacent to jurisdictional waters; and lakes, ponds and impoundments of jurisdictional waters. The agency and corps originally proposed six categories, but in the final version they collapsed ditches and impoundments into other categories. There are also 12 categories of waters that the agencies highlighted as being excluded from coverage, including groundwater, ephemeral streams and pools, prior converted cropland and waste treatment systems. Until the rule is fully litigated and finalized, the Registrants cannot predict the impact on overall compliance obligations.
In April 2020, the United States Supreme Court established a new test for Clean Water Act jurisdiction in County of Maui, Hawaii v. Hawaii Wildlife Fund, finding that the statute can cover discharges of contaminated groundwater in certain circumstances. The United States Supreme Court outlined a seven-factor test to determine whether discharges conveyed through groundwater to surface water are "functionally equivalent" to direct discharges, finding that the time it takes for pollutants to travel through groundwater and the distance traveled are the two most important factors in the test. The United States Supreme Court remanded County of Maui, Hawaii to the Ninth Circuit Court of Appeals for further adjudication, which subsequently remanded the case to the district court to determine whether additional discovery is needed before applying the new seven-factor test. The EPA finalized guidance January 14, 2021, implementing County of Maui. The EPA utilized the United States Supreme Court's seven factors, plus an additional factor for the design and performance of the system or facility from which the pollutant is reached, to determine whether pollutants that reach surface waters after traveling through groundwater are a "functional equivalent" to a direct discharge that require a permit. Until the functional equivalent test and guidance are applied by the courts, the Registrants cannot determine the impact of this case on their operations.
In April 2020, the U.S. District Court of the District of Montana vacated nationwide permit 12, which provides an expedited route for projects like oil and gas pipelines and utility lines to achieve compliance with the Clean Water Act, finding that the Corps of Engineers, which implements the nationwide permit program, failed to conduct necessary programmatic consultation of nationwide permit 12 under the Endangered Species Act. The district court's vacatur, which was subsequently limited just to the Keystone XL pipeline project, the subject of the initial lawsuit, is on appeal to the Ninth Circuit Court of Appeals. On January 13, 2021, the Corps of Engineers finalized a rule modifying its nationwide permit program for certain activities affecting waters of the United States. The final rule restructures the nationwide permit program for utility lines by splitting the existing nationwide permit 12 into three separate nationwide permits - one for oil and gas, including pipelines; one for electrical and telecommunications; and one for water/sewer and other utilities. The Corps of Engineers included a biological assessment for the final rule but did not conduct a formal Endangered Species Act consultation in connection with reissuance of the nationwide permits. The Corps of Engineers reissued and revised 12 of 52 and added four new nationwide permits, which will be effective for a period of five years. The remaining nationwide permits are scheduled for renewal in advance of expiration in 2022. Until the nationwide permit challenges are fully litigated, the Registrants cannot determine the impact of this case on their operations.
Coal Combustion Byproduct Disposal
In May 2010, the EPA released a proposed rule to regulate the management and disposal of coal combustion byproducts under the RCRA. The final rule was released by the EPA on December 19, 2014, was published in the Federal Register on April 17, 2015 and was effective on October 19, 2015. The final rule regulates coal combustion byproducts as non-hazardous waste under RCRA Subtitle D and establishes minimum nationwide standards for the disposal of CCR. Under the final rule, surface impoundments and landfills utilized for coal combustion byproducts may need to be closed unless they can meet the more stringent regulatory requirements. The final rule requires regulated entities to post annual groundwater monitoring and corrective action reports. The first of these reports was posted to the respective Registrant's coal combustion rule compliance data and information websites in March 2018. Based on the results in those reports, additional action may be required under the rule.
At the time the rule was published in April 2015, PacifiCorp operated 18 surface impoundments and seven landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, nine surface impoundments and three landfills were either closed or repurposed to no longer receive coal combustion byproducts and hence are not subject to the final rule. As PacifiCorp proceeded to implement the final coal combustion rule, it was determined that two surface impoundments located at the Dave Johnston generating facility were hydraulically connected and effectively constitute a single impoundment. In November 2017, a new surface impoundment was placed into service at the Naughton Generating Station. At the time the rule was published in April 2015, MidAmerican Energy owned or operated nine surface impoundments and four landfills that contain coal combustion byproducts. Prior to the effective date of the rule in October 2015, MidAmerican Energy closed or repurposed six surface impoundments to no longer receive coal combustion byproducts. Five of these surface impoundments were closed on or before December 21, 2017 and the sixth is undergoing closure. At the time the rule was published in April 2015, the Nevada Utilities operated ten evaporative surface impoundments and two landfills that contained coal combustion byproducts. Prior to the effective date of the rule in October 2015, the Nevada Utilities closed four of the surface impoundments, four impoundments discontinued receipt of coal combustion byproducts making them inactive and two surface impoundments remain active and subject to the final rule. The two landfills remain active and subject to the final rule.
Multiple parties filed challenges over various aspects of the final rule in the D.C. Circuit in 2015, resulting in settlement of some of the issues and subsequent regulatory action by the EPA, including subjecting inactive surface impoundments to regulation. Oral argument was held by the D.C. Circuit on November 20, 2017 over certain portions of the 2015 rule that had not been settled or otherwise remanded. On August 21, 2018, the D.C. Circuit issued its opinion in Utility Solid Waste Activities Group v. EPA, finding it was arbitrary and capricious for EPA to allow unlined ash ponds to continue operating until some unknown point in the future when groundwater contamination could be detected. The D.C. Circuit vacated the closure section of the CCR rule and remanded the issue of unlined ponds to EPA for reconsideration with specific instructions to consider harm to the environment, not just to human health. The D.C. Circuit also held EPA's decision to not regulate legacy ponds was arbitrary and capricious. While the D.C. Circuit's decision was pending, the EPA, on March 15, 2018, issued a proposal to address provisions of the final CCR rule that were remanded back to the agency on June 14, 2016, by the D.C. Circuit. The proposal included provisions that establish alternative performance standards for owners and operators of CCR units located in states that have approved permit programs or are otherwise subject to oversight through a permit program administered by the EPA. The EPA finalized the first phase of the CCR rule amendments on July 30, 2018, with an effective date of August 28, 2018 (the "Phase 1, Part 1 rule"). In addition to adopting alternative performance standards and revising groundwater performance standards for certain constituents, EPA extended the deadline by which facilities must initiate closure of unlined ash ponds exceeding a groundwater protection standard and impoundments that do not meet the rule's aquifer location restrictions to October 31, 2020. Following submittal of competing motions from environmental groups and the EPA to stay or remand this deadline extension, on March 13, 2019, the D.C. Circuit granted EPA's request to remand the rule and left the October 31, 2020 deadline in place while the agency undertakes a new rulemaking establishing a new deadline for initiating closure. On August 14, 2019, the EPA released its "Phase 2" proposal, which contains targeted amendments to the CCR rule in response to court remands and EPA settlement agreements, as well as issues raised in a rulemaking petition. The Phase 2 proposal modifies the definition of "beneficial use" by replacing a mass-based threshold with new location-based criteria for triggering the need to conduct an environmental demonstration; establishes a definition of "CCR storage pile" to address the temporary storage of CCR on the ground, depending on whether the material is destined for disposal or beneficial use; makes certain changes to the rule's annual groundwater monitoring and corrective action reports to make it easier for the public to see and understand the data contained within the reports; modifies the requirements related to facilities' publicly available CCR rule websites to make the information more readily available; and establishes a risk-based groundwater monitoring protection standard for boron in the event the EPA decides to add boron to Appendix IV in the CCR rule. The EPA accepted comments on the Phase 2 proposal through October 15, 2019. On December 22, 2020, the EPA released a notice of data availability relating to the Phase 2 proposal to revise the CCR rule's definition of beneficial use and provisions governing piles of CCR on- and off-site prior to beneficial use. The new information presented by the notice includes data and information the EPA received during the comment period on the Phase 2 proposal. The EPA accepted comment on the notice of data availability through February 22, 2021. The EPA has not announced an anticipated timeline for completing the Phase 2 rule. In February 2020, the EPA proposed a federal CCR permit program as required by the WIIN Act of 2016. The proposal would require permits for all CCR units in states that do not have an EPA-approved CCR program. The proposal would establish individual, general and permit-by-rule permits; a tiered schedule for applications to prioritize permits for high-hazard potential CCR units; and postpone timelines for permit applications for all other CCR units. The EPA has not announced an anticipated timeline for completing the federal CCR permit rule. In October 2020, the EPA released an advanced notice of proposed rulemaking on legacy CCR surface impoundments, seeking comment on and information related to issues relevant to development of regulations for legacy impoundments. Issues identified by the EPA include the definition of a legacy impoundment, information on the universe of legacy impoundments, the types of regulatory requirements that should apply to legacy impoundments, and the EPA's regulatory authority to regulate legacy impoundments under RCRA subtitle D. The EPA accepted comment on the advanced notice through February 12, 2021. Until the proposals are finalized and fully litigated, the Registrants cannot determine whether additional action may be required.
In August 2020, the EPA finalized its Holistic Approach to Closure: Part A rule ("Part A rule"). This proposal addressed the D.C. Circuit's revocation of the provisions that allow unlined impoundments to continue receiving ash. The Part A rule was finalized in August 2020 and establishes a new deadline of April 11, 2021, by which all unlined surface impoundments (including clay lined impoundments that do not otherwise meet the definition of "lined") must initiate closure. The Part A rule also identifies two extensions to that date: (1) a site-specific extension to develop alternate disposal capacity and initiate closure by October 15, 2023; and (2) a site-specific extension for facilities that agree to shut down the coal-fueled unit and complete ash pond closure activities by October 17, 2028. In addition to these closure deadline provisions, the Part A rule also finalized changes to the CCR rule's annual groundwater monitoring and corrective action reports and modified requirements related to CCR rule compliance websites initially proposed in the Phase 2 rule. PacifiCorp developed a demonstration for the development of alternative capacity for the Jim Bridger Plant FGD Pond 2 and a demonstration for closure of the Naughton Plant and ash pond and submitted them to the EPA in November 2020. Approval of these demonstrations is anticipated in first quarter 2021. No other Registrants used the provisions of the Part A rule. In December 2020, the EPA finalized its Holistic Approach to Closure: Part B rule ("Part B rule"), which establishes procedures for owners and operators of unlined ash ponds to demonstrate that the liner systems or underlying soils for these units perform as well as the liner criteria in the CCR rule. Additional provisions included in the proposed rule but not finalized, including the use of CCR in closure activities and allowing for the completion of groundwater corrective action during the post-closure care period, will be addressed in future rulemakings. As finalized, none of the relevant Registrants anticipate exercising the provisions of the Part B rule.
Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' CCR permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Using that guidance, the state of Oklahoma applied for EPA approval of its state program and, on June 28, 2018, the EPA's approval of the application was published in the Federal Register. Environmental groups, including Waterkeeper Alliance and the Sierra Club, filed suit in the D.C. Circuit on September 26, 2018, alleging that the EPA unlawfully approved Oklahoma's permit program. This suit also incorporates claims first identified in a July 26, 2018 notice of intent to sue that alleged the EPA failed to perform nondiscretionary duties related to the development and publication of minimum guidelines for public participation in the approval of state permit programs for CCR. To date, none of the states in which the Registrants operate has applied for EPA approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required PacifiCorp to submit permit applications for two of its landfills by March 2017. It is anticipated that the state of Utah will apply for EPA approval of its CCR permit program prior to the end of 2021. In 2019, the state of Wyoming proposed to adopt state rules which incorporate the final federal rule by reference. It is anticipated that Wyoming will finalize its rule and seek the EPA's approval to implement a state permit program in 2021.
Notwithstanding the status of the final CCR rule, citizens' suits have been filed against regulated entities seeking judicial relief for contamination alleged to have been caused by releases of coal combustion byproducts. Some of these cases have been successful in imposing liability upon companies if coal combustion byproducts contaminate groundwater that is ultimately released or connected to surface water. In addition, actions have been filed against regulated entities seeking to require that surface impoundments containing CCR be subject to closure by removal rather than being allowed to effectuate closure in place as provided under the final rule. The Registrants are not a party to these lawsuits and until they are resolved, the Registrants cannot predict the impact on overall compliance obligations.
On January 20, 2021, President Biden issued an executive order on climate change which also required review of actions taken over the preceding four years that were harmful to "public health, environment, unsupported by the best available science, or otherwise not in the national best interest." The order included a non-exhaustive list of regulatory actions to be reviewed by the issuing agencies, including New Source Performance Standards for the power sector and the oil and gas sector, rescission of the Clean Power Plan, particulate matter and ozone NAAQS, steam electric effluent limitation guidelines, waters of the United States, reissuance of nationwide permits, and the phase one, part one and holistic approach to closure: parts A and B under the CCR rule. In addition, the Biden administration issued a regulatory freeze memorandum that prohibits submission of rules and guidance documents to the Federal Register without direct review, requires immediate withdrawal of rules and guidance documents submitted to the Federal Register but not yet published, and, for rules and guidance documents published but not yet having taken effect, consideration of a 60-day delay and possible additional comment period. Until the issuing agency completes its review and takes final action consistent with these directives, the relevant Registrant cannot determine whether additional action under any of these rules will be necessary.
Other
Other laws, regulations and agencies to which the relevant Registrants are subject include, but are not limited to:
•The federal Comprehensive Environmental Response, Compensation and Liability Act and similar state laws may require any current or former owners or operators of a disposal site, as well as transporters or generators of hazardous substances sent to such disposal site, to share in environmental remediation costs. Certain Registrants have been identified as potentially responsible parties in connection with certain disposal sites. The relevant Registrants have completed several cleanup actions and are participating in ongoing investigations and remedial actions. Costs associated with these actions are not expected to be material and are expected to be found prudent and included in rates.
•The Nuclear Waste Policy Act of 1982, under which the United States DOE is responsible for the selection and development of repositories for, and the permanent disposal of, spent nuclear fuel and high-level radioactive wastes. Refer to Note 14 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 11 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K for additional information regarding MidAmerican Energy's nuclear decommissioning obligations.
•The federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes establish operational, reclamation and closure standards that must be met during and upon completion of PacifiCorp's mining activities.
•The FERC evaluates hydroelectric systems to ensure environmental impacts are minimized, including the issuance of environmental impact statements for licensed projects both initially and upon relicensing. The FERC monitors the hydroelectric facilities for compliance with the license terms and conditions, which include environmental provisions. Refer to Note 16 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K and Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for information regarding the relicensing of PacifiCorp's Klamath River hydroelectric system.
The Registrants expect they will be allowed to recover their respective prudently incurred costs to comply with the environmental laws and regulations discussed above. The Registrants' planning efforts take into consideration the complexity of balancing factors such as: (a) pending environmental regulations and requirements to reduce emissions, address waste disposal, ensure water quality and protect wildlife; (b) avoidance of excessive reliance on any one generation technology; (c) costs and trade-offs of various resource options including energy efficiency, demand response programs and renewable generation; (d) state-specific energy policies, resource preferences and economic development efforts; (e) additional transmission investment to reduce power costs and increase efficiency and reliability of the integrated transmission system; and (f) keeping rates affordable. Due to the number of generating units impacted by environmental regulations, deferring installation of compliance-related projects is often not feasible or cost effective and places the Registrants at risk of not having access to necessary capital, material, and labor while attempting to perform major equipment installations in a compressed timeframe concurrent with other utilities across the country. Therefore, the Registrants have established installation schedules with permitting agencies that coordinate compliance timeframes with construction and tie-in of major environmental compliance projects as units are scheduled off-line for planned maintenance outages; these coordinated efforts help reduce costs associated with replacement power and maintain system reliability.
Item 1A.
Item 1A. Risk Factors
Each Registrant is subject to numerous risks and uncertainties, including, but not limited to, those described below. Careful consideration of these risks, together with all of the other information included in this Form 10-K and the other public information filed by the relevant Registrant, should be made before making an investment decision. Additional risks and uncertainties not presently known or which each Registrant currently deems immaterial may also impair its business operations. Unless stated otherwise, the risks described below generally relate to each Registrant.
Corporate and Financial Structure Risks
BHE is a holding company and depends on distributions from subsidiaries, including joint ventures, to meet its obligations.
BHE is a holding company with no material assets other than the ownership interests in its subsidiaries and joint ventures, collectively referred to as its subsidiaries. Accordingly, cash flows and the ability to meet BHE's obligations are largely dependent upon the earnings of its subsidiaries and the payment of such earnings to BHE in the form of dividends or other distributions. BHE's subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay amounts due pursuant to BHE's senior debt, junior subordinated debt or its other obligations, or to make funds available, whether by dividends or other payments, for the payment of amounts due pursuant to BHE's senior debt, junior subordinated
debt or its other obligations, and do not guarantee the payment of any of its obligations. Distributions from subsidiaries may also be limited by:
•their respective earnings, capital requirements, and required debt and preferred stock payments;
•the satisfaction of certain terms contained in financing, ring-fencing or organizational documents; and
•regulatory restrictions that limit the ability of BHE's regulated utility subsidiaries to distribute profits.
BHE is substantially leveraged, the terms of its existing senior and junior subordinated debt do not restrict the incurrence of additional debt by BHE or its subsidiaries, and BHE's senior debt is structurally subordinated to the debt of its subsidiaries, and each of such factors could adversely affect BHE's consolidated financial results.
A significant portion of BHE's capital structure is comprised of debt, and BHE expects to incur additional debt in the future to fund items such as, among others, acquisitions, capital investments and the development and construction of new or expanded facilities. As of December 31, 2020, BHE had the following outstanding obligations:
•senior unsecured debt of $13.4 billion;
•junior subordinated debentures of $100 million;
•guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $1.3 billion; and
•commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $563 million.
BHE's consolidated subsidiaries also have significant amounts of outstanding debt, which totaled $38.6 billion as of December 31, 2020. These amounts exclude (a) trade debt, (b) preferred stock obligations, (c) letters of credit in respect of subsidiary debt, and (d) BHE's share of the outstanding debt of its own or its subsidiaries' equity method investments.
Given BHE's substantial leverage, it may not have sufficient cash to service its debt, which could limit its ability to finance future acquisitions, develop and construct additional projects, or operate successfully under difficult conditions, including those brought on by adverse national and global economies, unfavorable financial markets or growth conditions where its capital needs may exceed its ability to fund them. BHE's leverage could also impair its credit quality or the credit quality of its subsidiaries, making it more difficult to finance operations or issue future debt on favorable terms, and could result in a downgrade in debt ratings by credit rating agencies.
The terms of BHE's and its subsidiaries' debt do not limit BHE's ability or the ability of its subsidiaries to incur additional debt or issue preferred stock. Accordingly, BHE or its subsidiaries could enter into acquisitions, new financings, refinancings, recapitalizations, leases or other highly leveraged transactions that could significantly increase BHE's or its subsidiaries' total amount of outstanding debt. The interest payments needed to service this increased level of debt could adversely affect BHE's or its subsidiaries' financial results. Many of BHE's subsidiaries' debt agreements contain covenants, or may in the future contain covenants, that restrict or limit, among other things, such subsidiaries' ability to create liens, sell assets, make certain distributions, incur additional debt or miss contractual deadlines or requirements, and BHE's ability to comply with these covenants may be affected by events beyond its control. Further, if an event of default accelerates a repayment obligation and such acceleration results in an event of default under some or all of BHE's other debt, BHE may not have sufficient funds to repay all of the accelerated debt simultaneously, and the other risks described under "Corporate and Financial Structure Risks" may be magnified as well.
Because BHE is a holding company, the claims of its senior debt holders are structurally subordinated with respect to the assets and earnings of its subsidiaries. Therefore, the rights of its creditors to participate in the assets of any subsidiary in the event of a liquidation or reorganization are subject to the prior claims of the subsidiary's creditors and preferred shareholders, if any. In addition, pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties, the equity interest of MidAmerican Funding's subsidiary and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of solar and wind generation projects, are directly or indirectly pledged to secure their financings and, therefore, may be unavailable as potential sources of repayment of BHE's debt.
A downgrade in BHE's credit ratings or the credit ratings of its subsidiaries, including the Subsidiary Registrants, could negatively affect BHE's or its subsidiaries' access to capital, increase the cost of borrowing or raise energy transaction credit support requirements.
BHE's senior unsecured debt and its subsidiaries' long-term debt, including the Subsidiary Registrants, are rated by various rating agencies. BHE cannot give assurance that its senior unsecured debt rating or any of its subsidiaries' long-term debt ratings will not be reduced in the future. Although none of the Registrants' outstanding debt has rating-downgrade triggers that would accelerate a repayment obligation, a credit rating downgrade would increase any such Registrant's borrowing costs and commitment fees on its revolving credit agreements and other financing arrangements, perhaps significantly. In addition, such Registrant would likely be required to pay a higher interest rate in future financings, and the potential pool of investors and funding sources would likely decrease. Further, access to the commercial paper market could be significantly limited, resulting in higher interest costs.
Similarly, any downgrade or other event negatively affecting the credit ratings of BHE's subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could cause BHE to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing its and its subsidiaries' liquidity and borrowing capacity.
Most of the Registrants' large wholesale customers, suppliers and counterparties require such Registrant to have sufficient creditworthiness in order to enter into transactions, particularly in the wholesale energy markets. If the credit ratings of a Registrant were to decline, especially below investment grade, the relevant Registrant's financing costs and borrowings would likely increase because certain counterparties may require collateral in the form of cash, a letter of credit or some other form of security for existing transactions and as a condition to entering into future transactions with such Registrant. Amounts could be material and could adversely affect such Registrant's liquidity and cash flows.
BHE's majority shareholder, Berkshire Hathaway, could exercise control over BHE in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors and BHE could exercise control over the Subsidiary Registrants in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors and PacifiCorp's preferred stockholders.
Berkshire Hathaway is majority owner of BHE and has control over all decisions requiring shareholder approval. In circumstances involving a conflict of interest between Berkshire Hathaway and BHE's creditors, Berkshire Hathaway could exercise its control in a manner that would benefit Berkshire Hathaway to the detriment of BHE's creditors.
BHE indirectly owns all of the common stock of PacifiCorp, Nevada Power and Sierra Pacific and the membership interest in Eastern Energy Gas. BHE is also the sole member of MidAmerican Funding and, accordingly, indirectly owns all of MidAmerican Energy's common stock. As a result, BHE has control over all decisions requiring shareholder approval, including the election of directors. In circumstances involving a conflict of interest between BHE and the creditors of the Subsidiary Registrants, BHE could exercise its control in a manner that would benefit BHE to the detriment of the Subsidiary Registrants' creditors.
Business Risks
Much of BHE's growth has been achieved through acquisitions, and any such acquisition may not be successful.
Much of BHE's growth has been achieved through acquisitions. Future acquisitions may range from buying individual assets to the purchase of entire businesses. BHE will continue to investigate and pursue opportunities for future acquisitions that it believes, but cannot assure, may increase value and expand or complement existing businesses. BHE may participate in bidding or other negotiations at any time for such acquisition opportunities which may or may not be successful.
Any acquisition entails numerous risks, including, among others:
•the failure to complete the transaction for various reasons, such as the inability to obtain the required regulatory approvals, materially adverse developments in the potential acquiree's business or financial condition or successful intervening offers by third parties;
•the failure of the combined business to realize the expected benefits;
•the risk that federal, state or foreign regulators or courts could require regulatory commitments or other actions in respect of acquired assets, potentially including programs, contributions, investments, divestitures and market mitigation measures;
•the risk of unexpected or unidentified issues not discovered in the diligence process; and
•the need for substantial additional capital and financial investments.
An acquisition could cause an interruption of, or a loss of momentum in, the activities of one or more of BHE's subsidiaries. In addition, the final orders of regulatory authorities approving acquisitions may be subject to appeal by third parties. The diversion of BHE management's attention and any delays or difficulties encountered in connection with the approval and integration of the acquired operations could adversely affect BHE's combined businesses and financial results and could impair its ability to realize the anticipated benefits of the acquisition.
BHE cannot assure that future acquisitions, if any, or any integration efforts will be successful, or that BHE's ability to repay its obligations will not be adversely affected by any future acquisitions.
The Registrants are subject to operating uncertainties and events beyond each respective Registrant's control that impact the costs to operate, maintain, repair and replace utility and interstate natural gas pipeline systems, which could adversely affect each respective Registrant's financial results.
The operation of complex utility systems or interstate natural gas pipeline and storage systems that are spread over large geographic areas involves many operating uncertainties and events beyond each respective Registrant's control. These potential events include the breakdown or failure of the Registrants' thermal, nuclear, hydroelectric, solar, wind and other electricity generating facilities and related equipment, compressors, pipelines, transmission and distribution lines or other equipment or processes, which could lead to catastrophic events; unscheduled outages; strikes, lockouts or other labor-related actions; shortages of qualified labor; transmission and distribution system constraints; failure to obtain, renew or maintain rights-of-way, easements and leases on United States federal, Native American, First Nations or tribal lands; terrorist activities or military or other actions, including cyber attacks; fuel shortages or interruptions; unavailability of critical equipment, materials and supplies; low water flows and other weather-related impacts; performance below expected levels of output, capacity or efficiency; operator error; third-party excavation errors; unexpected degradation of pipeline systems; design, construction or manufacturing defects; and catastrophic events such as severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics (including potentially in relation to COVID-19) and embargoes. A catastrophic event might result in injury or loss of life, extensive property damage or environmental or natural resource damages. For example, in the event of an uncontrolled release of water at one of PacifiCorp's high hazard potential hydroelectric dams, it is probable that loss of human life, disruption of lifeline facilities and property damage could occur in the downstream population and civil or other penalties could be imposed by the FERC. The extent of that liability would be determined by the applicable state law where any such damage occurred. Any of these events or other operational events could significantly reduce or eliminate the relevant Registrant's revenue or significantly increase its expenses, thereby reducing the availability of distributions to BHE. For example, if the relevant Registrant cannot operate its electricity or natural gas facilities at full capacity due to damage caused by a catastrophic event, its revenue could decrease and its expenses could increase due to the need to obtain energy from more expensive sources.
Further, the Registrants self-insure many risks, and current and future insurance coverage may not be sufficient to replace lost revenue or cover repair and replacement costs or other damages. The scope, cost and availability of each Registrant's insurance coverage may change, including the portion that is self-insured. Any reduction of each Registrant's revenue or increase in its expenses resulting from the risks described above, could adversely affect the relevant Registrant's financial results.
The Registrants are subject to increasing risk from catastrophic wildfires and may be unable to obtain enough insurance coverage at a reasonable cost or at all to adequately protect the Registrants from liability, which could materially affect the Registrants financial results and liquidity.
The risk of catastrophic and severe wildfires has increased in the western United States giving rise to large damage claims against utilities for fire-related losses. Catastrophic and severe wildfires can occur in PacifiCorp, Nevada Power and Sierra Pacific's ("Western Domestic Utilities") service territory even when the Western Domestic Utilities effectively implement their wildfire mitigation plans and prudently manage their systems.
In California, for example, where PacifiCorp operates, "inverse condemnation" currently exposes utilities to potential liability for property damages where the utility's electrical equipment was a substantial cause of the wildfire. California courts have held that utilities can be held liable under inverse condemnation without being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover attorney's fees. As a result of inverse condemnation being applied to utilities and wildfire damages, recent losses recorded by insurance companies, and the risk of an increase in the frequency, duration and size of wildfires, insurance for wildfire liabilities may not be available or may be available only at rates that are prohibitively expensive. In addition, even if insurance for wildfire liabilities is available, it may not be available in amounts
necessary to cover potential losses. Uninsured losses and increases in the cost of insurance may be challenged when PacifiCorp seeks cost recovery and may not be recoverable in customer rates.
The Western Domestic Utilities monitor weather conditions with specific thresholds for designated high fire consequence areas to help ensure the safe and reliable operation of their systems during periods of elevated wildfire ignition risk. Should weather conditions become extreme, the Western Domestic Utilities may de-energize certain sections of their distribution and transmission facilities as a last resort to minimize risk to the public. These "public safety power shutoffs" could be subject to increased scrutiny by regulators and policy makers. And, although "public safety power shutoffs" are intended to minimize risk of wildfire ignition, de-energization may cause other damages for which the Western Domestic Utilities could be held liable.
Damage claims against PacifiCorp for the 2020 Wildfires (as defined below) may materially affect PacifiCorp's financial condition and results of operations.
In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and California (the "2020 Wildfires"). The 2020 Wildfires spread over certain parts of PacifiCorp's service territory and surrounding areas in Oregon and California and are 100% contained. Investigations into the cause and origin of each wildfire are complex and ongoing. Although those investigations are not complete, several civil actions (including a putative class action) have been filed in Oregon and California on behalf of citizens and businesses who suffered damages from fires allegedly involving PacifiCorp's equipment. It is possible that additional lawsuits against PacifiCorp may be filed in Oregon or California with respect to the 2020 Wildfires. If PacifiCorp is found liable for damages related to the 2020 Wildfires and is unable to, or believes that it will be unable to, recover those damages through insurance or customer rates, or access the bank and capital markets on reasonable terms, PacifiCorp's financial results could be adversely affected. Refer to PacifiCorp's Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information on the 2020 Wildfires.
Each Registrant's business could be adversely affected by COVID-19 or other pathogens, or similar crises.
Each Registrant's business could be adversely affected by the worldwide outbreak of COVID-19 generally and more specifically in the markets in which we operate, including, without limitation, if each Registrant's utility customers experience decreases in demand for their products and services or otherwise reduce their consumption of electricity or natural gas that the respective Registrant supplies, or if such Registrant experiences material payment defaults by its customers. For example, if the tourism industry in Nevada experiences a significant and extended decrease as a result of changes in customer behavior, demand for electricity sold by Nevada Power and Sierra Pacific could decrease. In addition, each Registrant's results and financial condition may be adversely affected by federal, state or local legislation related to COVID-19 (or other similar laws, regulations, orders or other governmental or regulatory actions) that would impose a moratorium on terminating electric or natural gas utility services, including related assessment of late fees, due to non-payment or other circumstances. Certain Registrants have already temporarily implemented certain of these measures, either voluntarily or in accordance with requirements of the respective Registrant's public utility commissions. These requirements will likely remain for the duration of the COVID-19 pandemic. Additionally, HomeServices' residential real estate brokerage business could experience a decline (which could be significant) in residential property transactions if potential customers elect to defer purchases in reaction to any substantial outbreak, or fear of such outbreak, of COVID-19 or other pathogen, or due to general economic uncertainty such as high unemployment levels, in some or all of the real estate markets in which HomeServices operates. The government and regulators could impose other requirements on each Registrant's business that could have an adverse impact on such Registrant's financial results.
Further, the recent outbreak of COVID-19, or another pathogen, could disrupt supply chains (including supply chains for energy generation, steel or transmission wire) relating to the markets each Registrant serves, which could adversely impact such Registrant's ability to generate or supply power. In addition, such disruptions to the supply chain could delay certain construction and other capital expenditure projects, including construction and repowering of the Registrants' renewable generation projects. Such disruptions could adversely affect the impacted Registrant's future financial results.
Such declines in demand, any inability to generate or supply power or delays in capital projects could also significantly reduce cash flows at BHE's subsidiaries, thereby reducing the availability of distributions to BHE, which could adversely affect its financial results.
Each Registrant is subject to extensive federal, state, local and foreign legislation and regulation, including numerous environmental, health, safety, reliability, data privacy and other laws and regulations that affect its operations and costs. These laws and regulations are complex, dynamic and subject to new interpretations or change. In addition, new laws and regulations, including initiatives regarding deregulation and restructuring of the utility industry, are continually being proposed and enacted that impose new or revised requirements or standards on each Registrant.
Each Registrant is required to comply with numerous federal, state, local and foreign laws and regulations as described in "General Regulation" and "Environmental Laws and Regulations" in Item 1 of this Form 10-K that have broad application to each Registrant and limits the respective Registrant's ability to independently make and implement management decisions regarding, among other items, acquiring businesses; constructing, acquiring, disposing or retiring of operating assets; operating and maintaining generating facilities and transmission and distribution system assets; complying with pipeline safety and integrity and environmental requirements; setting rates charged to customers; establishing capital structures and issuing debt or equity securities; transacting between subsidiaries and affiliates; and paying dividends or similar distributions. These laws and regulations, which are followed in developing the Registrants' safety and compliance programs and procedures, are implemented and enforced by federal, state and local regulatory agencies, such as the Occupational Safety and Health Administration, the FERC, the EPA, the DOT, the NRC, the Federal Mine Safety and Health Administration and various state regulatory commissions in the United States, and foreign regulatory agencies, such as GEMA, which discharges certain of its powers through its staff within Ofgem, in Great Britain and the AUC in Alberta, Canada.
Compliance with applicable laws and regulations generally requires each Registrant to obtain and comply with a wide variety of licenses, permits, inspections, audits and other approvals. Further, compliance with laws and regulations can require significant capital and operating expenditures, including expenditures for new equipment, inspection, cleanup costs, removal and remediation costs and damages arising out of contaminated properties. Compliance activities pursuant to existing or new laws and regulations could be prohibitively expensive or otherwise uneconomical. As a result, each Registrant could be required to shut down some facilities or materially alter its operations. Further, each Registrant may not be able to obtain or maintain all required environmental or other regulatory approvals and permits for its operating assets or development projects. Delays in, or active opposition by third parties to, obtaining any required environmental or regulatory authorizations or failure to comply with the terms and conditions of the authorizations may increase costs or prevent or delay each Registrant from operating its facilities, developing or favorably locating new facilities or expanding existing facilities. If any Registrant fails to comply with any environmental or other regulatory requirements, such Registrant may be subject to penalties and fines or other sanctions, including changes to the way its electricity generating facilities are operated that may adversely impact generation or how the Pipeline Companies are permitted to operate their systems that may adversely impact throughput. The costs of complying with laws and regulations could adversely affect each Registrant's financial results. Not being able to operate existing facilities or develop new generating facilities to meet customer electricity needs could require such Registrant to increase its purchases of electricity on the wholesale market, which could increase market and price risks and adversely affect such Registrant's financial results.
Existing laws and regulations, while comprehensive, are subject to changes and revisions from ongoing policy initiatives by legislators and regulators and to interpretations that may ultimately be resolved by the courts. For example, changes in laws and regulations could result in, but are not limited to, increased competition and decreased revenues within each Registrant's service territories, such as the defeated Nevada Energy Choice Initiative; new environmental requirements, including the implementation of or changes to the Affordable Clean Energy rule, RPS and GHG emissions reduction goals; the issuance of new or stricter air quality standards; the implementation of energy efficiency mandates; the issuance of regulations governing the management and disposal of coal combustion byproducts; changes in forecasting requirements; changes to each Registrant's service territories as a result of condemnation or takeover by municipalities or other governmental entities, particularly where it lacks the exclusive right to serve its customers; the inability of each Registrant to recover its costs on a timely basis, if at all; new pipeline safety requirements; or a negative impact on each Registrant's current cost recovery arrangements. In addition to changes in existing legislation and regulation, new laws and regulations are likely to be enacted from time to time that impose additional or new requirements or standards on each Registrant. Adverse rulings in GHG-related cases could result in increased or changed regulations and could increase costs for GHG emitters, including the Registrants' generating facilities. The GHG rules, changes to those rules, and the Registrants' compliance requirements are subject to potential outcomes from proceedings and litigation challenging the rules.
New federal, regional, state and international accords, legislation, regulation, or judicial proceedings limiting GHG emissions could have a material adverse impact on the Registrants, the United States and the global economy. Companies and industries with higher GHG emissions, such as utilities with significant coal-fueled generating facilities, will be subject to more direct impacts and greater financial and regulatory risks. The impact is dependent on numerous factors, none of which can be meaningfully quantified at this time. These factors include, but are not limited to, the magnitude and timing of GHG emissions reduction requirements; the design of the requirements; the cost, availability and effectiveness of emissions control technology;
the price, distribution method and availability of offsets and allowances used for compliance; government-imposed compliance costs; and the existence and nature of incremental cost recovery mechanisms. Examples of how new requirements may impact the Registrants include:
•Additional costs may be incurred to purchase required emissions allowances under any market-based cap-and-trade system in excess of allocations that are received at no cost. These purchases would be necessary until new technologies could be developed and deployed to reduce emissions or lower carbon generation is available;
•Acquiring and renewing construction and operating permits for new and existing generating facilities may be costly and difficult;
•Additional costs may be incurred to purchase and deploy new generating technologies;
•Costs may be incurred to retire existing coal-fueled generating facilities before the end of their otherwise useful lives or to convert them to burn fuels, such as natural gas or biomass, that result in lower emissions;
•Operating costs may be higher and generating unit outputs may be lower;
•Higher interest and financing costs and reduced access to capital markets may result to the extent that financial markets view climate change and GHG emissions as a greater business risk; and
•The relevant Registrant's natural gas pipeline operations, electric transmission and retail sales may be impacted in response to changes in customer demand and requirements to reduce GHG emissions.
The impact of events or conditions caused by climate change, whether from natural processes or human activities, are uncertain and could vary widely, from highly localized to worldwide, and the extent to which a utility's operations may be affected is uncertain. Climate change may cause physical and financial risk through, among other things, sea level rise, changes in precipitation and extreme weather events. Consumer demand for energy may increase or decrease, based on overall changes in weather and as customers promote lower energy consumption through the continued use of energy efficiency programs or other means. Availability of resources to generate electricity, such as water for hydroelectric production and cooling purposes, may also be impacted by climate change and could influence the Registrants' existing and future electricity generating portfolio. These issues may have a direct impact on the costs of electricity production and increase the price customers pay or their demand for electricity.
Implementing actions required under, and otherwise complying with, new federal and state laws and regulations and changes in existing ones are among the most challenging aspects of managing utility operations. The Registrants cannot accurately predict the type or scope of future laws and regulations that may be enacted, changes in existing ones or new interpretations by agency orders or court decisions, nor can each Registrant determine their impact on it at this time; however, any one of these could adversely affect each Registrant's financial results through higher capital expenditures and operating costs, early closure of generating facilities or lower tax benefits or restrict or otherwise cause an adverse change in how each Registrant operates its business. To the extent that each Registrant is not allowed by its regulators to recover or cannot otherwise recover the costs to comply with new laws and regulations or changes in existing ones, the costs of complying with such additional requirements could have a material adverse effect on the relevant Registrant's financial results. Additionally, even if such costs are recoverable in rates, if they are substantial and result in rates increasing to levels that substantially reduce customer demand, this could have a material adverse effect on the relevant Registrant's financial results.
Recovery of costs and certain activities by each Registrant is subject to regulatory review and approval, and the inability to recover costs or undertake certain activities may adversely affect each Registrant's financial results.
State Regulatory Rate Review Proceedings
The Utilities establish rates for their regulated retail service through state regulatory proceedings. These proceedings typically involve multiple parties, including government bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but generally have the common objective of limiting rate increases or requesting rate decreases while also requiring the Utilities to ensure system reliability. Decisions are subject to judicial appeal, potentially leading to further uncertainty associated with the approval proceedings.
States set retail rates based in part upon the state regulatory commission's acceptance of an allocated share of total utility costs. When states adopt different methods to calculate interjurisdictional cost allocations, some costs may not be incorporated into rates of any state or other jurisdiction. Ratemaking is also generally done on the basis of estimates of normalized costs, so if a given year's realized costs are higher than normalized costs, rates may not be sufficient to cover those costs. In some cases, actual costs are lower than the normalized or estimated costs recovered through rates and from time-to-time may result in a state
regulator requiring refunds to customers. Each state regulatory commission generally sets rates based on a test year established in accordance with that commission's policies. The test year data adopted by each state regulatory commission may create a lag between the incurrence of a cost and its recovery in rates. Each state regulatory commission also decides the allowed levels of expense, investment and capital structure that it deems are prudently incurred in providing the service and may disallow recovery in rates for any costs that it believes do not meet such standard. Additionally, each state regulatory commission establishes the allowed rate of return the Utilities will be given an opportunity to earn on their sources of capital. While rate regulation is premised on providing a fair opportunity to earn a reasonable rate of return on invested capital, the state regulatory commissions do not guarantee that each Registrant will be able to realize the allowed rate of return or recover all of its costs even if it believes such costs to be prudently incurred.
Some state regulatory commissions have authorized recovery of certain costs above the level assumed in establishing base rates through adjustment mechanisms, which may be subject to customer sharing. Any significant increase in fuel costs for electricity generation or purchased electricity costs could have a negative impact on the Utilities, despite efforts to minimize this impact through the use of hedging contracts and adjustment mechanisms or through future general regulatory rate reviews. Any of these consequences could adversely affect each Registrant's financial results.
FERC Jurisdiction
The FERC authorizes cost-based rates associated with transmission services provided by the Utilities' transmission facilities. Under the Federal Power Act, the Utilities, or MISO as it relates to MidAmerican Energy, may voluntarily file, or may be obligated to file, for changes, including general rate changes, to their system-wide transmission service rates. General rate changes implemented may be subject to refund. The FERC also has responsibility for approving both cost- and market-based rates under which the Utilities sell electricity in the wholesale market, has jurisdiction over most of PacifiCorp's hydroelectric generating facilities and has broad jurisdiction over energy markets. The FERC may impose price limitations, bidding rules and other mechanisms to address some of the volatility of these markets or could revoke or restrict the ability of the Utilities to sell electricity at market-based rates, which could adversely affect each Registrant's financial results. The FERC also maintains rules concerning standards of conduct, affiliate restrictions, interlocking directorates and cross-subsidization. As a transmission owning member of MISO, MidAmerican Energy is also subject to MISO-directed modifications of market rules, which are subject to FERC approval and operational procedures. As participants in EIM, PacifiCorp, Nevada Power and Sierra Pacific are also subject to applicable California ISO rules, which are subject to FERC approval and operational procedures. The FERC may also impose substantial civil penalties for any non-compliance with the Federal Power Act and the FERC's rules and orders.
The NERC has standards in place to ensure the reliability of the electric generation system and transmission grid. The Utilities are subject to the NERC's regulations and periodic audits to ensure compliance with those regulations. The NERC may carry out enforcement actions for non-compliance and administer significant financial penalties, subject to the FERC's review.
The FERC has jurisdiction over, among other things, the construction, abandonment, modification and operation of natural gas pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including all rates, charges and terms and conditions of service. The FERC also has market transparency authority and has adopted additional reporting and internet posting requirements for natural gas pipelines and buyers and sellers of natural gas.
Rates for the interstate natural gas transmission and storage operations at the Pipeline Companies, which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for charges, are authorized by the FERC. In accordance with the FERC's rate-making principles, the Pipeline Companies' current maximum tariff rates are designed to recover prudently incurred costs included in their pipeline system's regulatory cost of service that are associated with the construction, operation and maintenance of their pipeline system and to afford the Pipeline Companies an opportunity to earn a reasonable rate of return. Nevertheless, the rates the FERC authorizes the Pipeline Companies to charge their customers may not be sufficient to recover the costs incurred to provide services in any given period. Moreover, from time to time, the FERC may change, alter or refine its policies or methodologies for establishing pipeline rates and terms and conditions of service. In addition, the FERC has the authority under Section 5 of the Natural Gas Act of 1938 ("NGA") to investigate whether a pipeline may be earning more than its allowed rate of return and, when appropriate, to institute proceedings against such pipeline to prospectively reduce rates. Any such proceedings, if instituted, could result in significantly adverse rate decreases.
Under FERC policy, interstate pipelines and their customers may execute contracts at negotiated rates, which may be above or below the maximum tariff rate for that service or the pipeline may agree to provide a discounted rate, which would be a rate between the maximum and minimum tariff rates. In a rate proceeding, rates in these contracts are generally not subject to adjustment. It is possible that the cost to perform services under negotiated or discounted rate contracts will exceed the cost used in the determination of the negotiated or discounted rates, which could result either in losses or lower rates of return for providing such services. Under certain circumstances, FERC policy allows interstate natural gas pipelines to design new
maximum tariff rates to recover such costs in regulatory rate reviews. However, with respect to discounts granted to affiliates, the interstate natural gas pipeline must demonstrate that the discounted rate was necessary in order to meet competition.
GEMA Jurisdiction
The Northern Powergrid Distribution Companies, as Distribution Network Operators ("DNOs") and holders of electricity distribution licenses, are subject to regulation by GEMA. Most of the revenue of a DNO is controlled by a distribution price control formula set out in the electricity distribution license. The price control formula does not directly constrain profits from year-to-year, but is a control on revenue that operates independent of a significant portion of the DNO's actual costs. A resetting of the formula does not require the consent of the DNO, but if a licensee disagrees with a change to its license it can appeal the matter to the United Kingdom's Competition and Markets Authority. GEMA is able to impose financial penalties on DNOs that contravene any of their electricity distribution license duties or certain of their duties under British law, or fail to achieve satisfactory performance of individual standards prescribed by GEMA. Any penalty imposed must be reasonable and may not exceed 10% of the DNO's revenue. During the term of any price control, additional costs have a direct impact on the financial results of the Northern Powergrid Distribution Companies.
AUC Jurisdiction
The AUC is an independent, quasi-judicial agency established by the province of Alberta, Canada, which is responsible for, among other things, approving the tariffs of transmission facility owners, including AltaLink, and distribution utilities, acquisitions of such transmission facility owners or utilities, and construction and operation of new transmission projects in Alberta. The AUC also investigates and rules on regulated rate disputes and system access problems.
The AUC regulates and oversees Alberta's electricity transmission sector with broad authority that may impact many of AltaLink's activities, including its tariffs, rates, construction, operations and financing. The AUC has various core functions in regulating the Alberta electricity transmission sector, including the following:
•regulating and adjudicating issues related to the operation of electric utilities within Alberta;
•processing and approving general tariff applications relating to revenue requirements and rates of return including deemed capital structure for regulated utilities while ensuring that utility rates are just and reasonable and approval of the transmission tariff rates of regulated transmission providers by the AESO, which is the independent transmission system operator in Alberta that controls the operation of AltaLink's transmission system;
•approving the need for new electricity transmission facilities and permits to build and licenses to operate electricity transmission facilities;
•reviewing operations and accounts from electric utilities and conducting on-site inspections to ensure compliance with industry regulations and standards;
•adjudicating enforcement issues including the imposition of administrative penalties that arise when market participants violate the rules of the AESO; and
•collecting, storing, analyzing, appraising and disseminating information to effectively fulfill its duties as an industry regulator.
In addition, AUC approval is required in connection with new energy and regulated utility initiatives in Alberta, amendments to existing approvals and financing proposals by designated utilities.
Physical or cyber attacks, both threatened and actual, could impact each Registrant's operations and could adversely affect its financial results.
Each Registrant relies on technology in virtually all aspects of its business. Like those of many large businesses, certain of the Registrant's technology systems have been subject to computer viruses, malicious codes, unauthorized access, phishing efforts, denial-of-service attacks and other cyber attacks and each Registrant expects to be subject to similar attacks in the future as such attacks become more sophisticated and frequent. A significant disruption or failure of its technology systems by physical or cyber attack could result in service interruptions, safety failures, security events, regulatory compliance failures, an inability to protect information and assets against unauthorized users, and other operational difficulties. Attacks perpetrated against each Registrant's systems could result in loss of assets and critical information and expose it to remediation costs and reputational damage.
Although the Registrants have taken steps intended to mitigate these risks, a significant disruption or cyber intrusion could adversely affect each Registrant's financial results. Cyber attacks could further adversely affect each Registrant's ability to operate facilities, information technology and business systems, or compromise sensitive customer and employee information. In addition, physical or cyber attacks against key suppliers or service providers could have a similar effect on each Registrant. Additionally, if each Registrant is unable to acquire, develop, implement, adopt or protect rights around new technology, it may suffer a competitive disadvantage.
Each Registrant is actively pursuing, developing and constructing new or expanded facilities, the completion and expected costs of which are subject to significant risk, and each Registrant has significant funding needs related to its planned capital expenditures.
Each Registrant actively pursues, develops and constructs new or expanded facilities. Each Registrant expects to incur significant annual capital expenditures over the next several years. Such expenditures may include construction and other costs for new electricity generating facilities, electric transmission or distribution projects, environmental control and compliance systems, natural gas storage facilities, new or expanded pipeline systems, and continued maintenance and upgrades of existing assets.
Development and construction of major facilities are subject to substantial risks, including fluctuations in the price and availability of commodities, manufactured goods, equipment, and the imposition of tariffs thereon when sourced by foreign providers, labor, siting and permitting and changes in environmental and operational compliance matters, load forecasts and other items over a multi-year construction period, as well as counterparty risk and the economic viability of the Registrants' suppliers, customers and contractors. Certain of the Registrants' construction projects are substantially dependent upon a single supplier or contractor and replacement of such supplier or contractor may be difficult and cannot be assured. These risks may result in the inability to timely complete a project or higher than expected costs to complete an asset and place it in-service and, in extreme cases, the loss of the power purchase agreements or other long-term off-take contracts underlying such projects. Such costs may not be recoverable in the regulated rates or market or contract prices each Registrant is able to charge its customers. Delays in construction of renewable projects may result in delayed in-service dates which may result in the loss of anticipated revenue or income tax benefits. It is also possible that additional generation needs may be obtained through power purchase agreements, which could increase long-term purchase obligations and force reliance on the operating performance of a third party. The inability to successfully and timely complete a project, avoid unexpected costs or recover any such costs could adversely affect such Registrant's financial results.
Furthermore, each Registrant depends upon both internal and external sources of liquidity to provide working capital and to fund capital requirements. If BHE does not provide needed funding to its subsidiaries and the subsidiaries are unable to obtain funding from external sources, they may need to postpone or cancel planned capital expenditures.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results.
A significant sustained decrease in demand for electricity or natural gas in the markets served by each Registrant would decrease its operating revenue, could impact its planned capital expenditures and could adversely affect its financial results. Factors that could lead to a decrease in market demand include, among others:
•a depression, recession or other adverse economic condition that results in a lower level of economic activity or reduced spending by consumers on electricity or natural gas;
•an increase in the market price of electricity or natural gas or a decrease in the price of other competing forms of energy;
•shifts in competitively priced natural gas supply sources away from the sources connected to the Pipeline Companies' systems, including shale gas sources;
•efforts by customers, legislators and regulators to reduce the consumption of electricity generated or distributed by each Registrant through various existing laws and regulations, as well as, deregulation, conservation, energy efficiency and private generation measures and programs;
•laws mandating or encouraging renewable energy sources, which may decrease the demand for electricity and natural gas or change the market prices of these commodities;
•higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of natural gas or other fuel sources for electricity generation or that limit the use of natural gas or the generation of electricity from fossil fuels;
•a shift to more energy-efficient or alternative fuel machinery or an improvement in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or lower emissions, price differentials, incentives or otherwise;
•a reduction in the state or federal subsidies or tax incentives that are provided to agricultural, industrial or other customers, or a significant sustained change in prices for commodities such as ethanol or corn for ethanol manufacturers; and
•sustained mild weather that reduces heating or cooling needs.
Each Registrant's operating results may fluctuate on a seasonal and quarterly basis and may be adversely affected by weather.
In most parts of the United States and other markets in which each Registrant operates, demand for electricity peaks during the summer months when irrigation and cooling needs are higher. Market prices for electricity also generally peak at that time. In other areas, including the western portion of PacifiCorp's service territory, demand for electricity peaks during the winter when heating needs are higher. In addition, demand for natural gas and other fuels generally peaks during the winter. This is especially true in MidAmerican Energy's and Sierra Pacific's retail natural gas businesses. Further, extreme weather conditions, such as heat waves, winter storms or floods could cause these seasonal fluctuations to be more pronounced. Periods of low rainfall or snowpack may negatively impact electricity generation at PacifiCorp's hydroelectric generating facilities, which may result in greater purchases of electricity from the wholesale market or from other sources at market prices. Additionally, PacifiCorp and MidAmerican Energy have added substantial wind-powered generating capacity, and BHE's unregulated subsidiaries are adding solar and wind-powered generating capacity, each of which is also a climate-dependent resource.
As a result, the overall financial results of each Registrant may fluctuate substantially on a seasonal and quarterly basis. Each Registrant has historically provided less service, and consequently earned less income, when weather conditions are mild. Unusually mild weather in the future may adversely affect each Registrant's financial results through lower revenue or margins. Conversely, unusually extreme weather conditions could increase each Registrant's costs to provide services and could adversely affect its financial results. The extent of fluctuation in each Registrant's financial results may change depending on a number of factors related to its regulatory environment and contractual agreements, including its ability to recover energy costs, the existence of revenue sharing provisions as it relates to MidAmerican Energy and Nevada Power, and terms of its wholesale sale contracts.
Each Registrant is subject to market risk associated with the wholesale energy markets, which could adversely affect its financial results.
In general, each Registrant's primary market risk is adverse fluctuations in the market price of wholesale electricity and fuel, including natural gas, coal and fuel oil, which is compounded by volumetric changes affecting the availability of or demand for electricity and fuel. The market price of wholesale electricity may be influenced by several factors, such as the adequacy or type of generating capacity, scheduled and unscheduled outages of generating facilities, prices and availability of fuel sources for generation, disruptions or constraints to transmission and distribution facilities, weather conditions, demand for electricity, economic growth and changes in technology. Volumetric changes are caused by fluctuations in generation or changes in customer needs that can be due to the weather, electricity and fuel prices, the economy, regulations or customer behavior. For example, the Utilities purchase electricity and fuel in the open market as part of their normal operating businesses. If market prices rise, especially in a time when larger than expected volumes must be purchased at market prices, the Utilities may incur significantly greater expense than anticipated. Likewise, if electricity market prices decline in a period when the Utilities are a net seller of electricity in the wholesale market, the Utilities could earn less revenue. Although the Utilities have ECAMs, the risks associated with changes in market prices may not be fully mitigated due to customer sharing bands as it relates to PacifiCorp and other factors.
Potential terrorist activities and the impact of military or other actions, could adversely affect each Registrant's financial results.
The ongoing threat of terrorism and the impact of military or other actions by nations or politically, ethnically or religiously motivated organizations regionally or globally may create increased political, economic, social and financial market instability, which could subject each Registrant's operations to increased risks. Additionally, the United States government has issued warnings that energy assets, specifically pipeline, nuclear generation, transmission and other electric utility infrastructure, are potential targets for terrorist attacks. Political, economic, social or financial market instability or damage to or interference with the operating assets of the Registrants, customers or suppliers may result in business interruptions, lost revenue, higher commodity prices, disruption in fuel supplies, lower energy consumption and unstable markets, particularly with respect to
electricity and natural gas, and increased security, repair or other costs, any of which may materially adversely affect each Registrant in ways that cannot be predicted at this time. Any of these risks could materially affect its consolidated financial results. Furthermore, instability in the financial markets as a result of terrorism or war could also materially adversely affect each Registrant's ability to raise capital.
Certain Registrants are subject to the unique risks associated with nuclear generation.
The ownership and operation of nuclear power plants, such as MidAmerican Energy's 25% ownership interest in Quad Cities Station, involves certain risks. These risks include, among other items, mechanical or structural problems, inadequacy or lapses in maintenance protocols, the impairment of reactor operation and safety systems due to human error, the costs of storage, handling and disposal of nuclear materials, compliance with and changes in regulation of nuclear power plants, limitations on the amounts and types of insurance coverage commercially available, and uncertainties with respect to the technological and financial aspects of decommissioning nuclear facilities at the end of their useful lives. Additionally, Exelon Generation, the 75% owner and operator of the facility, may respond to the occurrence of any of these or other risks in a manner that negatively impacts MidAmerican Energy, including closure of Quad Cities Station prior to the expiration of its operating license. The prolonged unavailability, or early closure, of Quad Cities Station due to operational or economic factors could have a materially adverse effect on the relevant Registrant's financial results, particularly when the cost to produce power at the plant is significantly less than market wholesale prices. The following are among the more significant of these risks:
•Operational Risk - Operations at any nuclear power plant could degrade to the point where the plant would have to be shut down. If such degradations were to occur, the process of identifying and correcting the causes of the operational downgrade to return the plant to operation could require significant time and expense, resulting in both lost revenue and increased fuel and purchased electricity costs to meet supply commitments. Rather than incurring substantial costs to restart the plant, the plant could be shut down. Furthermore, a shut-down or failure at any other nuclear power plant could cause regulators to require a shut-down or reduced availability at Quad Cities Station.
In addition, issues relating to the disposal of nuclear waste material, including the availability, unavailability and expense of a permanent repository for spent nuclear fuel could adversely impact operations as well as the cost and ability to decommission nuclear power plants, including Quad Cities Station, in the future.
•Regulatory Risk - The NRC may modify, suspend or revoke licenses and impose civil penalties for failure to comply with applicable Atomic Energy Act regulations or the terms of the licenses of nuclear facilities. Unless extended, the NRC operating licenses for Quad Cities Station will expire in 2032. Changes in regulations by the NRC could require a substantial increase in capital expenditures or result in increased operating or decommissioning costs.
•Nuclear Accident and Catastrophic Risks - Accidents and other unforeseen catastrophic events have occurred at nuclear facilities other than Quad Cities Station, both in the United States and elsewhere, such as at the Fukushima Daiichi nuclear power plant in Japan as a result of the earthquake and tsunami in March 2011. The consequences of an accident or catastrophic event can be severe and include loss of life and property damage. Any resulting liability from a nuclear accident or catastrophic event could exceed the relevant Registrant's resources, including insurance coverage.
Certain of BHE's subsidiaries are subject to the risk that customers will not renew their contracts or that BHE's subsidiaries will be unable to obtain new customers for expanded capacity, each of which could adversely affect its financial results.
If BHE's subsidiaries are unable to renew, remarket, or find replacements for their customer agreements on favorable terms, BHE's subsidiaries' sales volumes and operating revenue would be exposed to reduction and increased volatility. For example, without the benefit of long-term transportation agreements, BHE cannot assure that the Pipeline Companies will be able to transport natural gas at efficient capacity levels. Substantially all of the Pipeline Companies' revenues are generated under transportation, storage and LNG contracts that periodically must be renegotiated and extended or replaced, and the Pipeline Companies are dependent upon relatively few customers for a substantial portion of their revenue. Similarly, without long-term power purchase agreements, BHE cannot assure that its unregulated power generators will be able to operate profitably. Failure to maintain existing long-term agreements or secure new long-term agreements, or being required to discount rates significantly upon renewal or replacement, could adversely affect BHE's consolidated financial results. The replacement of any existing long-term agreements depends on market conditions and other factors that may be beyond BHE's subsidiaries' control.
Each Registrant is subject to counterparty risk, which could adversely affect its financial results.
Each Registrant is subject to counterparty credit risk related to contractual payment obligations with wholesale suppliers and customers. Adverse economic conditions or other events affecting counterparties with whom each Registrant conducts business could impair the ability of these counterparties to meet their payment obligations. Each Registrant depends on these counterparties to remit payments on a timely basis. Each Registrant continues to monitor the creditworthiness of its wholesale suppliers and customers in an attempt to reduce the impact of any potential counterparty default. If strategies used to minimize these risk exposures are ineffective or if any Registrant's wholesale suppliers' or customers' financial condition deteriorates or they otherwise become unable to pay, it could have a significant adverse impact on each Registrant's liquidity and its financial results.
Each Registrant is subject to counterparty performance risk related to performance of contractual obligations by wholesale suppliers, customers and contractors. Each Registrant relies on wholesale suppliers to deliver commodities, primarily natural gas, coal and electricity, in accordance with short- and long-term contracts. Failure or delay by suppliers to provide these commodities pursuant to existing contracts could disrupt the delivery of electricity and require the Utilities to incur additional expenses to meet customer needs. In addition, when these contracts terminate, the Utilities may be unable to purchase the commodities on terms equivalent to the terms of current contracts.
Each Registrant relies on wholesale customers to take delivery of the energy they have committed to purchase. Failure of customers to take delivery may require the relevant Registrant to find other customers to take the energy at lower prices than the original customers committed to pay. If each Registrant's wholesale customers are unable to fulfill their obligations, there may be a significant adverse impact on its financial results.
The Northern Powergrid Distribution Companies' customers are concentrated in a small number of electricity supply businesses with RWE Npower PLC and British Gas Trading Limited accounting for approximately 15% and 12%, respectively, of distribution revenue in 2020. AltaLink's primary source of operating revenue is the AESO. Generally, a single customer purchases the energy from BHE's independent power projects in the United States and the Philippines pursuant to long-term power purchase agreements. For example, certain of BHE Renewables' solar and wind independent power projects sell all of their electrical production to either Pacific Gas and Electric Company or Southern California Edison Company, respectively. Any material payment or other performance failure by the counterparties in these arrangements could have a significant adverse impact on BHE's consolidated financial results.
BHE owns investments and projects in foreign countries that are exposed to risks related to fluctuations in foreign currency exchange rates and increased economic, regulatory and political risks.
BHE's business operations and investments outside the United States increase its risk related to fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar. BHE's principal reporting currency is the United States dollar, and the value of the assets and liabilities, earnings, cash flows and potential distributions from its foreign operations changes with the fluctuations of the currency in which they transact. BHE indirectly owns a hydroelectric power plant in the Philippines and may acquire significant energy-related investments and projects outside of the United States. BHE may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted amounts be settled in, or indexed to, United States dollars or a currency freely convertible into United States dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could negatively affect BHE's consolidated financial results.
In addition to any disruption in the global financial markets, the economic, regulatory and political conditions in some of the countries where BHE has operations or is pursuing investment opportunities may present increased risks related to, among others, inflation, foreign currency exchange rate fluctuations, currency repatriation restrictions, nationalization, renegotiation, privatization, availability of financing on suitable terms, customer creditworthiness, construction delays, business interruption, political instability, civil unrest, guerilla activity, terrorism, pandemics (including potentially in relation to COVID-19), expropriation, trade sanctions, contract nullification and changes in law, regulations or tax policy. BHE may not choose to or be capable of either fully insuring against or effectively hedging these risks.
Poor performance of plan and fund investments and other factors impacting the pension and other postretirement benefit plans and nuclear decommissioning and mine reclamation trust funds could unfavorably impact each Registrant's cash flows, liquidity and financial results.
Costs of providing each Registrant's defined benefit pension and other postretirement benefit plans and costs associated with the joint trustee plan to which PacifiCorp contributes depend upon a number of factors, including the rates of return on plan assets,
the level and nature of benefits provided, discount rates, mortality assumptions, the interest rates used to measure required minimum funding levels, the funded status of the plans, changes in benefit design, tax deductibility and funding limits, changes in laws and government regulation and each Registrant's required or voluntary contributions made to the plans. Furthermore, the timing of recognition of unrecognized gains and losses associated with the Registrants' defined benefit pension plans is subject to volatility due to events that may give rise to settlement accounting. Settlement events resulting from lump sum distributions offered by certain of the Registrants' defined benefit pension plans are influenced by the interest rates used to discount a participant's lump sum distribution. When the applicable interest rates are low, lump sum distributions in a given year tend to increase resulting in a higher likelihood of triggering settlement accounting.
Certain of the Registrant's pension and other postretirement benefit plans are in underfunded positions. Each Registrant may be required to make cash contributions to fund these plans in the future. Additionally, each Registrant's plans have investments in domestic and foreign equity and debt securities and other investments that are subject to loss. Losses from investments could add to the volatility, size and timing of future contributions.
Furthermore, the funded status of the UMWA 1974 Pension Plan multiemployer plan to which PacifiCorp's subsidiary previously contributed is considered critical and declining. PacifiCorp's subsidiary involuntarily withdrew from the UMWA 1974 Pension Plan in June 2015 when the UMWA employees ceased performing work for the subsidiary. PacifiCorp has recorded its best estimate of the withdrawal obligation.
In addition, MidAmerican Energy is required to fund over time the projected costs of decommissioning Quad Cities Station, a nuclear power plant, and Bridger Coal Company, a joint venture of PacifiCorp's subsidiary, Pacific Minerals, Inc., is required to fund projected mine reclamation costs. The funds that MidAmerican Energy has invested in a nuclear decommissioning trust and a subsidiary of PacifiCorp has invested in a mine reclamation trust are invested in debt and equity securities and poor performance of these investments will reduce the amount of funds available for their intended purpose, which could require MidAmerican Energy or PacifiCorp's subsidiary to make additional cash contributions. As contributions to the trust are being made over the operating life of the respective facility, reductions in the expected operating life of the facility could also require MidAmerican Energy and PacifiCorp's subsidiary to make additional contributions to the related trust. Such cash funding obligations, which are also impacted by the other factors described above, could have a material impact on MidAmerican Energy's or PacifiCorp's liquidity by reducing their available cash.
Inflation and changes in commodity prices and fuel transportation costs may adversely affect each Registrant's financial results.
Inflation and increases in commodity prices and fuel transportation costs may affect each Registrant by increasing both operating and capital costs. As a result of existing rate agreements, contractual arrangements or competitive price pressures, each Registrant may not be able to pass the costs of inflation on to its customers. If each Registrant is unable to manage cost increases or pass them on to its customers, its financial results could be adversely affected.
Cyclical fluctuations and competition in the residential real estate brokerage and mortgage businesses could adversely affect HomeServices.
The residential real estate brokerage and mortgage industries tend to experience cycles of greater and lesser activity and profitability and are typically affected by changes in economic conditions, which are beyond HomeServices' control. Any of the following, among others, are examples of items that could have a material adverse effect on HomeServices' businesses by causing a general decline in the number of home sales, sale prices or the number of home financings which, in turn, would adversely affect its financial results:
•rising interest rates or unemployment rates, including a sustained high unemployment rate in the United States;
•periods of economic slowdown or recession in the markets served or the adverse effects on market actions as a result of the actual or potential spread of COVID-19;
•decreasing home affordability;
•lack of available mortgage credit for potential homebuyers, such as the reduced availability of credit, which may continue into future periods;
•inadequate home inventory levels;
•sources of new competition; and
•changes in applicable tax law.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant.
Disruptions in the financial markets could affect each Registrant's ability to obtain debt financing or to draw upon or renew existing credit facilities and have other adverse effects on each Registrant. Significant dislocations and liquidity disruptions in the United States, Great Britain, Canada and global credit markets, such as those that occurred in 2008 and 2009, may materially impact liquidity in the bank and debt capital markets, making financing terms less attractive for borrowers that are able to find financing and, in other cases, may cause certain types of debt financing, or any financing, to be unavailable. Additionally, economic uncertainty in the United States or globally may adversely affect the United States' credit markets and could negatively impact each Registrant's ability to access funds on favorable terms or at all. If a Registrant is unable to access the bank and debt markets to meet liquidity and capital expenditure needs, it may adversely affect the timing and amount of its capital expenditures, acquisition financing and its financial results.
Potential changes in accounting standards may impact each Registrant's financial results and disclosures in the future, which may change the way analysts measure each Registrant's business or financial performance.
The Financial Accounting Standards Board ("FASB") and the SEC continuously make changes to accounting standards and disclosure and other financial reporting requirements. New or revised accounting standards and requirements issued by the FASB or the SEC or new accounting orders issued by the FERC could significantly impact each Registrant's financial results and disclosures. For example, beginning in 2018 all changes in the fair values of equity securities (whether realized or unrealized) are recognized as gains or losses in the relevant Registrant's financial statements. Accordingly, periodic changes in such Registrant's reported net income will likely be subject to significant variability.
Each Registrant is involved in a variety of legal proceedings, the outcomes of which are uncertain and could adversely affect its financial results.
Each Registrant is, and in the future may become, a party to a variety of legal proceedings. Litigation is subject to many uncertainties, and the Registrants cannot predict the outcome of individual matters with certainty. It is possible that the final resolution of some of the matters in which each Registrant is involved could result in additional material payments substantially in excess of established liabilities or in terms that could require each Registrant to change business practices and procedures or divest ownership of assets. Further, litigation could result in the imposition of financial penalties or injunctions and adverse regulatory consequences, any of which could limit each Registrant's ability to take certain desired actions or the denial of needed permits, licenses or regulatory authority to conduct its business, including the siting or permitting of facilities. Any of these outcomes could have a material adverse effect on such Registrant's financial results.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
Each Registrant's energy properties consist of the physical assets necessary to support its electricity and natural gas businesses. Properties of the relevant Registrant's electricity businesses include electric generation, transmission and distribution facilities, as well as coal mining assets that support certain of PacifiCorp's electric generating facilities. Properties of the relevant Registrant's natural gas businesses include natural gas distribution facilities, interstate pipelines, storage facilities, liquefied natural gas facilities, compressor stations and meter stations. The transmission and distribution assets are primarily within each Registrant's service territories. In addition to these physical assets, the Registrants have rights-of-way, mineral rights and water rights that enable each Registrant to utilize its facilities. It is the opinion of each Registrant's management that the principal depreciable properties owned by it are in good operating condition and are well maintained. Pursuant to separate financing agreements, substantially all of PacifiCorp's electric utility properties, MidAmerican Energy's electric utility properties in the state of Iowa, Nevada Power's and Sierra Pacific's properties in the state of Nevada, AltaLink's transmission properties and substantially all of the assets of the subsidiaries of BHE Renewables that are direct or indirect owners of generation projects are pledged or encumbered to support or otherwise provide the security for the related subsidiary debt. For additional information regarding each Registrant's energy properties, refer to Item 1 of this Form 10-K and Notes 4, 5 and 22 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Financial Statements of MidAmerican Energy in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Nevada Power in Item 8 of this Form 10-K, Notes 3 and 4 of the Notes to Consolidated Financial Statements of Sierra Pacific in Item 8 of this Form 10-K and Notes 4 and 5 of the Notes to Consolidated Financial Statements of Eastern Energy Gas in Item 8 of this Form 10-K.
The following table summarizes Berkshire Hathaway Energy's operating electric generating facilities as of December 31, 2020:
Additionally, as of December 31, 2020 the Company has electric generating facilities that are under construction in Iowa, Wyoming and Montana having total Facility Net Capacity and Net Owned Capacity of 603 MWs.
The right to construct and operate each Registrant's electric transmission and distribution facilities and interstate natural gas pipelines across certain property was obtained in most circumstances through negotiations and, where necessary, through prescription, eminent domain or similar rights. PacifiCorp, MidAmerican Energy, Nevada Power, Sierra Pacific, BHE GT&S, Northern Natural Gas and Kern River in the United States; Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc in Great Britain; and AltaLink in Alberta, Canada continue to have the power of eminent domain or similar rights in each of the jurisdictions in which they operate their respective facilities, but the United States and Canadian utilities do not have the power of eminent domain with respect to governmental, Native American or Canadian First Nations' tribal lands. Although the main Kern River pipeline crosses the Moapa Indian Reservation, all facilities in the Moapa Indian Reservation are located within a utility corridor that is reserved to the United States Department of Interior, Bureau of Land Management.
With respect to real property, each of the electric transmission and distribution facilities and interstate natural gas pipelines fall into two basic categories: (1) parcels that are owned in fee, such as certain of the electric generating facilities, electric substations, natural gas compressor stations, natural gas meter stations and office sites; and (2) parcels where the interest derives from leases, easements (including prescriptive easements), rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for the construction, operation and maintenance of the electric transmission and distribution facilities and interstate natural gas pipelines. Each Registrant believes it has satisfactory title or interest to all of the real property making up their respective facilities in all material respects.
Item 3.
Item 3. Legal Proceedings
PacifiCorp
On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et. al. vs. PacifiCorp, Case No. 20cv33885, Circuit Court, Multnomah County, Oregon. The complaint was filed on behalf of certain named Oregon residents and businesses and all Oregon citizens and entities whose real or personal property was harmed by wildfires in Oregon beginning on or after September 7, 2020. The complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The complaint was amended November 2, 2020 to seek the following damages: (i) damages for real and personal property and other economic losses in excess of $600 million; (ii) double the amount of property and economic damages based on alleged gross negligence; (iii) treble damages for specific costs associated with loss of timber, trees and shrubbery; (iv) double the damages for the costs of litigation and reforestation; and (v) prejudgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint to allege claims for punitive damages. Other individual lawsuits alleging similar claims have been filed in Oregon related to the 2020 wildfires. Investigations as to the cause and origin of the wildfires are ongoing.
For more information regarding certain legal proceedings affecting PacifiCorp, refer to Note 14 of the Notes to Consolidated Financial Statements of PacifiCorp in Part II, Item 8 of this Form 10-K.
Item 4.
Item 4. Mine Safety Disclosures
Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Reform Act is included in Exhibit 95 to this Form 10-K.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
BERKSHIRE HATHAWAY ENERGY
BHE's common stock is beneficially owned by Berkshire Hathaway, Mr. Walter Scott, Jr., a member of BHE's Board of Directors (along with his family members and related or affiliated entities) and Mr. Gregory E. Abel, BHE's Chairman, and has not been registered with the SEC pursuant to the Securities Act of 1933, as amended, listed on a stock exchange or otherwise publicly held or traded. BHE has not declared or paid any cash dividends to its common shareholders since Berkshire Hathaway acquired an equity ownership interest in BHE in March 2000 and does not presently anticipate that it will declare any dividends on its common stock in the foreseeable future.
PACIFICORP
All common stock of PacifiCorp is held by its parent company, PPW Holdings LLC, which is a direct, wholly owned subsidiary of BHE. PacifiCorp declared and paid dividends to PPW Holdings LLC of $- million in 2020 and $175 million in 2019.
MIDAMERICAN FUNDING AND MIDAMERICAN ENERGY
All common stock of MidAmerican Energy is held by its parent company, MHC, which is a direct, wholly owned subsidiary of MidAmerican Funding. MidAmerican Funding is an Iowa limited liability company whose membership interest is held solely by BHE. Neither MidAmerican Funding nor MidAmerican Energy declared or paid any cash distributions or dividends to its sole member or shareholder in 2020 and 2019.
NEVADA POWER
All common stock of Nevada Power is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Nevada Power declared and paid dividends to NV Energy of $155 million in 2020 and $371 million in 2019.
SIERRA PACIFIC
All common stock of Sierra Pacific is held by its parent company, NV Energy, which is an indirect, wholly owned subsidiary of BHE. Sierra Pacific declared and paid dividends to NV Energy of $20 million in 2020 and $46 million in 2019.
EASTERN ENERGY GAS
Eastern Energy Gas is a Virginia limited liability corporation whose membership interest is held solely by its parent company, BHE GT&S, which is an indirect, wholly owned subsidiary of BHE. Eastern Energy Gas did not declare or pay cash distributions to BHE GT&S in 2020. Eastern Energy Gas declared and paid cash distributions to DEI of $4.3 billion in 2020 and $457 million in 2019.
Item 6.
Item 6. Selected Financial Data
Information required by Item 6 is omitted pursuant to General Instruction I(2)(a) to Form 10-K.
Item 7.
Item 7. 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 Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical Financial Statements and Notes to Financial Statements each in Item 8 of this Form 10-K. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.
Results of Operations
Overview
MidAmerican Energy -
MidAmerican Energy's net income for 2020 was $826 million, an increase of $33 million, or 4%, compared to 2019 primarily due to a higher income tax benefit of $199 million from higher PTCs recognized of $132 million, lower pretax income of $166 million and the effects of ratemaking, and lower operations and maintenance expenses, partially offset by higher depreciation and amortization expense of $77 million, lower allowances for equity and borrowed funds used during construction of $45 million, higher interest expense of $23 million and lower electric and natural gas utility margins. Higher PTCs recognized were due to greater wind-powered generation driven primarily by repowering and new wind projects placed in-service in 2019. Depreciation and amortization expense increased due to additional assets placed in-service in 2019 and 2020, partially offset by $23 million of lower Iowa revenue sharing accruals. Electric utility margin decreased due to lower wholesale revenue and the price impacts from changes in retail sales mix, partially offset by lower generation costs from higher wind generation, higher retail customer volumes and higher recoveries related to the ratemaking treatment of 2017 Tax Reform. Electric retail customer volumes increased 1.2% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased primarily due to 10.2% lower retail customer volumes mainly from the unfavorable impact of weather.
MidAmerican Energy's net income for 2019 was $793 million, an increase of $111 million, or 16%, compared to 2018 due to a higher income tax benefit of $116 million from higher PTCs of $70 million and the effects of ratemaking, higher electric utility margin of $42 million, higher allowances for equity and borrowed funds of $32 million and higher investment earnings of $20 million, partially offset by higher interest expense of $54 million and higher depreciation and amortization expense of $30 million due to wind-powered generation and other plant placed in-service offset by $46 million of lower Iowa revenue sharing. Electric utility margin increased due to lower fuel costs from higher wind generation, higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax benefit) and higher retail customer volumes. Electric retail customer volumes increased 1.4% as an increase in industrial volumes of 4.0% was largely offset by lower residential volumes from the less favorable impact of weather and lower overall customer usage.
MidAmerican Funding -
MidAmerican Funding's net income for 2020 was $818 million, an increase of $37 million, or 5%, compared to 2019. MidAmerican Funding's net income for 2019 was $781 million, an increase of $112 million, or 17%, compared to 2018. The increases 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 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 expenses 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 directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income for the years ended December 31 (in millions):
* Not meaningful.
Electric Utility Margin
A comparison of key operating results related to electric utility margin is as follows for the years ended December 31:
(1) GWh amounts are net of energy used by the related generating facilities.
(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.
(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.
Natural Gas Utility Margin
A comparison of key operating results related to natural gas utility margin is as follows for the years ended December 31:
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
MidAmerican Energy -
Electric utility margin decreased $38 million for 2020 compared to 2019 primarily due to:
(1) Lower wholesale utility margin of $60 million due to lower market prices, partially offset by lower energy costs and higher sales volumes;
(2) Higher retail utility margin of $18 million due to -
•an increase of $23 million from non-weather-related factors, net of price impacts from sales mix, including increased usage for certain industrial customers and the impacts of COVID-19, which generally resulted in lower commercial and industrial customer usage and higher residential customer usage;
•an increase of $1 million, net of energy costs, from higher recoveries through bill riders, primarily related to lower refunds related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and higher transmission cost recoveries (offset in operations and maintenance expense), substantially offset by a decrease of $28 million in electric energy efficiency program revenue (offset in operations and maintenance expense) and the PTC component of the energy adjustment clause (offset in income tax benefit);
•a decrease of $3 million from the impact of weather; and
•a decrease of $3 million from various other revenue; and
(3) Higher Multi-Value Projects ("MVP") transmission revenue of $4 million.
Natural gas utility margin decreased $19 million for 2020 compared to 2019 primarily due to:
(1) A decrease of $10 million in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
(2) A decrease of $9 million from the unfavorable impact of weather in the first quarter.
Operations and maintenance decreased $46 million for 2020 compared to 2019 primarily due to lower energy efficiency program expense of $38 million (offset in operating revenue), lower fossil-fueled generation maintenance of $14 million, lower natural gas distribution expenses of $10 million, lower electric distribution operations expenses of $7 million, a nuclear property insurance premium refund of $5 million and decreases in benefit plan service costs and healthcare and other administrative costs, partially offset by higher wind-powered generation expenses of $21 million due to new and repowered wind-powered generating facilities placed in-service in 2019 and easements, higher electric distribution maintenance expenses of $13 million largely driven by storm restoration related to a significant wind storm in August 2020 and higher transmission operations costs from MISO of $5 million (offset in operating revenue).
Depreciation and amortization increased $77 million for 2020 compared to 2019 primarily due to $95 million related to new and repowered wind-powered generating facilities and other plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $23 million.
Property and other taxes increased $9 million for 2020 compared to 2019 due to higher wind turbine property taxes and other real estate taxes.
Interest expense increased $23 million for 2020 compared to 2019 primarily due to higher average long-term debt balances.
Allowance for borrowed and equity funds decreased $45 million for 2020 compared to 2019 primarily due to lower construction work-in-progress balances related to new and repowered wind-powered generation projects.
Other, net increased $2 million for 2020 compared to 2019 primarily due to lower non-service costs of postretirement employee benefit plans and a gain from the contribution of land to a joint venture in 2020, partially offset by lower interest income due to an unfavorable cash position and lower cash surrender values of corporate-owned life insurance policies.
Income tax benefit increased $199 million for 2020 compared to 2019, and the effective tax rate was (223)% for 2020 and (88)% for 2019. The change in the effective tax rate was substantially due to an increase of $132 million in PTCs, state income tax impacts, the effects of ratemaking and lower pretax income in 2020.
Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a prescribed per-kilowatt rate pursuant to the applicable federal income tax law and are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in service. Beginning in late 2014, some of MidAmerican Energy's wind-powered generating facilities surpassed the 10-year eligibility period for earning the credits. Most of those facilities have since been repowered, and under Internal Revenue Service rules, qualifying repowered facilities are eligible for the credits, or a portion thereof, for 10 years from the date they are returned to service. Refer to "Capital Expenditures" in Liquidity and Capital Resources for additional information about repowering and new wind-powered generation placed in-service. A credit per kilowatt hour of $0.025 for 2020 and 2019 and $0.024 for 2018 was applied to the annual production of eligible facilities, which resulted in $510 million, $378 million and $308 million, respectively, in PTCs.
MidAmerican Funding -
Income tax benefit for MidAmerican Funding increased $197 million for 2020 compared to 2019, and the effective tax rate was (235)% for 2020 and (93)% for 2019. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
MidAmerican Energy -
Electric utility margin increased $42 million for 2019 compared to 2018 primarily due to:
(1) Higher retail utility margin of $36 million due to -
•an increase of $38 million, net of energy costs, from higher recoveries through bill riders, primarily related to the PTC component of the energy adjustment clause and ratemaking treatment for the impact of 2017 Tax Reform (both offset in income tax benefit), partially offset by a decrease of $49 million in electric energy efficiency program revenue (offset in operations and maintenance expense);
•an increase of $19 million from non-weather-related factors, net of price impacts from sales mix, including higher industrial customer usage, partially offset by lower residential customer usage;
•a decrease of $3 million from various other revenue; and
•a decrease of $18 million from the impact of weather;
(2) Higher wholesale utility margin of $5 million due to higher margin per unit reflecting lower energy costs, partially offset by lower sales volumes; and
(3) Higher MVP transmission revenue of $1 million.
Natural gas utility margin decreased $24 million for 2019 compared to 2018 primarily due to:
(1) A decrease of $27 million in natural gas energy efficiency program revenue (offset in operations and maintenance expense); and
(2) An increase of $2 million from higher retail sales volumes due primarily to the impact of colder winter temperatures.
Operations and maintenance decreased $11 million for 2019 compared to 2018 due to lower energy efficiency program expense of $76 million (offset in operating revenue) and lower fossil-fueled generation maintenance of $9 million, partially offset by higher wind-powered generation costs of $37 million, primarily due to new and repowered wind-powered generating facilities, higher natural gas and electric distribution operations costs of $11 million, higher transmission operations costs from MISO of $7 million (offset in operating revenue), and higher healthcare and other operations costs.
Depreciation and amortization increased $30 million for 2019 compared to 2018 due to $78 million related to new and repowered wind-powered generating facilities and other plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $46 million.
Interest expense increased $54 million for 2019 compared to 2018 primarily due to higher average long-term debt balances.
Allowance for borrowed and equity funds increased $32 million for 2019 compared to 2018 primarily due to higher construction work-in-progress balances related to new and repowered wind-powered generation projects.
Other, net increased $20 million for 2019 compared to 2018 primarily due to higher returns on corporate-owned life insurance policies and higher interest income due to a favorable cash position.
Income tax benefit increased $116 million for 2019 compared to 2018, and the effective tax rate was (88)% for 2019 and (60)% for 2018. The change in the effective tax rate was substantially due to an increase of $70 million in PTCs, state income tax impacts and the effects of ratemaking.
MidAmerican Funding -
Income tax benefit for MidAmerican Funding increased $115 million for 2019 compared to 2018, and the effective tax rate was (93)% for 2019 and (64)% for 2018. The change in effective tax rates was due principally to the factors discussed for MidAmerican Energy.
Liquidity and Capital Resources
As of December 31, 2020, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):
Operating Activities
MidAmerican Energy's net cash flows from operating activities were $1,543 million, $1,490 million and $1,508 million for 2020, 2019 and 2018, respectively. MidAmerican Funding's net cash flows from operating activities were $1,536 million, $1,475 million and $1,516 million for 2020, 2019 and 2018, respectively. Cash flows from operating activities increased for 2020 compared to 2019 primarily due to higher income tax receipts and lower payments to vendors, partially offset by higher payments for the settlement of AROs, lower cash margins for MidAmerican Energy's regulated electric and natural gas businesses and higher interest payments due to long-term debt issued in October 2019. Cash flows from operating activities decreased for 2019 compared to 2018 primarily due to lower income tax receipts and higher interest payments, partially offset by lower payments to vendors and lower payments for the settlement of AROs.
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.
In February 2021, the central United States experienced extreme cold temperatures, causing increased demand for natural gas by MidAmerican Energy's customers. While MidAmerican Energy was able to meet such demand without any significant interruptions to service, commodity prices for natural gas purchases were significantly higher than historical experience. The increased commodity prices are expected to result in greater short-term borrowing to fund such purchases until amounts are collected from customers via the PGAs. MidAmerican Energy believes it has adequate liquidity to meet the anticipated increase in short-term borrowing. While the increased costs are expected to be fully recoverable from customers, the timing of recovery may depend upon possible actions taken by MidAmerican Energy's regulators.
Investing Activities
MidAmerican Energy's net cash flows from investing activities were $(1,826) million, $(2,801) million and $(2,310) million for 2020, 2019 and 2018, respectively. MidAmerican Funding's net cash flows from investing activities were $(1,825) million, $(2,801) million and $(2,310) million for 2020, 2019 and 2018, 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 primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust, and other investment proceeds relates primarily to company-owned life insurance policies. In 2018, proceeds from sales of other investments includes $15 million for the transfer of corporate aircraft to BHE.
Financing Activities
MidAmerican Energy's net cash flows from financing activities were $(2) million, $1,585 million and $576 million for 2020, 2019 and 2018, respectively. MidAmerican Funding's net cash flows from financing activities were $4 million, $1,600 million and $569 million for 2020, 2019 and 2018, respectively. In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due April 2029 and $900 million of its 4.25% First Mortgage Bonds due July 2049, and in October 2019, issued an additional $250 million of its 3.65% First Mortgage Bonds due April 2029 and $600 million of its 3.15% First Mortgage Bonds due April 2050. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. In February 2018, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due August 2048 and, in March 2018, repaid $350 million of its 5.30% Senior Notes due March 2018. Net (repayments of) proceeds from short-term debt relate to MidAmerican Energy's use of short-term borrowings through its commercial paper program. MidAmerican Funding received $5 million and $15 million in 2020 and 2019, respectively, and made payments totaling $8 million in 2018 through its note payable with BHE.
Debt Authorizations and Related Matters
MidAmerican Energy has authority from the FERC to issue through April 2, 2022, commercial paper and bank notes aggregating $1.5 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points. MidAmerican Energy has a $900 million unsecured credit facility expiring in June 2022. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. MidAmerican Energy has a $600 million unsecured credit facility, which expires in May 2021, with an option to extend for up to three months, and has a variable interest rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
MidAmerican Energy currently has an effective automatic registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021. Additionally, MidAmerican Energy has authorization from the FERC to issue, through June 30, 2021, long-term debt securities up to an aggregate of $850 million at interest rates not to exceed the applicable United States Treasury rate plus a spread of 175 basis points and preferred stock up to an aggregate of $500 million and from the ICC to issue long-term debt securities up to an aggregate of $850 million through August 20, 2022.
MidAmerican Funding or one of its subsidiaries, including MidAmerican Energy, may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by MidAmerican Funding or one of its subsidiaries may be reissued or resold by MidAmerican Funding or one of its subsidiaries from time to time and will depend on prevailing market conditions, the issuing company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
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 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, for the years ended December 31 are as follows (in millions):
MidAmerican Energy's capital expenditures provided above consist of the following:
•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.
◦Construction and acquisition of wind-powered generating facilities totaled $848 million for 2020, $1,486 million for 2019 and $1,261 million for 2018. MidAmerican Energy placed in-service 729 MWs (nominal ratings) during 2020, including the acquisition of an existing 80-MW wind farm, 1,019 MWs (nominal ratings) during 2019 and 817 MWs (nominal ratings) during 2018. Wind XI, a 2,000-MW project, was completed in January 2020. Wind XII, a 592-MW project, was placed in-service in 2019 and 2020. MidAmerican Energy had three other wind-powered generation projects under construction in 2020 that totaled 319 MWs, including facilities placed in-service in 2020 and the remainder expected to be placed in-service in early 2021. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates.
MidAmerican Energy is currently planning to construct 483 MWs of additional wind-powered generating facilities, for which the related projects are at varying stages of development. Planned spending for those projects totals $461 million for 2021, $16 million for 2022 and $421 million for 2023.
◦Repowering of wind-powered generating facilities totaled $37 million for 2020, $369 million for 2019 and $422 million for 2018. Planned spending for repowering totals $409 million in 2021 and $673 million in 2022. MidAmerican Energy expects its repowered facilities to meet IRS 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. Below is a summary of historical and forecast wind-powered generation repowering projects:
(1) Capacity values for historical repowered facilities reflect new nominal ratings and for forecast projects reflect existing nominal ratings.
•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.
•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.
•Solar reflects MidAmerican Energy's current plan to construct 767 MWs of small- and utility-scale solar generation, for which the related projects are in varying stages of development.
•Remaining expenditures primarily relate to routine projects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.
Contractual Obligations
MidAmerican Energy and MidAmerican Funding have contractual cash obligations that may affect their financial condition. The following table summarizes the material contractual cash obligations of MidAmerican Energy and MidAmerican Funding as of December 31, 2020 (in millions):
(1)Not reflected on the Consolidated Balance Sheets.
(2)Includes interest payments for tax-exempt bond obligations with interest rates scheduled to reset periodically prior to maturity. Future variable interest rates are assumed to equal December 31, 2020 rates.
MidAmerican Energy has other types of commitments that relate primarily to construction expenditures (in "Capital Expenditures" section above) and AROs beyond 2020 (Note 11), which have not been included in the above table because the amount or timing of the cash payments is not certain. Refer to Notes 8, 11 and 13 in Notes to Financial Statements in Item 8 of this Form 10-K for additional information.
Regulatory Matters
MidAmerican Energy is subject to comprehensive regulation. Refer to the discussion contained in Item 1 of this Form 10-K for further information regarding MidAmerican Energy's general regulatory framework and current regulatory matters.
COVID-19
In March 2020, COVID-19 was declared a global pandemic, and containment and mitigation measures were recommended worldwide, which has had an unprecedented impact on society in general and many of the customers served by MidAmerican Energy. While COVID-19 has impacted MidAmerican Energy's financial results and operations through December 31, 2020, the impacts have not been material. However, more severe impacts may still occur that could adversely affect future financial results depending on the duration and extent of COVID-19. The states in which MidAmerican Energy operates have moved to varying phases of recovery plans with most businesses opening subject to certain operating restrictions. As the impacts of COVID-19 and related customer and governmental responses remain uncertain, including the duration of restrictions on business openings, reductions in the consumption of electricity or natural gas may continue to occur, particularly in the commercial and industrial classes. Due to regulatory requirements and voluntary actions taken by MidAmerican Energy related to customer collection activity and suspension of disconnections for non-payment, MidAmerican Energy has seen delays and reductions in cash receipts from retail customers related to the impacts of COVID-19, which could result in higher than normal bad debt write-offs. The amount of such reductions in cash receipts through December 2020 has not been material compared to the same period in 2019, but uncertainty remains. Regulatory jurisdictions may allow for recovery of certain costs incurred in responding to COVID-19. Refer to "Regulatory Matters" in Item 1 of this Form 10-K for further discussion.
MidAmerican Energy's business has been deemed essential and its employees have been identified as "critical infrastructure employees" allowing them to move within communities and across jurisdictional boundaries as necessary to maintain its electric generation, transmission and distribution system and its natural gas distribution system. In response to the effects of COVID-19, MidAmerican Energy has implemented its business continuity plan to protect its employees and customers. Such plans include a variety of actions, including situational use of personal protective equipment by employees when interacting with customers and implementing practices to enhance social distancing at the workplace. Such practices have included work-from-home, staggered work schedules, rotational work location assignments, increased cleaning and sanitation of work spaces and providing general health reminders intended to help lower the risk of spreading COVID-19.
Quad Cities Generating Station Operating Status
Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase ZECs and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.
The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.
On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a compliance filing on March 18, 2020, wherein the PJM proposes 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 it submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.
On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services, which will then be used in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the new revenue projection methodology, and the timing for commencing the capacity auction schedule.
Exelon Generation is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be removed from PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of Quad Cities Station.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. In addition to imposing continuing compliance obligations, 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. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
Refer to "Environmental Laws and Regulations" in Item 1 of this Form 10-K for additional information regarding environmental laws and regulations.
Collateral and Contingent Features
Debt securities of MidAmerican Energy are rated by credit rating agencies. Assigned credit ratings are based on each rating agency's assessment of MidAmerican Energy's ability to, in general, meet the obligations of its issued debt securities. The credit ratings are not a recommendation to buy, sell or hold securities, and there is no assurance that a particular credit rating will continue for any given period of time. As of December 31, 2020, MidAmerican Energy'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. As a result of the issuance of first mortgage bonds by MidAmerican Energy in September 2013, its then outstanding senior unsecured debt was equally and ratably secured with such first mortgage bonds. Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements in Item 8 of this Form 10-K for a discussion of MidAmerican Energy's first mortgage bonds.
MidAmerican Funding and MidAmerican Energy have no credit rating downgrade triggers that would accelerate the maturity dates of its outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. MidAmerican Energy's unsecured revolving credit facilities do not require the maintenance of a minimum credit rating level in order to draw upon their availability. However, commitment fees and interest rates under the credit facilities are tied to credit ratings and increase or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base MidAmerican Energy's collateral requirements on its 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," or in some cases terminate the contract, in the event of a material adverse change in MidAmerican Energy's creditworthiness. These rights can vary by contract and by counterparty. If all credit-risk-related contingent features or adequate assurance provisions for these agreements had been triggered as of December 31, 2020, MidAmerican Energy would have been required to post $87 million of additional collateral. MidAmerican Energy's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
Inflation
Historically, overall inflation and changing prices in the economies where MidAmerican Energy operates have not had a significant impact on its financial results. MidAmerican Energy operates under cost-of-service based rate structures administered by various state commissions and the FERC. Under these rate structures, MidAmerican Energy is allowed to include prudent costs in its rates, including the impact of inflation. MidAmerican Energy attempts to minimize the potential impact of inflation on its operations through the use of fuel, energy and other cost adjustment clauses and bill riders, by employing prudent risk management and hedging strategies and by considering, among other areas, inflation's impact on purchases of energy, operating expenses, materials and equipment costs, contract negotiations, future capital spending programs, and long-term debt issuances. There can be no assurance that such actions will be successful.
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. The following critical accounting estimates are impacted significantly by MidAmerican Energy's methods, judgments and assumptions used in the preparation of the Financial Statements and should be read in conjunction with MidAmerican Energy's Summary of Significant Accounting Policies included in Note 2 of Notes to Financial Statements in Item 8 of this Form 10-K.
Accounting for the Effects of Certain Types of Regulation
MidAmerican Energy prepares its financial statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, MidAmerican Energy defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
MidAmerican Energy continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition, that could limit MidAmerican Energy's ability to recover its costs. MidAmerican Energy believes the application of the guidance for regulated operations is appropriate, and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as AOCI. Total regulatory assets were $392 million and total regulatory liabilities were $1,111 million as of December 31, 2020. Refer to Note 5 of Notes to Financial Statements in Item 8 of this Form 10-K for additional information regarding regulatory assets and liabilities.
Income Taxes
In determining MidAmerican Funding's and MidAmerican Energy's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by MidAmerican Energy's various regulatory commissions. MidAmerican Funding's and MidAmerican Energy's income tax returns are subject to continuous examinations by federal, state and local tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. MidAmerican Funding and MidAmerican Energy recognize the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of their federal, state and local tax examinations is uncertain, each company believes it has made adequate provisions for its income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on its consolidated financial results. Refer to Note 9 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for additional information regarding income taxes.
It is probable that MidAmerican Energy will pass income tax benefits and expense related to the federal tax rate change from 35% to 21% as a result of 2017 Tax Reform, certain property-related basis differences and other various differences on to its customers in certain state jurisdictions. As of December 31, 2020, these amounts were recognized as a net regulatory liability of $263 million and will be included in regulated rates when the temporary differences reverse.
Impairment of Goodwill
MidAmerican Funding's Consolidated Balance Sheet as of December 31, 2020, includes goodwill from the acquisition of MHC totaling $1.3 billion. Goodwill is allocated to each reporting unit. MidAmerican Funding evaluates goodwill for impairment at least annually and completed its annual review as of October 31. Additionally, no indicators of impairment were identified as of December 31, 2020. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. MidAmerican Funding uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. Estimated future cash flows are impacted by, among other factors, growth rates, changes in regulations and rates, ability to renew contracts and estimates of future commodity prices. In estimating future cash flows, MidAmerican Funding incorporates current market information, as well as historical factors.
Pension and Other Postretirement Benefits
MidAmerican Energy sponsors defined benefit pension and other postretirement benefit plans that cover the majority of the employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy Inc. MidAmerican Energy recognizes the funded status of its defined benefit pension and other postretirement benefit plans on the Balance Sheets. Funded status is the fair value of plan assets minus the benefit obligation as of the measurement date. As of December 31, 2020, MidAmerican Energy recognized a net liability totaling $153 million for the funded status of its defined benefit pension and other postretirement benefit plans. As of December 31, 2020, amounts not yet recognized as a component of net periodic benefit cost that were included in regulatory assets and regulatory liabilities totaled $66 million and $20 million, respectively.
The expense and benefit obligations relating to these defined benefit pension and other postretirement benefit plans are based on actuarial valuations. Inherent in these valuations are key assumptions, including discount rates, expected long-term rate of return on plan assets and healthcare cost trend rates. These key assumptions are reviewed annually and modified as appropriate. MidAmerican Energy believes that the assumptions utilized in recording obligations under the plans are reasonable based on prior plan experience and current market and economic conditions. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for disclosures about MidAmerican Energy's defined benefit pension and other postretirement benefit plans, including the key assumptions used to calculate the funded status and net periodic benefit cost for these plans as of and for the year ended December 31, 2020.
MidAmerican Energy chooses a discount rate based upon high quality debt security investment yields in effect as of the measurement date that corresponds to cash flows over the expected benefit period. The pension and other postretirement benefit liabilities increase as the discount rate is reduced.
In establishing its assumption as to the expected long-term rate of return on plan assets, MidAmerican Energy utilizes the expected asset allocation and return assumptions for each asset class based on historical performance and forward-looking views of the financial markets. Pension and other postretirement benefits expense increases as the expected long-term rate of return on plan assets decreases. MidAmerican Energy regularly reviews its actual asset allocations and rebalances its investments to its targeted allocations when considered appropriate.
MidAmerican Energy chooses a healthcare cost trend rate that reflects the near and long-term expectations of increases in medical costs and corresponds to the expected benefit payment periods. The healthcare cost trend rate is assumed to gradually decline to 5% by 2025 at which point the rate of increase is assumed to remain constant. Refer to Note 10 of Notes to Financial Statements in Item 8 of this Form 10-K for healthcare cost trend rate sensitivity disclosures.
The key assumptions used may differ materially from period to period due to changing market and economic conditions. These differences may result in a significant impact to pension and other postretirement benefits expense and the funded status. If changes were to occur for the following key assumptions, the approximate effect on the Financial Statements of the total plan before allocations to affiliates would be as follows (in millions):
A variety of factors affect the funded status of the plans, including asset returns, discount rates, plan changes and MidAmerican Energy's funding policy for each plan.
Revenue Recognition - Unbilled Revenue
Revenue from electric and natural gas customers is recognized as electricity or natural gas is delivered or services are provided. The determination of customer billings is based on a systematic reading of meters and rates. At the end of each month, energy provided to customers since the date of the last meter reading is estimated, and the corresponding unbilled revenue is recorded. Unbilled revenue was $95 million as of December 31, 2020. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns, total volumes supplied to the system, line losses and composition of sales among customer classes. Unbilled revenue is reversed in the following month, and billed revenue is recorded based on the subsequent meter readings.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Eastern Energy Gas' Consolidated Balance Sheets include assets and liabilities with fair values that are subject to market risks. Eastern Energy Gas' significant market risks are primarily associated with commodity prices, interest rates, foreign currency and the extension of credit to counterparties with which Eastern Energy Gas transacts. The following discussion addresses the significant market risks associated with Eastern Energy Gas' business activities. Eastern Energy Gas has established guidelines for credit risk management. Refer to Note 2 of Notes to Consolidated Financial Statements in Item 8
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Eastern Energy Gas Holdings, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of Eastern Energy Gas as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of Eastern Energy Gas' management. Our responsibility is to express an opinion on Eastern Energy Gas' financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Eastern Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Eastern Energy Gas' internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Assets and Liabilities - Impact of Rate Regulation on the Financial Statements -Refer to Notes 2 and 7 to the financial statements
Critical Audit Matter Description
Eastern Energy Gas, through its subsidiaries, is subject to rate regulation by the Federal Energy Regulatory Commission (the "FERC"), which has jurisdiction with respect to the rates of interstate natural gas transmission companies. Management has determined its rate regulated subsidiaries meet the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment, net; regulatory assets; regulatory liabilities; operating revenue; operations and maintenance expense; and depreciation and amortization expense; and income tax expense (benefit).
Revenue provided by the Eastern Energy Gas interstate natural gas transmission operations is based primarily on rates approved by the FERC. Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur. Eastern Energy Gas continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. The evaluation reflects the current political and regulatory climate. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss).
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs and (2) a refund to customers. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the FERC, auditing these judgments required specialized knowledge of the accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the FERC included the following, among others:
•We evaluated the Eastern Energy Gas disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.
•We read relevant orders issued by the FERC, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the FERC's treatment of similar costs under similar circumstances. We evaluated the external information and compared to management's recorded regulatory assets and liability balances for completeness.
•For regulatory matters in process, we inspected Eastern Energy Gas' filings with the FERC, and the filings with the FERC by intervenors that may impact Eastern Energy Gas' future rates. for any evidence that might contradict management's assertions.
•We read and analyzed the minutes of the Board of Directors of Berkshire Hathaway Energy and the Board of Directors of Eastern Energy Gas, for discussions of changes in legal, regulatory, or business factors which could impact management's conclusions with respect to the impacted account balances and disclosures of rate regulation.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2021
We have served as Eastern Energy Gas' auditor since 2012.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Amounts in millions)
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in millions)
(1)Includes income tax expense of $33 million and less than $1 million for the years ended December 31, 2019 and 2018, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
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
(Amounts in millions)
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in millions)
The accompanying notes are an integral part of these consolidated financial statements.
EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Eastern Energy Gas Holdings, LLC and its subsidiaries ("Eastern Energy Gas") is a holding company that conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transportation pipeline and underground storage operations in the eastern region of the United States and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transportation pipeline. On November 1, 2020, Berkshire Hathaway Energy Company ("BHE") completed its acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). As a result of the GT&S Transaction, Eastern Energy Gas became an indirect wholly owned subsidiary of BHE. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). See Note 3 for more information regarding the GT&S Transaction.
(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of Eastern Energy Gas and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
Certain amounts in Eastern Energy Gas' 2019 and 2018 Consolidated Financial Statements and Notes have been reclassified to conform to the 2020 presentation for comparative purposes; however, such reclassifications did not affect Eastern Energy Gas' net income, total assets, liabilities, equity or cash flows.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; impairment of goodwill; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
Eastern Energy Gas prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, Eastern Energy Gas defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
Eastern Energy Gas continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit Eastern Energy Gas' ability to recover its costs. Eastern Energy Gas believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be recognized in net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Alternative valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Cash Equivalents and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in restricted cash and cash equivalents on the Consolidated Balance Sheets.
Investments
Eastern Energy Gas utilizes the equity method of accounting with respect to investments when it possesses the ability to exercise significant influence, but not control, over the operating and financial policies of the investee. The ability to exercise significant influence is presumed when the investor possesses more than 20% of the voting interests of the investee. This presumption may be overcome based on specific facts and circumstances that demonstrate the ability to exercise significant influence is restricted. In applying the equity method, Eastern Energy Gas records the investment at cost and subsequently increases or decreases the carrying value of the investment by Eastern Energy Gas' share of the net earnings or losses and other comprehensive income ("OCI") of the investee. Eastern Energy Gas records dividends or other equity distributions as reductions in the carrying value of the investment. Equity investments are presented on the Consolidated Balance Sheets.
Allowance for Credit Losses
Trade receivables are primarily short-term in nature with stated collection terms of less than one year from the date of origination and are stated at the outstanding principal amount, net of an estimated allowance for credit losses. The allowance for credit losses is based on Eastern Energy Gas' assessment of the collectability of amounts owed to Eastern Energy Gas by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. In measuring the allowance for credit losses for trade receivables, Eastern Energy Gas primarily utilizes credit loss history. However, Eastern Energy Gas may adjust the allowance for credit losses to reflect current conditions and reasonable and supportable forecasts that deviate from historical experience. The changes in the balance of the allowance for credit losses, which is included in trades receivables, net on the Consolidated Balance Sheets, is summarized as follows for the years ended December 31, (in millions):
Derivatives
Eastern Energy Gas employs a number of different derivative contracts, which may include forwards, futures, options, swaps and other agreements, to manage its commodity price, interest rate, and foreign currency exchange rate risk. 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. Derivative balances reflect offsetting permitted under master netting agreements with counterparties and cash collateral paid or received under such agreements. Cash collateral received from or paid to counterparties to secure derivative contract assets or liabilities in excess of amounts offset is included in other current assets on the Consolidated Balance Sheets.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as operating revenue or cost of sales on the Consolidated Statements of Operations.
For Eastern Energy Gas' derivatives not designated as hedging contracts, unrealized gains and losses are recognized on the Consolidated Statements of Operations as operating revenue for derivatives related to natural gas sales contracts; and other, net for interest rate swap derivatives.
For Eastern Energy Gas' derivatives designated as hedging contracts, Eastern Energy Gas formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. Eastern Energy Gas formally documents hedging activity by transaction type and risk management strategy. For derivative instruments that are accounted for as cash flow hedges or fair value hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.
Changes in the estimated fair value of a derivative contract designated and qualified as a cash flow hedge, to the extent effective, are included on the Consolidated Statements of Changes in Equity as AOCI, net of tax, until the contract settles and the hedged item is recognized in earnings. Eastern Energy Gas discontinues hedge accounting prospectively when it has determined that a derivative contract no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative contract no longer qualifies as an effective hedge, future changes in the estimated fair value of the derivative contract are charged to earnings. Gains and losses related to discontinued hedges that were previously recorded in AOCI will remain in AOCI until the contract settles and the hedged item is recognized in earnings, unless it becomes probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in earnings.
Inventories
Inventories consist mainly of materials and supplies and are determined using the average cost method.
Gas Imbalances
Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Eastern Energy Gas values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Eastern Energy Gas from other parties are reported in other current assets and imbalances that Eastern Energy Gas owes to other parties are reported in other current liabilities on the Consolidated Balance Sheets.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. Eastern Energy Gas capitalizes all construction-related materials, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include capitalized interest, including debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on estimated useful lives. Depreciation studies are completed by Eastern Energy Gas to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the FERC. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when Eastern Energy Gas retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represent the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, is capitalized by Eastern Energy Gas as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, Eastern Energy Gas is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets.
Asset Retirement Obligations
Eastern Energy Gas recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. Eastern Energy Gas' AROs are primarily related to the obligations associated with its natural gas pipeline and storage well assets. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment, net) and for accretion of the ARO liability due to the passage of time. For Eastern Energy Gas, the difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability.
Impairment of Long-Lived Assets
Eastern Energy Gas evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value and any resulting impairment loss is reflected on the Consolidated Statements of Operations. The impacts of regulation are considered when evaluating the carrying value of regulated assets. See Notes 4 and 7 for more information.
Leases
Eastern Energy Gas has non-cancelable operating leases primarily for office space, office equipment and land and finance leases consisting primarily of natural gas pipeline facilities and vehicles. These leases generally require Eastern Energy Gas to pay for insurance, taxes and maintenance applicable to the leased property. Given the capital intensive nature of the utility industry, it is common for a portion of lease costs to be capitalized when used during construction or maintenance of assets, in which the associated costs will be capitalized with the corresponding asset and depreciated over the remaining life of that asset. Certain leases contain renewal options for varying periods and escalation clauses for adjusting rent to reflect changes in price indices. Eastern Energy Gas does not include options in its lease calculations unless there is a triggering event indicating Eastern Energy Gas is reasonably certain to exercise the option. Eastern Energy Gas' accounting policy is to not recognize right-of-use assets and lease obligations for leases with contract terms of one year or less and not separate lease components from non-lease components and instead account for each separate lease component and the non-lease components associated with a lease as a single lease component. Leases will be evaluated for impairment in line with Accounting Standards Codification ("ASC") 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.
Eastern Energy Gas' operating and finance right-of-use assets are recorded in other assets and the operating and finance lease liabilities are recorded in current and long-term other liabilities accordingly.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net assets acquired in business combinations. Eastern Energy Gas evaluates goodwill for impairment at least annually. Prior to the GT&S Transaction, Eastern Energy Gas evaluated goodwill for impairment as of April 1. As a result of the GT&S Transaction, Eastern Energy Gas will complete its annual reviews as of October 31 to align with BHE's policy. When evaluating goodwill for impairment, Eastern Energy Gas estimates the fair value of its reporting units. If the carrying amount of a reporting unit, including goodwill, exceeds the estimated fair value, then the identifiable assets, including identifiable intangible assets, and liabilities of the reporting unit are estimated at fair value as of the current testing date. The excess of the estimated fair value of the reporting unit over the current estimated fair value of net assets establishes the implied value of goodwill. The excess of the recorded goodwill over the implied goodwill value is charged to earnings as an impairment loss. Significant judgment is required in estimating the fair value of the reporting unit and performing goodwill impairment tests. Eastern Energy Gas uses a variety of methods to estimate a reporting unit's fair value, principally discounted projected future net cash flows. Key assumptions used include, but are not limited to, the use of estimated future cash flows; multiples of earnings; and an appropriate discount rate. In estimating future cash flows, Eastern Energy Gas incorporates current market information, as well as historical factors. As such, the determination of fair value incorporates significant unobservable inputs. During 2020, 2019 and 2018, Eastern Energy Gas did not record any goodwill impairments.
Eastern Energy Gas records goodwill adjustments for (a) the tax benefit associated with the excess of tax-deductible goodwill over the reported amount of goodwill and (b) changes to the purchase price allocation prior to the end of the measurement period, which is not to exceed one year from the acquisition date.
Revenue Recognition
Eastern Energy Gas uses a single five-step model to identify and recognize revenue from contracts with customers ("Customer Revenue") upon transfer of control of promised goods or services in an amount that reflects the consideration to which Eastern Energy Gas expects to be entitled in exchange for those goods or services. Eastern Energy Gas records sales and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
A majority of Eastern Energy Gas' energy revenue is derived from tariff-based sales arrangements approved by the FERC. These tariff-based revenues are mainly comprised of natural gas transmission and storage services and have performance obligations which are satisfied over time as services are provided. Eastern Energy Gas' revenue that is nonregulated primarily relates to LNG terminalling services.
Revenue recognized is equal to what Eastern Energy Gas has the right to invoice as it corresponds directly with the value to the customer of Eastern Energy Gas' performance to date and includes billed and unbilled amounts. As of December 31, 2020 and 2019, trade receivables, net on the Consolidated Balance Sheets relate substantially to Customer Revenue, including unbilled revenue of $95 million and $104 million, respectively. Payments for amounts billed are generally due from the customer within 30 days of billing. Rates charged for energy products and services are established by regulators or contractual arrangements that establish the transaction price as well as the allocation of price amongst the separate performance obligations. When preliminary regulated rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. In the event one of the parties to a contract has performed before the other, Eastern Energy Gas would recognize a contract asset or contract liability depending on the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas has recognized contract assets of $29 million and $40 million as of December 31, 2020 and 2019, respectively, and $19 million and $20 million of contract liabilities as of December 31, 2020 and 2019, respectively, due to Eastern Energy Gas' performance on certain contracts.
Unamortized Debt Premiums, Discounts and Debt Issuance Costs
Premiums, discounts and debt issuance costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
Income Taxes
Prior to the GT&S Transaction, DEI included Eastern Energy Gas in its consolidated United States federal income tax return. Subsequent to the GT&S Transaction, Berkshire Hathaway includes Eastern Energy Gas in its consolidated United States federal income tax return. Consistent with established regulatory practice, Eastern Energy Gas' provision for income taxes has been computed on a stand-alone return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using enacted income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities associated with components of OCI are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities associated with certain property-related basis differences and other various differences that Eastern Energy Gas' regulated businesses deems probable to be passed on to its customers are charged or credited directly to a regulatory asset or liability and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized.
In determining Eastern Energy Gas' income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the FERC. Eastern Energy Gas' income tax returns are subject to continuous examinations by federal, state and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. Eastern Energy Gas recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not to be realized upon ultimate settlement. Although the ultimate resolution of Eastern Energy Gas' federal, state and local income tax examinations is uncertain, Eastern Energy Gas believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on Eastern Energy Gas' consolidated financial results. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Segment Information
Eastern Energy Gas currently has one segment, which includes its natural gas pipeline, storage and LNG operations.
(3) Business Acquisitions and Dispositions
Acquisition of Eastern Energy Gas by BHE
In July 2020, DEI entered into an agreement to sell substantially all of its gas transmission and storage operations, including Eastern Energy Gas and a 25% limited partnership interest in Cove Point, to BHE. Approval of the transaction under the Hart-Scott-Rodino Act was not obtained within 75 days and DEI and BHE mutually agreed to a dual-phase closing consisting of two separate disposal groups identified as the GT&S Transaction and the proposed sale of the Questar Pipeline Group by DEI to BHE pursuant to a purchase and sale agreement entered into on October 5, 2020 ("Q-Pipe Transaction"). The Q-Pipe Transaction is currently anticipated to close in the first half of 2021, contingent on clearance or approval under the Hart-Scott-Rodino Act, and other customary closing and regulatory conditions. Prior to the completion of the GT&S Transaction, Eastern Energy Gas finalized a restructuring whereby Eastern Energy Gas distributed the Questar Pipeline Group and a 50% noncontrolling interest in Cove Point to DEI. This restructuring was accounted for by Eastern Energy Gas as a reorganization of entities under common control and the disposition was reflected as an equity transaction. The disposition was not reported as a discontinued operation as the disposal did not represent a strategic shift in the way management had intended to run the business.
In November 2020, the GT&S Transaction was completed and Eastern Energy Gas, with the exception of the Questar Pipeline Group as discussed above, became an indirect wholly-owned subsidiary of BHE. DEI retained a 50% noncontrolling interest in Cove Point as well as the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations sold and relating to services provided before closing. See Notes 11 and 14 for more information on the GT&S Transaction.
Eastern Energy Gas recorded a distribution of net assets of $699 million, including goodwill of $185 million and $41 million of cash, for the distribution of the Questar Pipeline Group to DEI and recorded an approximately $2.8 billion increase in noncontrolling interests for DEI's retained 50% noncontrolling interest in Cove Point. Additionally, in accordance with the terms of the GT&S Transaction, DEI retained certain assets and liabilities associated with Eastern Energy Gas and settled all affiliated balances. As a result, Eastern Energy Gas recorded a contribution for the reset of deferred taxes of $1.3 billion, net of distributions of $895 million related to the pension and other postretirement employee benefit plans retained by DEI and $107 million related to the settlement of affiliated balances.
Dominion Energy Gas Restructuring
The acquisition of CPMLP Holdings Company, LLC (formerly known as Dominion Cove Point, LLC) ("DCP") and Eastern MLP Holding Company II, LLC (formerly known as Dominion MLP Holding Company II, LLC) ("DMLPHCII") from, and the disposition of the East Ohio Gas Company ("East Ohio") and Eastern Gathering and Processing, Inc. (formerly known as Dominion Gathering and Processing, Inc.) ("EGP") to, DEI by Eastern Energy Gas on November 6, 2019 ("Dominion Energy Gas Restructuring") was considered to be a reorganization of entities under common control. As a result, Eastern Energy Gas' basis in DCP and DMLPHCII, which included the general partner of Northeast Midstream Partners, LP (formerly known as Dominion Energy Midstream Partners, LP) ("Northeast Midstream"), a controlling 75% interest in Cove Point, Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC), Questar Pipeline Group, a 50% noncontrolling interest in White River Hub, LLC ("White River Hub") and a 25.93% noncontrolling interest in Iroquois, is equal to DEI's cost basis in the assets and liabilities of such entities since the applicable inception dates of common control. In November 2019, following completion of the Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Eastern Energy Gas and therefore are consolidated by Eastern Energy Gas. The accompanying Consolidated Financial Statements and Notes of Eastern Energy Gas have been retrospectively adjusted to include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by DEI, and subsequently sold to Brookfield Super-Core Infrastructure Partners ("Brookfield") in December 2019, and the non-DEI held interest in Northeast Midstream (through January 2019) are reflected as noncontrolling interest.
The Dominion Energy Gas Restructuring included the disposition of East Ohio and EGP by Eastern Energy Gas in November 2019. This restructuring represented a strategic shift in the operations of Eastern Energy Gas as Eastern Energy Gas' operations consist of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Eastern Energy Gas have been retrospectively adjusted to include the historical results and financial position of East Ohio and EGP as discontinued operations until November 2019. As the Dominion Energy Gas Restructuring was considered to be a reorganization of entities under common control, Eastern Energy Gas reflected the disposition as an equity transaction. The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Eastern Energy Gas' Consolidated Statements of Operations (in millions):
Capital expenditures and significant noncash items relating to East Ohio included the following (in millions):
The following table represents selected information regarding the results of operations of EGP, which are reported as discontinued operations in Eastern Energy Gas' Consolidated Statements of Operations (in millions):
Capital expenditures and significant noncash items of EGP included the following (in millions):
(4) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
Construction work-in-progress includes $196 million and $584 million as of December 31, 2020 and 2019, respectively, related to the construction of utility plant.
EGP Gathering and Processing Assets
In the fourth quarter of 2018, Eastern Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at EGP. Based on an evaluation of EGP's long-lived assets for recoverability under a probability weighted approach, Eastern Energy Gas determined the assets were impaired. As a result of this evaluation, Eastern Energy Gas recorded a charge of $219 million ($165 million after-tax) in discontinued operations in its Consolidated Statement of Operations to write-down EGP's property, plant and equipment to its estimated fair value of $190 million. The fair value of the property, plant and equipment was estimated using an income approach and market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.
Assignments of Shale Development Rights
In December 2013, Eastern Energy Gas closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Eastern Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In August 2017, Eastern Energy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Eastern Energy Gas' remaining 68% interest in approximately 70,000 acres and the elimination of Eastern Energy Gas' overriding royalty interest in gas produced from all acreage. Eastern Energy Gas received consideration of $65 million in September 2018 in connection with the final conveyance. As a result of this amendment, Eastern Energy Gas recognized in 2018 a $65 million ($47 million after-tax) gain included in operations and maintenance expense in the Consolidated Statement of Operations associated with the final conveyance of acreage.
In November 2014, Eastern Energy Gas closed an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Eastern Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In January 2018, Eastern Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Eastern Energy Gas' remaining 50% interest in approximately 18,000 acres and the elimination of Eastern Energy Gas' overriding royalty interest in gas produced from all acreage. Eastern Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax) gain recorded in operations and maintenance expense in the Consolidated Statement of Operations.
In March 2018, Eastern Energy Gas closed an agreement with a natural gas producer to convey approximately 11,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Eastern Energy Gas, subject to customary adjustments, of $16 million. In March 2018, Eastern Energy Gas received cash proceeds of $16 million associated with the conveyance of the acreage, resulting in a $16 million ($12 million after-tax) gain recorded in operations and maintenance expense in the Consolidated Statement of Operations.
In June 2018, Eastern Energy Gas closed an amendment to an agreement with a natural gas producer for the elimination of Eastern Energy Gas' overriding royalty interest in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Eastern Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax) gain recorded in operations and maintenance expense in the Consolidated Statement of Operations.
(5) Jointly Owned Utility Facilities
Under joint facility ownership agreements with other utilities, Eastern Energy Gas, as a tenant in common, has undivided interests in jointly owned transmission and storage facilities. Eastern Energy Gas accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners primarily based on their percentage of ownership. Operating costs and expenses on the Consolidated Statements of Operations include Eastern Energy Gas' share of the expenses of these facilities.
The amounts shown in the table below represent Eastern Energy Gas' share in each jointly owned facility included in property, plant and equipment, net as of December 31, 2020 (dollars in millions):
(6) Leases
The following table summarizes Eastern Energy Gas' leases recorded on the Consolidated Balance Sheet (in millions):
The following table summarizes Eastern Energy Gas' lease costs (in millions):
The following table summarizes Eastern Energy Gas' supplemental cash flow information relating to leases (in millions):
Eastern Energy Gas has the following remaining lease commitments as of (in millions):
(7) Regulatory Matters
Regulatory Assets
Regulatory assets represent costs that are expected to be recovered in future regulated rates. Eastern Energy Gas' regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
(1)Represents costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain rate-regulated subsidiaries.
(2)Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt.
Eastern Energy Gas had regulatory assets not earning a return on investment of $10 million and $46 million as of December 31, 2020 and 2019, respectively.
Regulatory Liabilities
Regulatory liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. Eastern Energy Gas' regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.
(2)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.
(3)Rates charged to customers by Eastern Energy Gas' regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.
Regulatory Matters
Eastern Gas Transmission and Storage, Inc.
In July 2017, the FERC audit staff communicated to Eastern Gas Transmission and Storage, Inc. ("EGTS") that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge of $129 million ($94 million after-tax) recorded primarily within operations and maintenance expense in the Consolidated Statement of Operations for the year ended December 31, 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) charge for disallowance of capitalized AFUDC, recorded within operations and maintenance expense in the Consolidated Statement of Operations. As a condition of the December 2020 ruling, EGTS will file its proposed accounting entries and supporting documentation with the FERC by the second quarter of 2021; however, EGTS does not expect a material change from the charge recognized.
In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statement of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO. In the third quarter of 2020, Eastern Energy Gas recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to the previously established ARO, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statement of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.
In December 2019, EGTS filed an application to request FERC authorization to construct, operate and maintain the Tri-West project to provide 120,000 Dths per day of firm transportation service from Pennsylvania to Ohio for delivery to Tennessee Gas Pipeline Company, L.L.C. The application was automatically approved after a 60-day waiting period from the date of filing and the project commenced commercial operations in August 2020 at a cost of $17 million.
In January 2018, EGTS filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. In June 2019, EGTS withdrew its application for the project due to certain regulatory delays. As a result of the project abandonment, during the second quarter of 2019, EGTS recorded a charge of $13 million ($10 million after-tax), included in operations and maintenance expenses in the Consolidated Statement of Operations.
Cove Point
In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million project to provide 150,000 Dths per day of transportation service to help meet demand for natural gas for Washington Gas Light Company ("Eastern Market Access Project"). In January 2018, Cove Point received FERC authorization to construct and operate the project facilities. In October 2018, Cove Point announced it was evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million ($28 million after-tax). In May 2019, Cove Point filed an application for an amendment to vacate its FERC authorization for the Charles County, Maryland compressor station and revised its project scope. In August 2019, Cove Point received FERC authorization and the Eastern Market Access Project commenced commercial operations in September 2019.
In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of approximately $182 million. In February 2020, FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of approximately $4 million and a decrease in annual depreciation expense of approximately $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021, which is subject to final approval by the FERC.
(8) Investments and Restricted Cash and Cash Equivalents
Investments and restricted cash and cash equivalents consists of the following as of December 31 (in millions):
Equity Method Investments
Eastern Energy Gas, through a subsidiary, owns 50% of Iroquois, which owns and operates an interstate natural gas pipeline located in the states of New York and Connecticut. Prior to the GT&S Transaction, Eastern Energy Gas, through the Questar Pipeline Group, owned 50% of White River Hub, which owns and operates a natural gas pipeline in northwest Colorado.
As of December 31, 2020 and 2019, the carrying amount of Eastern Energy Gas' investments exceeded its share of underlying equity in net assets by $130 million and $146 million, respectively. The difference reflects equity method goodwill and is not being amortized. Eastern Energy Gas received distributions from its investments of $77 million, $74 million and $64 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(9) Short-term Debt and Credit Facilities
Prior to the GT&S Transaction, Eastern Energy Gas' short-term financing was supported through its access as co-borrower to a joint revolving credit facility with DEI. The credit facility was used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes. As of December 31, 2019, a maximum of $1.5 billion of the facility was available to Eastern Energy Gas and the sub-limit was $750 million. As of December 31, 2019, Eastern Energy Gas had $62 million of commercial paper outstanding with a weighted-average interest rate of 1.98%.
(10) Long-term Debt
Eastern Energy Gas' long-term debt consists of the following, including unamortized premiums, discounts and debt issuance costs, as of December 31 (dollars and euros in millions):
(1)The senior notes have variable interest rates based on LIBOR plus an applicable spread. Eastern Energy Gas has entered into an interest rate swap that fixes the interest rate on 100% of the notes. The fixed interest rates as of December 31, 2020 and 2019 were 3.46% (including a 0.60% margin).
(2)The senior notes are denominated in Euros with an outstanding principal balance of €250 million and a fixed interest rate of 1.45%. Eastern Energy Gas has entered into cross currency swaps that fix USD payments for 100% of the notes. The fixed USD outstanding principal when combined with the swaps is $280 million, with fixed interest rates at both December 31, 2020 and 2019 that averaged 3.32%.
(3)Long-term debt associated with the Questar Pipeline Group.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt for the years beginning January 1, 2021 and thereafter, are as follows (in millions):
(11) Income Taxes
Income tax (benefit) expense consists of the following for the years ended December 31 (in millions):
Income tax expense reported in discontinued operations for the year ended December 31, 2019 was $33 million. Income tax expense reported in discontinued operations for year ended December 31, 2018 was less than $1 million.
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 for the years ended December 31:
For the year ended December 31, 2020, Eastern Energy Gas' effective tax rate is primarily a function of the nominal year-to-date pre-tax income driven by charges associated with the Supply Header Project, as discussed in Note 7. In addition, the effective tax rate reflects an income tax benefit of $24 million associated with finalizing the effects of changes in tax status of certain subsidiaries in connection with the Dominion Energy Gas Restructuring.
The net deferred income tax asset (liability) consists of the following as of December 31 (in millions):
(1)Net deferred income tax asset as of December 31, 2020 is presented in other assets in the Consolidated Balance Sheet.
The net deferred income tax liability decreased significantly due to the GT&S Transaction. The acquisition was treated as a deemed asset sale for federal and state income tax purposes. All deferred taxes at Eastern Energy Gas were reset to reflect financial and tax basis differences as of November 1, 2020.
Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined state income tax returns. The United States Internal Revenue Service has closed its examination of Eastern Energy Gas' consolidated income tax returns through December 31, 2018. The statute of limitations for Eastern Energy Gas' state tax returns have expired through December 31, 2016, with the exception of Pennsylvania, New York and West Virginia, for which the earliest remaining open tax years are December 31, 2012, December 31, 2015, and December 31, 2017, respectively. DEI is responsible for income taxes, including any adjustments resulting from its audit examinations, prior to the GT&S Transaction.
A reconciliation of the beginning and ending balances of Eastern Energy Gas' net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
As of December 31, 2019, Eastern Energy Gas has unrecognized tax benefits of $2 million, that if recognized, would have an impact on the effective tax rate. As part of the GT&S Transaction, DEI will retain all pre-close unrecognized tax benefits.
(12) Employee Benefit Plans
Defined Benefit Plans
As discussed in Note 3, in November 2020, the GT&S Transaction was completed and the assets and obligations of the pension and other postretirement employee benefit plans associated with the operations sold and relating to services provided before closing were retained by DEI. As a result, just prior to completing the sale, net benefit plan assets of $895 million were distributed through an equity transaction with DEI. Eastern Energy Gas employees are covered by MidAmerican Energy Company's ("MidAmerican Energy") pension and other postretirement benefit plans subsequent to the GT&S Transaction. Prior to the GT&S Transaction, Eastern Energy Gas participated in a number of the DEI-sponsored retirement plans.
Prior to the GT&S Transaction, certain Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by DEI that provides benefits to multiple DEI subsidiaries. As participating employers, Eastern Energy Gas was subject to DEI's funding policy, which was to contribute annually an amount that is in accordance with the Employee Retirement Income Security Act of 1974. During 2020, Eastern Energy Gas made no contributions to the Dominion Energy Pension Plan. Eastern Energy Gas' net periodic pension credit related to this plan was $(14) million, $(8) million and $(35) million for the years ended December 31, 2020, 2019 and 2018, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Operations, except for $(14) million and $(21) million of Eastern Energy Gas' costs for the years ended December 31, 2019 and 2018, respectively, that are recorded in net income from discontinued operations. The funded status of various DEI subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating DEI subsidiaries. Subsequent to the GT&S Transaction, certain Eastern Energy Gas employees are covered by the MidAmerican Energy Pension Plan similar to the DEI plan described above. Eastern Energy Gas' net periodic pension cost related to this plan was $3 million for the year ended December 31, 2020. During 2020, Eastern Energy Gas made $3 million of contributions to the MidAmerican Energy Pension Plan and expects to contribute $19 million in 2021.
Prior to the GT&S transaction, certain retiree healthcare and life insurance benefits for Eastern Energy Gas employees not represented by collective bargaining units were covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by DEI that provides certain retiree healthcare and life insurance benefits to multiple DEI subsidiaries. Eastern Energy Gas' net periodic benefit credit related to this plan was $(5) million, $(4) million, and $(8) million for the years ended December 31, 2020, 2019 and 2018, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expense in the Consolidated Statements of Operations, except for less than $(1) million and $(2) million of Eastern Energy Gas' costs for the years ended December 31, 2019 and 2018, respectively, that are recorded in net income from discontinued operations. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating DEI subsidiaries. Subsequent to the GT&S Transaction, certain Eastern Energy Gas employees are covered by the MidAmerican Energy Retiree Health and Welfare plan similar to the DEI plan described above. Eastern Energy Gas' net periodic benefit cost related to this plan was $2 million for the year ended December 31, 2020. During 2020, Eastern Energy Gas made $2 million of contributions to the MidAmerican Energy Health and Welfare Plan and expects to contribute $12 million in 2021.
Pension benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate pension plan that provides benefits to employees of both EGTS and Hope Gas, Inc. ("Hope"). Employee compensation was the basis for allocating pension costs and obligations between EGTS and Hope. Retiree healthcare and life insurance benefits for Eastern Energy Gas employees represented by collective bargaining units were covered by a separate other postretirement benefit plan that provides benefits to both EGTS and Hope. Employee headcount was the basis for allocating other postretirement benefit costs and obligations between EGTS and Hope.
Eastern Energy Gas included the separate pension and other postretirement benefit plans for East Ohio employees covered by collective bargaining units through November 2019, the effective date of the Dominion Energy Gas Restructuring. See Note 3 for more information on the Dominion Energy Gas Restructuring.
Pension Remeasurement
In the third quarter of 2020, Eastern Energy Gas remeasured a pension plan due to a curtailment resulting from the agreement for DEI to retain the assets and obligations of the pension benefit plan associated with the GT&S Transaction. The remeasurement resulted in an increase in the pension benefit obligation of $3 million and a decrease in the fair value of the pension plan assets of $7 million for Eastern Energy Gas. The impact of the remeasurement on net periodic pension benefit credit was recognized prospectively from the remeasurement date and is not material. The discount rate used for the remeasurement was 3.16%. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2019.
Voluntary Retirement Program
In March 2019, Eastern Energy Gas announced a voluntary retirement program to employees that met certain age and service requirements. The voluntary retirement program will not compromise safety or Eastern Energy Gas' ability to comply with applicable laws and regulations. In 2019, upon the determinations made concerning the number of employees that elected to participate in the program, Eastern Energy Gas recorded a charge of $74 million ($58 million after-tax) included within operations and maintenance expense ($41 million), other income ($1 million) and discontinued operations ($32 million) in the Consolidated Statements of Operations. In the second quarter of 2019, Eastern Energy Gas remeasured its pension and other postretirement benefit plans as a result of the voluntary retirement program. The remeasurement resulted in an increase in the pension benefit obligation of $32 million and an increase in the fair value of the pension plan assets of $146 million. In addition, the remeasurement resulted in an increase in the accumulated postretirement benefit obligation of $8 million and an increase in the fair value of the other postretirement benefit plan assets of $29 million. The impact of the remeasurement on net periodic benefit cost (credit) was recognized prospectively from the remeasurement date. The discount rate used for the remeasurement was 4.10% for the Eastern Energy Gas pension plans and 4.05% for the Eastern Energy Gas other postretirement benefit plans. All other assumptions used for the remeasurement were consistent with the measurement as of December 31, 2018.
Funded Status
The following table is a reconciliation of the fair value of plan assets for the year ended December 31 (in millions):
The following table is a reconciliation of the benefit obligations for the year ended December 31 (in millions):
The funded status of the plans and the amounts recognized on the Consolidated Balance Sheets as of December 31 are as follows (in millions):
The accumulated benefit obligation for the defined benefit pension plans covering Eastern Energy Gas employees represented by collective bargaining units was $279 million as of December 31, 2019.
Plan Assets
Investment Policy and Asset Allocations
DEI's overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by DEI, Eastern Energy Gas was subject to DEI's investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for DEI's pension funds were 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.
DEI also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.
Strategic investment policies are established for DEI's prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans' strategic allocation are a function of DEI's assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans' actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to further reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.
Fair Value Measurements
The following table presents the fair value of plan assets, by major category, for Eastern Energy Gas' defined benefit pension plan as of December 31, 2019 (in millions):
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
The following table presents the fair value of plan assets, by major category, for Eastern Energy Gas' defined benefit other postretirement plan as of December 31, 2019 (in millions):
(1)Refer to Note 15 for additional discussion regarding the three levels of the fair value hierarchy.
For Level 1 investments, 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. For Level 2 investments, the fair value is determined using pricing models based on observable market inputs. Shares of mutual funds not registered under the Securities Act of 1933, private equity limited partnership interests, common and commingled trust funds and investment entities are reported at fair value based on the net asset value per unit, which is used for expedience purposes. A fund's net asset value is based on the fair value of the underlying assets held by the fund less its liabilities.
Net Periodic Benefit Cost
Net periodic benefit cost for the plans included the following components for the years ended December 31 (in millions):
Significant assumptions used to determine periodic credits for the years ended December 31:
Unrecognized Amounts
The portion of the funded status of the plans not yet recognized in net periodic benefit cost as of December 31 is as follows (in millions):
(1)As of December 31, 2019, of the $150 million related to pension benefits, $147 million is included in AOCI, with the remainder included in regulatory assets and liabilities and the $(5) million related to other postretirement benefits is included entirely in regulatory assets and liabilities.
Defined Contribution Plans
Eastern Energy Gas participated in the BHE GT&S, LLC ("BHE GT&S") defined contribution employee savings plan subsequent to the GT&S Transaction and the DEI defined contribution employee savings plans prior to the GT&S Transaction. Eastern Energy Gas' matching contributions are based on each participant's level of contribution. Contributions cannot exceed the maximum allowable for tax purposes. Eastern Energy Gas' contributions to the 401(k) plan were $4 million, $4 million and $8 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(13) Asset Retirement Obligations
Eastern Energy Gas estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of the expected work.
Eastern Energy Gas does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on the Cove Point LNG facility, interim removal of natural gas pipelines and certain storage wells in EGTS' underground natural gas storage network cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. Cost of removal regulatory liabilities totaled $88 million and $73 million as of December 31, 2020 and 2019, respectively. Eastern Energy Gas will continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets.
The following table reconciles the beginning and ending balances of Eastern Energy Gas' ARO liabilities for the years ended December 31 (in millions):
(14) Risk Management and Hedging Activities
Eastern Energy Gas is exposed to the impact of market fluctuations in commodity prices, interest rates, and foreign currency exchange rates. Eastern Energy Gas is principally exposed to natural gas market fluctuations primarily through fuel retained and used during the operation of the pipeline system as well as lost and unaccounted for gas, to interest rate risk on its outstanding variable-rate short- and long-term debt and future debt issuances, and to foreign currency exchange risk associated with Euro denominated debt. Eastern Energy Gas has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report, each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Eastern Energy Gas uses over-the-counter commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Eastern Energy Gas also uses over-the-counter interest rate swaps to hedge its exposure to variable interest rates on long-term debt as well as over-the-counter foreign currency swaps to hedge its exposure to principal and interest payments denominated in Euros. Eastern Energy Gas does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
Subsequent to the GT&S Transaction, Eastern Energy Gas has elected to offset derivative contracts where master netting arrangements allow. There have been no other significant changes in Eastern Energy Gas' accounting policies related to derivatives. Refer to Notes 2 and 15 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 Eastern Energy Gas' 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):
AOCI
The following table presents selected information related to losses on cash flow hedges included in AOCI in Eastern Energy Gas' Consolidated Balance Sheet as of December 31, 2020 (in millions):
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.
In July 2020, Eastern Energy Gas recorded a loss of $141 million ($105 million after-tax) in interest expense in the Consolidated Statement of Operations, for cash flow hedges of debt-related items that are probable of not occurring as a result of the GT&S Transaction. The derivatives related to these hedges were settled in October 2020 for a cash payment of $165 million.
Gains and Losses on Derivative Contracts
The following tables present the gains and losses on Eastern Energy Gas' derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Consolidated Statements of Operations for the years ended December 31 (in millions):
(1)Amounts deferred into AOCI have no associated effect in Eastern Energy Gas' Consolidated Statements of Operations.
(2)Amounts recorded in Eastern Energy Gas' Consolidated Statements of Operations are classified in interest expense.
(3)Amounts recorded in Eastern Energy Gas' Consolidated Statements of Operations are classified in other, net.
(1)Amounts recorded in Eastern Energy Gas' Consolidated Statements of Operations are classified in interest expense.
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 December 31 (in millions):
Credit Risk
Eastern Energy Gas 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 Eastern Energy Gas' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, Eastern Energy Gas 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, Eastern Energy Gas 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, Eastern Energy Gas exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Upon the Cove Point LNG export/liquefaction facility commencing commercial operations in April 2018, the majority of Cove Point's revenue and earnings are from annual reservation payments under certain terminalling, storage and transportation contracts with ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., LTD., and GAIL Global (USA) LNG, LLC (the "Export Customers"). If such agreements were terminated and Cove Point was unable to replace such agreements on comparable terms, there could be a material impact on results of operations, financial condition and/or cash flows.
The Export Customers comprised approximately 34% of Eastern Energy Gas' operating revenues for both of the years ended December 31, 2020 and 2019, with Eastern Energy Gas' largest customer representing approximately 17% of such amounts.
For the year ended December 31, 2020, EGTS provided service to 289 customers with approximately 98% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 37% of the total storage and transportation revenue and the thirty largest provided approximately 69% of the total storage and transportation revenue.
(15) 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.
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. All of Eastern Energy Gas' derivatives are considered Level 2 in the fair value hierarchy.
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 as of December 31 (in millions):
(16) Commitments and Contingencies
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.
Air
Revisions to Ozone National Ambient Air Quality Ozone Standards
The Clean Air Act includes National Ambient Air Quality Standards ("NAAQS"). States adopt rules that ensure their air quality meets the NAAQS. In October 2015, the United States Environmental Protection Agency ("EPA") published a rule lowering the ground level ozone NAAQS for non-attainment designations. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, Eastern Energy Gas is unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on Eastern Energy Gas' results of operations and cash flows.
Oil and Gas New Source Performance Standards
In August 2020, the EPA issued two final amendments related to the reconsideration of the New Source Performance Standard ("NSPS") for the oil and natural gas sector applicable to volatile organic compound and methane emissions. Together, the two amendments have the effect of rescinding the methane portion of the NSPS for all segments of the oil and natural gas sector, rescinding all NSPS for the transmission and storage segment and modifying some of the NSPS volatile organic compound requirements for facilities in the production and processing segments. The two amendments have been challenged in the United States Court of Appeals for the District of Columbia Circuit but remain in effect pending the outcome of the litigation. Eastern Energy Gas is still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.
Carbon Regulations
In August 2016, the EPA issued a draft rule proposing to reaffirm that a source's obligation to obtain a prevention of significant deterioration or Title V permit for greenhouse gases ("GHG") is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of carbon dioxide equivalent emissions under which a source would not be required to apply best available control technology for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, Eastern Energy Gas cannot predict the impact to its results of operations, financial condition and/or cash flows.
Other 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.
Surety Bonds
As of December 31, 2020, Eastern Energy Gas had purchased $22 million of surety bonds. Under the terms of surety bonds, BHE is obligated to indemnify the respective surety bond company for any amounts paid.
(17) Revenue from Contracts with Customers
Eastern Energy Gas uses a single five-step model to identify and recognize revenue from contracts with customers upon transfer of control of promised goods or services in an amount that reflects the consideration to which Eastern Energy Gas expects to be entitled in exchange for those goods or services. The following table summarizes Eastern Energy Gas' energy products and services revenue by regulated and nonregulated for the years ended December 31 (in millions):
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 December 31, 2020 (in millions):
(18) 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 taxes, for the year ended December 31 (in millions):
The following table shows the reclassifications from AOCI to net income for the year ended December 31 (in millions):
(19) Variable Interest Entities
The primary beneficiary of a variable interest entity ("VIE") is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity's economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.
As part of the Dominion Energy Gas Restructuring, DEI contributed to Eastern Energy Gas a 75% controlling limited partner interest in Cove Point. In December 2019, DEI sold its retained 25% noncontrolling limited partner interest in Cove Point. As discussed in Note 3, as part of the GT&S Transaction, Eastern Energy Gas finalized a restructuring which included the disposition of a 50% noncontrolling interest in Cove Point to DEI, which resulted in Eastern Energy Gas owning 100% of the general partner interest and 25% of the limited partnership interest in Cove Point. Eastern Energy Gas concluded that Cove Point is a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Eastern Energy Gas is the primary beneficiary of Cove Point as it has the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it.
Eastern Energy Gas purchased shared services from Carolina Gas Services, Inc. ("Carolina Gas Services") an affiliated VIE, of $12 million, $16 million and $16 million for the years ended December 31, 2020, 2019 and 2018, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to Carolina Gas Services of $22 million and $9 million as of December 31, 2020 and 2019 respectively. Eastern Energy Gas determined that neither it nor any of its consolidated entities is the primary beneficiary of Carolina Gas Services as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Carolina Gas Services provides marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities has any obligation to absorb more than its allocated share of Carolina Gas Services costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Questar Pipeline Services, Inc. ("DEQPS"), an affiliated VIE, of $23 million, $33 million and $29 million for the years ended December 31, 2020, 2019 and 2018, respectively. Eastern Energy Gas' Consolidated Balance Sheet included amounts due to DEQPS of $6 million as of December 31, 2019. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DEQPS, as neither it nor any of its consolidated entities has both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DEQPS provided marketing and operational services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DEQPS costs.
Prior to the GT&S Transaction, Eastern Energy Gas purchased shared services from Dominion Energy Services, Inc. ("DES"), an affiliated VIE, of $90 million, $119 million and $106 million for the years ended December 31, 2020, 2019 and 2018, respectively. Eastern Energy Gas' Consolidated Balance Sheets included amounts due to DES of $27 million as of December 31, 2019. Eastern Energy Gas determined that neither it nor any of its consolidated entities was the primary beneficiary of DES as neither it nor any of its consolidated entities had both the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. DES provided accounting, legal, finance and certain administrative and technical services. Neither Eastern Energy Gas nor any of its consolidated entities had any obligation to absorb more than its allocated share of DES costs.
(20) Noncontrolling Interests
Included in noncontrolling interests in the Consolidated Financial Statements are DEI's 50% interest in Cove Point (effective November 2020), Brookfield's 25% interest in Cove Point (effective December 2019) and the public's ownership interest in Northeast Midstream (through January 2019).
Noncontrolling Interest in Northeast Midstream
Northeast Midstream was a publicly traded master limited partnership that included common units, subordinated units, Series A Preferred Units and incentive distribution rights as its participating securities. In accordance with the partnership agreement, when the subordination period ended, all subordinated units converted into common units on a one-for-one basis and participated pro rata with the other common units in distributions.
In May 2018, all of the subordinated units of Northeast Midstream held by DEI were converted into common units on a 1:1 ratio following the payment of Northeast Midstream's distribution for the first quarter of 2018. In June 2018, DEI, as general partner, exercised an incentive distribution right reset as defined in Northeast Midstream's partnership agreement and received 27 million common units representing limited partner interests in Northeast Midstream. As a result of the increase in its ownership interest in Northeast Midstream, DEI recorded a decrease in noncontrolling interest, and a corresponding increase in shareholders' equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Northeast Midstream held by others.
In January 2019, DEI and Northeast Midstream closed on an agreement and plan of merger pursuant to which DEI acquired each outstanding common unit representing limited partner interests in Northeast Midstream not already owned by DEI through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Northeast Midstream was converted into the right to receive 0.2492 shares of DEI common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Northeast Midstream was converted into common units representing limited partner interests in Northeast Midstream in accordance with the terms of Northeast Midstream's partnership agreement. The merger was accounted for by DEI following the guidance for a change in a parent company's ownership interest in a consolidated subsidiary. Because DEI controlled Northeast Midstream both before and after the merger, the changes in DEI's ownership interest in Northeast Midstream were accounted for as an equity transaction and no gain or loss was recognized. In connection with the merger, DEI recognized $40 million of income taxes in equity primarily attributable to establishing additional regulatory liabilities related to excess deferred income taxes and changes in state income taxes.
Subsequent to this activity, as a result of the Dominion Energy Gas Restructuring, Eastern Energy Gas is considered to have acquired all of the outstanding partnership interests of Northeast Midstream and Northeast Midstream became a wholly-owned subsidiary of Eastern Energy Gas.
(21) Supplemental Cash Flow Disclosures
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of December 31, 2020 and December 31, 2019 consist substantially of customer deposits. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of December 31, 2020 and December 31, 2019, 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):
The summary of supplemental cash flow disclosures as of and for the years ending December 31 is as follows (in millions):
(22) Related-Party Transactions
Transactions Prior to the GT&S Transaction
Prior to the GT&S Transaction, Eastern Energy Gas engaged in related party transactions primarily with other DEI subsidiaries (affiliates). Eastern Energy Gas' receivable and payable balances with affiliates were settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Through October 31, 2020, Eastern Energy Gas was included in DEI's consolidated federal income tax return and, where applicable, combined income tax returns for DEI are filed in various states. As of December 31, 2019, Eastern Energy Gas had a net affiliated receivable of $209 million due from DEI, representing $212 million of federal income taxes receivable from DEI and $3 million of state income taxes payable to DEI. In addition, Eastern Energy Gas' Consolidated Balance Sheet as of December 31, 2019 includes $10 million of state income taxes receivable. All affiliate payables or receivables were settled with DEI prior to the closing date of the GT&S Transaction.
Eastern Energy Gas transacted with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Eastern Energy Gas provided transportation and storage services to affiliates. Eastern Energy Gas also entered into certain other contracts with affiliates, and related parties, including construction services, which were presented separately from contracts involving commodities or services. As of December 31, 2019, Eastern Energy Gas did not have any commodity derivative assets and liabilities with affiliates. See Notes 14 and 18 for more information. See Note 3 for information regarding the Dominion Energy Gas Restructuring, an affiliated transaction. Eastern Energy Gas participated in certain DEI benefit plans as described in Note 12. As of December 31, 2019, Eastern Energy Gas' amount due from DEI associated with the Dominion Energy Pension Plan and reflected in other assets on the Consolidated Balance Sheet was $326 million. Eastern Energy Gas' amount due from DEI associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in other assets on the Consolidated Balance Sheet was $17 million as of December 31, 2019.
DES, Carolina Gas Services, DEQPS and other affiliates provided accounting, legal, finance and certain administrative and technical services to Eastern Energy Gas. Eastern Energy Gas provided certain services to related parties, including technical services.
The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES, Carolina Gas Services and DEQPS to Eastern Energy Gas on the basis of direct and allocated methods in accordance with Eastern Energy Gas' services agreements with DES, Carolina Gas Services and DEQPS. Where costs incurred cannot be determined by specific identification, the costs were allocated based on the proportional level of effort devoted by DES, Carolina Gas Services and DEQPS resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.
Subsequent to the GT&S Transaction, and with the exception of Cove Point, Eastern Energy Gas' transactions with other DEI subsidiaries are no longer related-party transactions.
Presented below are Eastern Energy Gas' significant transactions with DES, Carolina Gas Services, DEQPS and other affiliated and related parties for the years ended December 31 (in millions):
(1)Includes capitalized expenditures of $14 million, $19 million and $37 million for the years ended December 31, 2020, 2019 and 2018, respectively.
(2)Includes amounts attributable to Atlantic Coast Pipeline, a related-party VIE prior to the GT&S Transaction. See below for more information.
The following table presents affiliated and related party balances as of December 31 (in millions):
(1)Represents amounts due from Atlantic Coast Pipeline.
(2)Amounts are presented in other current assets on the Consolidated Balance Sheet.
(3)Amounts are presented in other current liabilities on the Consolidated Balance Sheet.
EGTS provided services to Atlantic Coast Pipeline, which totaled $46 million, $103 million and $203 million for the years ended December 31, 2020, 2019 and 2018, respectively, included in operating revenue in the Consolidated Statements of Operations.
Trade receivables, net as of December 31, 2019 included $22 million of accrued unbilled revenue, respectively. This revenue is based on estimated amounts of services provided but not yet billed to various affiliates.
Interest income related to the affiliated notes receivable under the DEI money pool was $3 million for the year ended December 31, 2020.
Interest income on affiliated notes receivable from East Ohio and EGP borrowings under intercompany revolving credit agreements with Eastern Energy Gas was $14 million and $15 million for the years ended December 31, 2019 and 2018, respectively.
In 2018, in connection with the closing of a $3.0 billion term loan, Cove Point loaned DEI $3.0 billion in exchange for a promissory note. Interest income related to DEI's borrowing was $82 million and $21 million for the years ended December 31, 2019 and 2018, respectively. In September 2019, DEI repaid the promissory note to Cove Point and the proceeds were used by Cove Point to repay its $3.0 billion term loan.
Eastern Energy Gas' affiliated notes receivable from DEI totaled $1.8 billion as of December 31, 2019. In August 2020, DEI repaid the remaining principal balance outstanding. Interest income on the promissory notes was $32 million and $5 million for the years ended December 31, 2020 and 2019, respectively.
As of December 31, 2019, Eastern Energy Gas' affiliated notes receivable from East Ohio totaled $1.7 billion. In June 2020, East Ohio repaid the remaining principal balance outstanding. Interest income on these promissory notes was $33 million, $72 million and $64 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Eastern Energy Gas' borrowings under an intercompany revolving credit agreement with DEI totaled $251 million as of December 31, 2019, with a weighted average interest rate of 2.02%. Interest charges related to Eastern Energy Gas' total borrowings from DEI were $3 million, $3 million and less than $1 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Interest charges related to DCP's total borrowings from DEI totaled $94 million and $96 million for the years ended December 31, 2019 and 2018, respectively.
DCP had borrowings of $9 million with DES as of December 31, 2019, with a weighted-average interest rate of 3.85%. Interest related to DCP's total borrowings from DES totaled $3 million, $3 million and $1 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Interest charges related to Northeast Midstream's promissory note with DEI were $10 million for the year ended December 31, 2019.
For the years ended December 31, 2020, 2019 and 2018, Eastern Energy Gas, including entities acquired in the Dominion Energy Gas Restructuring, distributed $4.3 billion, $603 million and $230 million to DEI, respectively.
Transactions Subsequent to the GT&S Transaction
Eastern Energy Gas is party to a tax-sharing agreement and is part of the Berkshire Hathaway consolidated United States federal income tax return. For current federal and state income taxes, Eastern Energy Gas had a receivable from BHE of $20 million as of December 31, 2020. Eastern Energy Gas received net cash receipts for federal and state income taxes from BHE totaling $76 million for the year ended December 31, 2020.
DEI, BHE, MidAmerican Energy, Northern Natural Gas Company and other related parties provided accounting, human resources, information technology and certain other administrative and technical services to Eastern Energy Gas, which totaled $4 million for the year ended December 31, 2020. Eastern Energy Gas provided certain services to affiliates, including administrative and technical services, which totaled $7 million for the year ended December 31, 2020. Eastern Energy Gas also provided transportation and storage services to affiliates, which totaled $4 million for the year ended December 31, 2020. Other assets included amounts due from an affiliate of $7 million as of December 31, 2020.
Eastern Energy Gas has a $400 million intercompany revolving credit agreement from its parent, BHE GT&S, expiring in November 2021. The credit facility, which is for general corporate purposes and provide for the issuance of letters of credit, has a variable interest rate based on London Interbank Offered Rate ("LIBOR") plus a fixed spread. As of December 31, 2020, $9 million was outstanding under the credit agreement, with a weighted average interest rate of 0.55%.
BHE GT&S has a $200 million intercompany revolving credit agreement from Eastern Energy Gas expiring in December 2021. The credit agreement has a variable interest rate based on LIBOR plus a fixed spread. As of December 31, 2020, $124 million was outstanding under the credit agreement.
Eastern Energy Gas participates in certain MidAmerican Energy benefit plans as described in Note 12. As of December 31, 2020, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheet was $115 million.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
At the end of the period covered by this Annual Report on Form 10-K, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities and Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting, except as noted below.
As a result of Berkshire Hathaway Energy Company's acquisition of substantially all of the natural gas transmission and storage business of Dominion Energy, Inc. and Dominion Energy Questar Corporation, exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "GT&S Transaction" or "GT&S Entities") on November 1, 2020, Berkshire Hathaway Energy Company has expanded its internal control over financial reporting to include consolidation of the GT&S Entities financial statements, as well as acquisition related accounting and disclosures.
Management's Report on Internal Control over Financial Reporting
Management of each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company and Eastern Energy Gas Holdings, LLC, respectively, is responsible for establishing and maintaining, for such entity, adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Under the supervision and with the participation of management for each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, such management conducted an evaluation for the relevant entity of the effectiveness of internal control over financial reporting as of December 31, 2020, as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, management for each such respective entity used the criteria set forth in the framework in "Internal Control - Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the evaluation conducted under the framework in "Internal Control - Integrated Framework (2013)," management for each such respective entity concluded that internal control over financial reporting for such entity was effective as of December 31, 2020.
On November 1, 2020, Berkshire Hathaway Energy Company completed the acquisition of the GT&S Entities. In conducting its evaluation of the effectiveness of its internal control over financial reporting, Berkshire Hathaway Energy Company's management elected to exclude the GT&S Entities from this evaluation as permitted under United States Securities and Exchange Commission rules. The GT&S Entities constituted 10.5% of total consolidated assets as of December 31, 2020, and 1.1% of total consolidated net income attributable to BHE shareholders for the year ended December 31, 2020.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 10 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
PacifiCorp is an indirect subsidiary of BHE, and its directors consist of executive management from both BHE and PacifiCorp. Each director was elected based on individual responsibilities, experience in the energy industry and functional expertise. There are no family relationships among the executive officers, nor any arrangements or understandings between any executive officer and any other person pursuant to which the executive officer was appointed. Set forth below is certain information, as of January 31, 2021, with respect to the current directors and executive officers of PacifiCorp:
WILLIAM J. FEHRMAN, 60, Chairman of the Board of Directors and Chief Executive Officer since January 2018. Mr. Fehrman has also been President, Chief Executive Officer and director of BHE since January 2018. Mr. Fehrman was Chief Executive Officer of MidAmerican Energy Company from 2008 to January 2018 and President and director from 2007 to January 2018. Mr. Fehrman joined BHE in 2006 and has extensive executive management experience in the energy industry with strong regulatory and operational skills.
STEFAN A. BIRD, 54, President and Chief Executive Officer of Pacific Power and director since 2015. Mr. Bird was Senior Vice President, Commercial and Trading, of PacifiCorp from 2007 to 2014. Mr. Bird joined BHE in 1998 and has significant operational, public policy and leadership experience in the energy industry, including expertise in energy supply management, resource acquisition and federal and state regulatory matters.
GARY W. HOOGEVEEN, 52, Director since November 2018, President since June 2018 and Chief Executive Officer since November 2018 of Rocky Mountain Power. Prior to his current positions, Mr. Hoogeveen served as Senior Vice President and Chief Commercial Officer of Rocky Mountain Power since November 2014 and President and CEO of Kern River Gas Transmission Company from 2010 to 2014. He joined Kern River after serving as Vice President of Customer Service and Business Development for Northern Natural Gas Company. Prior to joining Northern Natural Gas Company, Mr. Hoogeveen held various management positions at Berkshire Hathaway Energy, joining BHE in 2000. He has significant operational, public policy and leadership experience in both the electricity and natural gas industries, including customer, regulatory and government relations.
NIKKI L. KOBLIHA, 48, Vice President and Chief Financial Officer since 2015 and Treasurer and director since 2017. Ms. Kobliha joined PacifiCorp in 1997 and has significant financial, accounting and leadership experience in the energy industry, including expertise in financial reporting to the SEC and FERC.
CALVIN D. HAACK, 52, Director since May 2020. Mr. Haack has been Senior Vice President and Chief Financial Officer of BHE since March 2020 and was Vice President and Treasurer of BHE from 2010 to 2020. Mr. Haack joined BHE in 1997 and has significant financial experience, including expertise in mergers and acquisitions, accounting, treasury and tax functions. Mr. Haack is also a manager of MidAmerican Funding, LLC.
NATALIE L. HOCKEN, 51, Director since 2007. Ms. Hocken has been Senior Vice President and General Counsel of BHE since 2015 and Corporate Secretary since 2017. Ms. Hocken was Senior Vice President, Transmission and System Operations of PacifiCorp from 2012 to 2015 and Vice President and General Counsel of Pacific Power from 2007 to 2012. Ms. Hocken joined PacifiCorp in 2002 and has significant experience in the utility industry, including expertise in transmission, legal matters and federal and state regulatory matters. Ms. Hocken is also a manager of MidAmerican Funding, LLC.
Board's Role in the Risk Oversight Process
PacifiCorp's Board of Directors is comprised of a combination of BHE senior executives and PacifiCorp senior management who have direct and indirect responsibility for the management and oversight of risk. PacifiCorp's Board of Directors has not established a separate risk management and oversight committee.
Audit Committee and Audit Committee Financial Expert
During the year ended December 31, 2020, and as of the date of this Annual Report on Form 10-K, PacifiCorp's Board of Directors did not have an audit committee. PacifiCorp is not required to have an audit committee as its common stock is indirectly and wholly owned by BHE. However, the audit committee of BHE acts as the audit committee for PacifiCorp.
Code of Ethics
PacifiCorp has adopted a code of ethics that applies to its principal executive officer, its principal financial and accounting officer, or persons acting in such capacities, and certain other covered officers. The code of ethics is incorporated by reference in the exhibits to this Annual Report on Form 10-K.
Item 11.
Item 11. Executive Compensation
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 11 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Compensation Discussion and Analysis
Compensation Philosophy and Overall Objectives
Mr. William J. Fehrman, PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer, or Chairman and CEO, received no direct compensation from PacifiCorp. PacifiCorp reimbursed its indirect parent company, BHE, for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries.
PacifiCorp believes that the compensation paid to each of its Chief Financial Officer, or CFO, and its other most highly compensated executive officers, to whom PacifiCorp refers collectively as its Named Executive Officers, or NEOs, should be closely aligned with its overall performance, and each NEO's contribution to that performance, on both a short- and long-term basis, and that such compensation should be sufficient to attract and retain highly qualified leaders who can create significant value for the organization. PacifiCorp's compensation programs are designed to provide its NEOs meaningful incentives for superior corporate and individual performance. Performance is evaluated on a subjective basis within the context of both financial and non-financial objectives, among which are customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, which PacifiCorp believes contribute to its long-term success.
How is Compensation Determined
PacifiCorp's compensation committee consists solely of the Chairman and CEO. The Chairman and CEO is responsible for the establishment and oversight of PacifiCorp's compensation policy and for approving compensation decisions for its NEOs such as approving base pay increases, incentive and performance awards, off-cycle pay changes, and participation in other employee benefit plans and programs.
PacifiCorp's criteria for assessing executive performance and determining compensation in any year is inherently subjective and is not based upon specific formulas or weighting of factors. PacifiCorp does not specifically use other companies as benchmarks when establishing its NEOs' compensation.
Discussion and Analysis of Specific Compensation Elements
Base Salary
PacifiCorp determines base salaries for all of its NEOs, other than the Chairman and CEO, by reviewing its overall performance, and each NEO's performance, the value each NEO brings to PacifiCorp and general labor market conditions. While base salary provides a base level of compensation intended to be competitive with the external market, the annual base salary adjustment for each NEO, other than the Chairman and CEO, is determined on a subjective basis after consideration of these factors and is not based on target percentiles or other formal criteria. All merit increases are approved by the Chairman and CEO and take effect in the last payroll period of the year. An increase or decrease in base salary may also result from a promotion or other significant change in a NEO's responsibilities during the year. For 2020, base salaries for all NEOs, other than the Chairman and CEO, increased on average by 4.36% effective December 26, 2019, reflecting merit increases.
Short-Term Incentive Compensation
The objective of short-term incentive compensation is to reward the achievement of significant annual corporate and business unit goals while also providing NEOs with competitive total cash compensation.
Annual Incentive Plan
Under PacifiCorp's Annual Incentive Plan, or AIP, all NEOs, other than the Chairman and CEO, are eligible to earn an annual discretionary cash incentive award, which is determined on a subjective basis at the Chairman and CEO's sole discretion and is not based on a specific formula or cap. The Chairman and CEO considers a variety of factors in determining each NEO's annual incentive award including the NEO's performance, PacifiCorp's overall performance and each NEO's contribution to that overall performance. The Chairman and CEO evaluates performance using financial and non-financial objectives, including customer service, employee commitment, environmental respect, regulatory integrity, operational excellence and financial strength, as well as the NEO's response to issues and opportunities that arise during the year. No factor was individually material to the Chairman and CEO's determination regarding the amounts paid to each NEO under the AIP for 2020. Approved awards are paid prior to year-end.
Performance Awards
In addition to the annual awards under the AIP, PacifiCorp may grant cash performance awards periodically during the year to one or more NEOs, other than the Chairman and CEO, to reward the accomplishment of significant non-recurring tasks or projects. These awards are discretionary and are approved by the Chairman and CEO. In 2020, a cash performance award was granted to Ms. Kobliha in recognition of her outstanding efforts.
Long-Term Incentive Compensation
The objective of long-term incentive compensation is to retain NEOs, reward their exceptional performance and motivate them to create long-term, sustainable value. PacifiCorp's current long-term incentive compensation program is cash-based. PacifiCorp does not utilize stock options or other forms of equity-based awards.
Long-Term Incentive Partnership Plan
The PacifiCorp Long-Term Incentive Partnership Plan, or LTIP, is designed to retain key employees and to align PacifiCorp's interests and the interests of the participating employees. All of PacifiCorp's NEOs, other than the Chairman and CEO, participate in the LTIP. The LTIP provides for annual discretionary awards based upon significant accomplishments by the individual participants and the achievement of the financial and non-financial objectives previously described. The goals are developed with the objective of being attainable with a sustained, focused and concerted effort and are determined and communicated by January of each plan year. The BHE Chairman and PacifiCorp's Presidents approve eligibility to participate in the LTIP and the amount of the incentive award. Awards are finalized in the first quarter of the following year. PacifiCorp's Presidents may participate in the LTIP but only the BHE Chairman shall make determinations regarding their participation and the value of their incentive award. These cash-based awards are subject to mandatory deferral and equal annual vesting over a four-year period starting in the performance year. Participants allocate the value of their deferral accounts among various investment alternatives. Gains or losses may be incurred based on investment performance. Participating NEOs may elect to defer all or a part of the award or receive payment in cash after the four-year mandatory deferral and vesting period. Vested balances (including any investment gains or losses thereon) of terminating participants are paid at the time of termination.
Deferred Compensation Plan
PacifiCorp's Executive Voluntary Deferred Compensation Plan, or DCP, provides a means for all NEOs, other than the Chairman and CEO, to make voluntary deferrals of up to 50% of base salary and 100% of short-term incentive compensation awards. PacifiCorp includes the DCP as part of the participating NEO's overall compensation in order to provide a comprehensive, competitive package. The deferrals and any investment returns grow on a tax-deferred basis. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered under the DCP and selected by the participant. The plan allows participants to choose from three forms of distribution. The plan permits PacifiCorp to make discretionary contributions on behalf of participants.
Potential Payments Upon Termination
PacifiCorp's NEOs, other than the Chairman and CEO, are not entitled to severance or enhanced benefits upon termination of employment or change in control. However, upon any termination of employment, PacifiCorp's other NEOs would be entitled to the vested balances in the LTIP, DCP and PacifiCorp's non-contributory defined benefit pension plan, or the Retirement Plan.
Compensation Committee Report
Mr. Fehrman, PacifiCorp's current Chairman and CEO and sole member of PacifiCorp's compensation committee, has reviewed the Compensation Discussion and Analysis and, based on this review, has recommended to the Board of Directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
William J. Fehrman
Summary Compensation Table
The following table sets forth information regarding compensation earned by each of PacifiCorp's NEOs during the years indicated:
(1)Consists of annual cash incentive awards earned pursuant to the AIP for PacifiCorp's NEOs, performance awards, and the vesting of LTIP awards and associated vested earnings. The breakout for 2020 is as follows:
The ultimate payouts of LTIP awards are undeterminable as the amounts to be paid out may increase or decrease depending on investment performance. BHE's Chairman and PacifiCorp's Presidents establish the award categories for determining LTIP awards based on net income target goals or other criteria. In 2020, the gross award was subjectively determined at the discretion of the BHE Chairman and PacifiCorp's Presidents based on the overall achievement of PacifiCorp's financial and non-financial objectives including customer service, employee commitment and safety, environmental respect, regulatory integrity, operational excellence and financial strength.
(2)Amounts are based upon the aggregate increase in the actuarial present value of all qualified and nonqualified defined benefit plans, which includes the Retirement Plan. Refer to the Pension Benefits table below for a discussion of the assumptions used in calculating these amounts. No participant in PacifiCorp's nonqualified deferred compensation plans earned "above market" or "preferential" earnings on amounts deferred.
(3)Amounts consist of PacifiCorp K Plus Employee Savings Plan, or 401(k) Plan, contributions PacifiCorp paid on behalf of the NEOs, except for Mr. Bird for whom PacifiCorp also includes an amount paid for a tax gross-up with respect to a personal benefit with a value less than $10,000.
(4)Any amounts voluntarily deferred by the NEO, if applicable, are included in the appropriate column in the Summary Compensation Table.
(5)On January 10, 2018, Mr. William J. Fehrman was elected as PacifiCorp's Chairman of the Board of Directors and Chief Executive Officer. Mr. Fehrman receives no direct compensation from PacifiCorp. PacifiCorp reimburses BHE for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp, including compensation paid to him by BHE, pursuant to an intercompany administrative services agreement among BHE and its subsidiaries. In 2020, PacifiCorp reimbursed BHE $277,908 for the cost of Mr. Fehrman's time spent on matters supporting PacifiCorp pursuant to the intercompany administrative services agreement.
(6)Mr. Gary W. Hoogeveen was named Rocky Mountain Power's president effective June 1, 2018 and Rocky Mountain Power's chief executive officer effective November 28, 2018.
Pension Benefits
The following table sets forth certain information regarding the defined benefit pension plan accounts held by each of PacifiCorp's NEOs as of December 31, 2020:
(1)Amounts are computed using assumptions, other than the expected retirement age, consistent with those used in preparing the related pension disclosures in the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K and are as of December 31, 2020, which is the measurement date for the plans. The expected retirement age assumption has been determined in accordance with Instruction 2 to Item 402(h)(2) of Regulation S-K. For the Retirement Plan calculations of the present value of accumulated benefits, the following assumptions were used: 80% lump sum payment; 20% joint and 100% survivor annuity if participant is married and 20% single life annuity if participant is single. The present value assumptions used in calculating the present value of accumulated benefits for the Retirement Plan were as follows: a discount rate of 2.50%; an expected retirement age of 65; cash balance interest crediting assumption of 0.82% for 2021 and 2022, and 2.00% thereafter; postretirement mortality using the RP-2014 gender specific tables, adjusted for BHE credibility weighted experience, translated to 2011 using MP-2014; generational mortality improvements from 2011 forward based on MP-2020; a lump sum interest rate of 2.50%; and lump sum mortality using the unisex tables set forth in IRC 417(e)(3) for the upcoming fiscal year with mortality improvements determined using MP-2019.
Historically, PacifiCorp has adopted the Retirement Plan for the majority of its employees, other than employees subject to collective bargaining agreements that do not provide for coverage under the Retirement Plan. Through May 31, 2007, participants earned benefits at retirement payable for life based on length of service through May 31, 2007 and average pay in the 60 consecutive months of highest pay out of the 120 months prior to May 31, 2007. Pay for this purpose included base salary and annual incentive plan payments up to 10% of base salary, but was limited to the amounts specified in Internal Revenue Code Section 401(a)(17). Benefits were based on 1.3% of final average pay plus 0.65% of final average pay in excess of covered compensation (as defined in Internal Revenue Code Section 401(1)(5)(E)) multiplied by years of service.
The Retirement Plan was restated effective June 1, 2007 to change from a traditional final average pay formula as described above to a cash balance formula for non-union participants. Benefits under the final average pay formula were frozen as of May 31, 2007, and no future benefits will accrue under that formula for non-union participants. Under the cash balance formula, benefits are based on pay credits to each participant's account of 6.5% (5.0% for employees hired after June 30, 2006 and before January 1, 2008) of eligible compensation. In addition, through August 1, 2009, there was a pay credit of 4% of eligible compensation in excess of the Social Security Wage Base. Interest is also credited to each participant's account. Employees who were age 40 or older as of May 31, 2007 received certain additional transition pay credits for five years from the effective date of the Retirement Plan restatement.
Participants in the Retirement Plan are entitled to receive full benefits upon retirement on or after age 65. Such participants are also entitled to receive reduced benefits upon early retirement after age 55 with at least five years of service or when age plus years of service equals 75.
The Retirement Plan was closed to non-union employees hired after December 31, 2007 (which includes Mr. Hoogeveen). In 2008, non-union employee participants in the Retirement Plan were offered the option to continue to receive pay credits in the Retirement Plan or receive equivalent fixed contributions to the 401(k) Plan with any such election becoming effective January 1, 2009. Ms. Kobliha elected the equivalent fixed 401(k) contribution option and, therefore, no longer receives pay credits in the Retirement Plan. In 2017, the Retirement Plan was frozen for the remainder of the non-union employees who had participated (which includes Mr. Bird) with pay credits equivalent to those received in the Retirement Plan allocated into the 401(k) Plan. Mr. Bird and Ms. Kobliha continue to receive interest credits in the Retirement Plan.
Nonqualified Deferred Compensation
The following table sets forth certain information regarding the nonqualified deferred compensation plan accounts held by each of PacifiCorp's NEOs as of December 31, 2020:
(1)The executive contribution amount shown for Mr. Hoogeveen represents a deferral of $200,262 of his 2017 LTIP award which was deferred in 2020. $139,109 of the deferred 2017 LTIP award is included in the 2020 total compensation reported for him in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2020.
(2)The executive contribution amount shown for Ms. Kobliha represents a deferral of $44,995 of her 2020 compensation and a deferral of $131,354 of her 2017 LTIP award which was deferred in 2020. $43,821 of the deferred 2017 LTIP award is included in the 2020 total compensation reported for her in the Summary Compensation Table and is not additional compensation. The remaining LTIP award was earned prior to 2020.
Eligibility for PacifiCorp's DCP is restricted to select management and highly compensated employees. The plan provides tax benefits to eligible participants by allowing them to defer compensation on a pretax basis, thus reducing their current taxable income. Deferrals and any investment returns grow on a tax-deferred basis, thus participants pay no income tax until they receive distributions. The DCP permits participants to make a voluntary deferral of up to 50% of base salary and 100% of short-term incentive compensation awards. All deferrals are net of social security taxes. Amounts deferred under the DCP receive a rate of return based on the returns of any combination of various investment alternatives offered by the plan and selected by the participant. Gains or losses are calculated daily, and returns are posted to accounts based on participants' fund allocation elections. Participants can change their fund allocations as of the end of any day on which the market is open.
The DCP allows participants to maintain three accounts based upon when they want to receive payments: retirement account, in-service account and education account. Both the retirement and in-service accounts can be distributed as lump sums or in up to 10 annual installments, except in the case of the four DCP transition accounts that allow for a grandfathered payout based on the previous deferred compensation plan distribution elections of lump sum, 5, 10 or 15 annual installments. Effective December 31, 2006, no new money may be deferred into the DCP transition accounts. The education account is distributed in four annual installments. If a participant leaves employment prior to retirement (age 55), all amounts in the participant's account will be paid out in a lump sum as soon as administratively practicable. Participants are 100% vested in their deferrals and any investment gains or losses recorded in their accounts.
Participants in PacifiCorp's LTIP also have the option of deferring all or a part of those awards after the four-year mandatory deferral and vesting period. The provisions governing the deferral of LTIP awards are similar to those described for the DCP above.
Potential Payments Upon Termination
PacifiCorp's NEOs, other than the Chairman and CEO, are not generally entitled to severance or enhanced benefits upon termination of employment or change in control.
The following table sets forth the estimated increase in the present value of benefits pursuant to the termination scenarios indicated for PacifiCorp's NEOs, other than Mr. Fehrman. Payments or benefits that are not enhanced in form or amount upon the occurrence of a particular termination scenario, which include 401(k) and nonqualified deferred compensation account balances and those portions of long-term incentive payments that would have otherwise been paid, are not included herein. All estimated payments reflected in the table below assume termination on December 31, 2020 and are payable as lump sums unless otherwise noted.
(1)Amounts represent the unvested portion of each NEO's LTIP account, which becomes 100% vested under certain circumstances.
(2)Pension values represent the excess of the present value of benefits payable under each termination scenario over the amount already reflected in the Pension Benefits table.
Chief Executive Officer Pay Ratio
PacifiCorp's CEO receives no direct compensation from PacifiCorp, and no amounts are reported for the CEO in the Summary Compensation Table. Accordingly, PacifiCorp has determined that the CEO pay ratio is not calculable.
Director Compensation
PacifiCorp's directors do not receive additional compensation for service as directors of PacifiCorp. Compensation information for Messrs. Fehrman, Bird, Hoogeveen, and Ms. Kobliha for their services as executive officers of PacifiCorp is described above.
Compensation Committee Interlocks and Insider Participation
Mr. Fehrman is PacifiCorp's Chairman and CEO and also the President and Chief Executive Officer of BHE. None of PacifiCorp's executive officers serves as a member of the compensation committee of any company that has an executive officer serving as a member of PacifiCorp's Board of Directors. None of PacifiCorp's executive officers serves as a member of the board of directors of any company (other than BHE) that has an executive officer serving as a member of PacifiCorp's compensation committee. See also PacifiCorp's Item 13 in this Annual Report on Form 10-K.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 12 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Beneficial Ownership
PacifiCorp is a consolidated subsidiary of BHE. PacifiCorp's common stock is indirectly owned by BHE, 666 Grand Avenue, Suite 500, Des Moines, Iowa 50309-2580. BHE is a consolidated subsidiary of Berkshire Hathaway that, as of January 31, 2021, owns 91.1% of BHE's common stock. The balance of BHE's common stock is beneficially owned by Walter Scott, Jr. (along with his family members and related or affiliated entities), a member of BHE's Board of Directors, and Gregory E. Abel, BHE's Chairman.
None of PacifiCorp's executive officers or directors owns shares of its preferred stock. The following table sets forth certain information regarding the beneficial ownership of BHE's common stock and the Class A and Class B shares of Berkshire Hathaway common stock held by each of PacifiCorp's directors, executive officers and all of its directors and executive officers as a group as of January 31, 2021:
* Indicates beneficial ownership of less than one percent of all outstanding shares.
(1)Includes shares of which the listed beneficial owner is deemed to have the right to acquire beneficial ownership under Rule 13d-3(d) under the Securities Exchange Act, including, among other things, shares which the listed beneficial owner has the right to acquire within 60 days.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN FUNDING, MIDAMERICAN ENERGY, NEVADA POWER, SIERRA PACIFIC AND EASTERN ENERGY GAS
Information required by Item 13 is omitted pursuant to General Instruction I(2)(c) to Form 10-K.
PACIFICORP
Certain Relationships and Related Transactions
The Berkshire Hathaway Inc. Code of Business Conduct and Ethics and the BHE Code of Business Conduct, or the Codes, which apply to all of PacifiCorp's directors, officers and employees and those of its subsidiaries, generally govern the review, approval or ratification of any related-person transaction. A related-person transaction is one in which PacifiCorp or any of its subsidiaries participate and in which one or more of PacifiCorp's directors, executive officers, holders of more than five percent of its voting securities or any of such persons' immediate family members have a direct or indirect material interest.
Under the Codes, all of PacifiCorp's directors and executive officers (including those of its subsidiaries) must disclose to PacifiCorp's legal department any material transaction or relationship that reasonably could be expected to give rise to a conflict with its interests. No action may be taken with respect to such transaction or relationship until approved by the legal department. For PacifiCorp's chief executive officer and chief financial officer, prior approval for any such transaction or relationship must be given by Berkshire Hathaway's audit committee. In addition, prior legal department approval must be obtained before a director or executive officer can accept employment, offices or board positions in other for-profit businesses, or engage in his or her own business that raises a potential conflict or appearance of conflict with PacifiCorp's interests.
Under an intercompany administrative services agreement PacifiCorp has entered into with BHE and its other subsidiaries, the costs of certain administrative services provided by BHE to PacifiCorp or by PacifiCorp to BHE, or shared with BHE and other subsidiaries, are directly charged or allocated to the entity receiving such services. This agreement has been filed with the regulatory commissions in the states where PacifiCorp serves retail customers. PacifiCorp also provides an annual report of all transactions with its affiliates to its state regulatory commissions, who have the authority to refuse recovery in rates for payments PacifiCorp makes to its affiliates deemed to have the effect of subsidizing the separate business activities of BHE or its other subsidiaries.
Refer to Note 21 of the Notes to the Consolidated Financial Statements of PacifiCorp in Item 8 of this Form 10-K for additional information regarding related-party transactions.
Director Independence
Because PacifiCorp's common stock is indirectly, wholly owned by BHE and its Board of Directors consists of BHE and PacifiCorp employees, PacifiCorp is not required to have independent directors or audit, nominating or compensation committees consisting of independent directors.
Based on the standards of the New York Stock Exchange LLC, on which the common stock of PacifiCorp's ultimate parent company, Berkshire Hathaway, is listed, PacifiCorp's Board of Directors has determined that none of its directors are considered independent because of their employment by BHE or PacifiCorp.
Item 14.
Item 14. Principal Accountant Fees and Services
The following table shows the fees paid or accrued by each Registrant for audit and audit-related services and fees paid for tax and all other services rendered by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu Limited, and their respective affiliates (collectively, the "Deloitte Entities") for each of the last two years (in millions):
(1)The reported fees for Berkshire Hathaway Energy include those fees reported for PacifiCorp, MidAmerican Funding, Nevada Power, Sierra Pacific and Eastern Energy Gas (since November 1, 2020 acquisition date totaling $0.9 million) while the reported fees for MidAmerican Funding include those fees reported for MidAmerican Energy.
(2)Audit fees include fees for the audit of the consolidated financial statements and interim reviews of the quarterly financial statements for each Registrant, audit services provided in connection with required statutory audits of certain of BHE's subsidiaries and comfort letters, consents and other services related to SEC matters for each Registrant.
(3)Audit-related fees primarily include fees for assurance and related services for any other statutory or regulatory requirements, audits of certain employee benefit plans and consultations on various accounting and reporting matters.
(4)Tax fees include fees for services relating to tax compliance, tax planning and tax advice. These services include assistance regarding federal, state and international tax compliance, tax return preparation and tax audits.
The audit committee has considered whether the non-audit services provided to the Registrants by the Deloitte Entities impaired the independence of the Deloitte Entities and concluded that they did not. All of the services performed by the Deloitte Entities were pre-approved in accordance with the pre-approval policy adopted by the audit committee. The policy provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by the Deloitte Entities to the Registrants. The policy (a) identifies the guiding principles that must be considered by the audit committee in approving services to ensure that the Deloitte Entities' independence is not impaired; (b) describes the audit, audit-related and tax services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, requests to provide services that require specific approval by the audit committee will be submitted to the audit committee by both the Registrants' independent auditor and BHE's Chief Financial Officer. All requests for services to be provided by the independent auditor that do not require specific approval by the audit committee will be submitted to BHE's Chief Financial Officer and must include a detailed description of the services to be rendered. BHE's Chief Financial Officer will determine whether such services are included within the list of services that have received the general pre-approval of the audit committee. The audit committee will be informed on a timely basis of any such services rendered by the independent auditor.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)Financial Statements and Schedules
(1)Financial Statements
The financial statements of all Registrants are included in their respective Item 8 of this Form 10-K.102
(2)Financial Statement Schedules
BHE Parent Company Only Condensed Financial Statements (Schedule I)
BHE Valuation and Qualifying Accounts (Schedule II)
MidAmerican Funding, LLC Parent Company Only Condensed Financial Statements (Schedule I)
MidAmerican Energy Company Valuation and Qualifying Accounts (Schedule II)
MidAmerican Funding, LLC and Subsidiaries; Consolidated Valuation and Qualifying Accounts (Schedule II)
Schedules not listed above have been omitted because they are either not applicable, not required or the information required to be set forth therein is included on the Consolidated Financial Statements or notes thereto.
(3)Management contracts or compensatory plans are identified by an asterisk in the Exhibit Index filed as part of this Annual Report.
(b)Exhibits
The exhibits listed on the accompanying Exhibit Index are filed as part of this Annual Report.
Item 16. Form 10-K Summary
None.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Amounts in millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
BERKSHIRE HATHAWAY ENERGY COMPANY
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Basis of Presentation - The condensed financial information of BHE investments in subsidiaries are presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in subsidiaries are recorded in the Condensed Balance Sheets. The income from operations of subsidiaries is reported on a net basis as equity income in the Condensed Statements of Operations.
Other investments - BHE's investment in BYD Company Limited ("BYD") common stock is accounted for as a marketable security with changes in fair value recognized in net income. As of December 31, 2020 and 2019, the fair value of BHE's investment in BYD common stock was $5,897 million and $1,122 million.
Dividends and distributions from subsidiaries - Cash dividends paid to BHE by its subsidiaries for the years ended December 31, 2020, 2019 and 2018 were $2.0 billion, $2.0 billion and $2.3 billion, respectively. In January and February 2021, BHE received cash dividends from its subsidiaries totaling $131 million.
Guarantees and commitments - BHE has issued guarantees and letters of credit in respect of subsidiary and equity method investments aggregating $1.3 billion and commitments, subject to satisfaction of certain specified conditions, to provide equity contributions in support of renewable tax equity investments totaling $563 million.
See the notes to the consolidated BHE financial statements in Part II, Item 8 for other disclosures regarding long-term obligations (Notes 9, 10 and 11) and shareholders' equity (Note 18).
Schedule II
BERKSHIRE HATHAWAY ENERGY COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2020
(Amounts in millions)
The notes to the consolidated BHE financial statements are an integral part of this financial statement schedule.
(1)Reserves not deducted from assets relate primarily to estimated liabilities for losses retained by BHE for workers compensation, public liability and property damage claims.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED BALANCE SHEETS
(Amounts in millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF OPERATIONS
(Amounts in millions)
The accompanying notes are an integral part of this financial statement schedule.
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
CONDENSED STATEMENTS OF CASH FLOWS
(In millions)
The accompanying notes are an integral part of this financial statement schedule.
Schedule I
MIDAMERICAN FUNDING, LLC
PARENT COMPANY ONLY
NOTES TO CONDENSED FINANCIAL STATEMENTS
Incorporated by reference are MidAmerican Funding, LLC and Subsidiaries Consolidated Statements of Changes in Equity for the three years ended December 31, 2020 in Part II, Item 8.
Basis of Presentation - The condensed financial information of MidAmerican Funding, LLC's ("MidAmerican Funding's") investments in subsidiaries is presented under the equity method of accounting. Under this method, the assets and liabilities of subsidiaries are not consolidated. The investments in and advances to subsidiaries are recorded on the Condensed Balance Sheets. The income from operations of the subsidiaries is reported on a net basis as equity in undistributed earnings of subsidiary companies on the Condensed Statements of Operations. The Condensed Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the years ended December 31, 2020, 2019 and 2018.
Payable to Affiliate - MHC, Inc. ("MHC") settles all obligations of MidAmerican Funding including primarily interest costs on, and repayments of, MidAmerican Funding's long-term debt and income taxes. MHC paid $12 million and $12 million in 2020 and 2019, respectively, and received $2 million in 2018 on behalf of MidAmerican Funding. In 2019, MHC transferred to MidAmerican Funding $440 million of its receivable from MidAmerican Funding in the form of a dividend.
Distribution to Parent - In 2019, MidAmerican Funding recorded a noncash dividend of $8 million for the transfer to BHE of corporate aircraft owned by MHC.
See the notes to the consolidated MidAmerican Funding financial statements in Part II, Item 8 for other disclosures.
Schedule II
MIDAMERICAN ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2020
(Amounts in millions)
(1)Reserves not deducted from assets include estimated liabilities for losses retained by MidAmerican Energy for workers compensation, public liability and property damage claims.
Schedule II
MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 2020
(Amounts in millions)
(1)Reserves not deducted from assets include primarily estimated liabilities for losses retained by MidAmerican Funding and MHC for workers compensation, public liability and property damage claims.
EXHIBIT INDEX
Exhibit No. Description
BERKSHIRE HATHAWAY ENERGY
2.1Purchase and Sale Agreement, dated as of July 3, 2020, by and among Dominion Energy, Inc., Dominion Energy Questar Corporation and Berkshire Hathaway Energy Company (incorporated by reference to Exhibit 2.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated July 6, 2020).
2.2Purchase and Sale Agreement, dated as of October 5, 2020, by and between Dominion Energy Questar Corporation, Dominion Energy, Inc. and Berkshire Hathaway Energy Company (incorporated by reference to Exhibit 2.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated October 6, 2020).
3.1Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective March 2, 2006 (incorporated by reference to Exhibit 3.1 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
3.2Articles of Amendment to the Second Amended and Restated Articles of Incorporation of MidAmerican Energy Holdings Company effective April 30, 2014 (incorporated by reference to Exhibit 3.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
3.3Third Amended and Restated Articles of Incorporation of Berkshire Hathaway Energy Company, effective as of October 27, 2020 (incorporated by reference to Exhibit 3.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated November 2, 2020).
3.4Amended and Restated Bylaws of Berkshire Hathaway Energy Company (incorporated by reference to Exhibit 3.2 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.1Shareholders Agreement, dated as of March 14, 2000 (incorporated by reference to Exhibit 4.19 to the Berkshire Hathaway Energy Company Registration Statement No. 333-101699 dated December 6, 2002).
4.2Amendment No. 1 to Shareholders Agreement, dated December 7, 2005 (incorporated by reference to Exhibit 4.17 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.3Indenture, dated as of October 4, 2002, by and between MidAmerican Energy Holdings Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Registration Statement No. 333-101699 dated December 6, 2002).
4.4Fourth Supplemental Indenture, dated as of March 24, 2006, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.125% Senior Bonds due 2036 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 28, 2006).
4.5Fifth Supplemental Indenture, dated as of May 11, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 5.95% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated May 11, 2007).
4.6Sixth Supplemental Indenture, dated as of August 28, 2007, by and between MidAmerican Energy Holdings Company and The Bank of New York Trust Company, N.A., Trustee, relating to the 6.50% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated August 28, 2007).
4.7Ninth Supplemental Indenture, dated as of November 8, 2013, by and between MidAmerican Energy Holdings Company and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 3.750% Senior Notes due 2023 and the 5.150% Senior Notes due 2043 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated November 8, 2013).
Exhibit No. Description
4.8Tenth Supplemental Indenture, dated as December 4, 2014, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 2.40% Senior Notes due 2020, the 3.50% Senior Notes due 2025 and the 4.50% Senior Notes due 2045 (incorporated by reference to Exhibit 4.8 to the Berkshire Hathaway Energy Company Registration Statement No. 333-200928 dated December 12, 2014).
4.9Eleventh Supplemental Indenture, dated as of December 29, 2017, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 6.50% Senior Bonds due 2037 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated January 5, 2018).
4.10Twelfth Supplemental Indenture, dated as of January 5, 2018, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 2.375% Senior Notes due 2021, the 2.80% Senior Notes due 2023, the 3.25% Senior Notes due 2028 and the 3.80% Senior Notes due 2048 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated January 5, 2018).
4.11Thirteenth Supplemental Indenture, dated as of July 25, 2018, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 4.45% Senior Notes due 2049 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
4.12Fourteenth Supplemental Indenture, dated as of March 24, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 4.05% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 25, 2020).
4.13Fifteenth Supplemental Indenture, dated as of March 27, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 3.70% Senior Notes due 2030 and the 4.25% Senior Notes due 2050 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 27, 2020).
4.14Sixteenth Supplemental Indenture, dated as of October 29, 2020, by and between Berkshire Hathaway Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee, relating to the 1.650% Senior Notes due 2031 and the 2.850% Senior Notes due 2051 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated November 2, 2020).
4.15Indenture, dated as of October 15, 1997, by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated October 23, 1997).
4.16Form of Second Supplemental Indenture, dated as of September 22, 1998 by and between MidAmerican Energy Holdings Company and IBJ Schroder Bank & Trust Company, Trustee, relating to the 8.48% Senior Notes due 2028 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated September 17, 1998).
4.17Trust Deed, dated December 15, 1997 among CE Electric UK Funding Company, AMBAC Insurance UK Limited and The Law Debenture Trust Corporation, p.l.c., Trustee (incorporated by reference to Exhibit 99.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 30, 2004).
4.18Insurance and Indemnity Agreement, dated December 15, 1997 by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.2 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 30, 2004).
4.19Supplemental Agreement to Insurance and Indemnity Agreement, dated September 19, 2001, by and between CE Electric UK Funding Company and AMBAC Insurance UK Limited (incorporated by reference to Exhibit 99.3 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated March 30, 2004).
4.20Trust Deed, dated as of February 4, 1998 among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.74 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
Exhibit No. Description
4.22First Supplemental Trust Deed, dated as of October 1, 2001, among Yorkshire Power Finance Limited, Yorkshire Power Group Limited and Bankers Trustee Company Limited, Trustee, relating to the £200,000,000 in principal amount of the 7.25% Guaranteed Bonds due 2028 (incorporated by reference to Exhibit 10.75 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2004).
4.23Trust Deed dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.24Reimbursement and Indemnity Agreement, dated May 5, 2005 among Northern Electric Finance plc, Northern Electric Distribution Limited and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.25Trust Deed, dated May 5, 2005 among Yorkshire Electricity Distribution plc, Ambac Assurance UK Limited and HSBC Trustee (C.I.) Limited (incorporated by reference to Exhibit 99.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.27Reimbursement and Indemnity Agreement, dated May 5, 2005 between Yorkshire Electricity Distribution plc and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.4 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.27Supplemental Trust Deed, dated May 5, 2005 among CE Electric UK Funding Company, Ambac Assurance UK Limited and The Law Debenture Trust Corporation plc (incorporated by reference to Exhibit 99.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.28Second Supplemental Agreement to Insurance and Indemnity Agreement, dated May 5, 2005 by and between CE Electric UK Funding Company and Ambac Assurance UK Limited (incorporated by reference to Exhibit 99.6 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2005).
4.29£119,000,000 Finance Contract, dated July 2, 2010, by and between Northern Electric Distribution Limited and the European Investment Bank (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2010).
4.30Guarantee and Indemnity Agreement, dated July 2, 2010, by and between CE Electric UK Funding Company and the European Investment Bank (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2010).
4.31£151,000,000 Finance Contract, dated July 2, 2010, by and between Yorkshire Electricity Distribution plc and the European Investment Bank (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2010).
4.33Guarantee and Indemnity Agreement, dated July 2, 2010, by and between CE Electric UK Funding Company and the European Investment Bank (incorporated by reference to Exhibit 4.4 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2010).
4.33Trust Deed, dated as of July 5, 2012, among Northern Powergrid (Yorkshire) plc and HSBC Corporate Trustee Company (UK) Limited, relating to the £150,000,000 in principal amount of the 4.375% Bonds due 2032 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2012).
4.34Trust Deed, dated as of April 1, 2015, among Northern Powergrid (Yorkshire) plc and HSBC Corporate Trustee Company (UK) Limited, relating to the £150,000,000 in principal amount of the 2.50% Bonds due 2025 (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).
4.35£120,000,000 Finance Contract, dated December 2, 2015, by and between Northern Powergrid (Northeast) Ltd and the European Investment Bank (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
Exhibit No. Description
4.36Guarantee and Indemnity Agreement, dated December 8, 2015, by and between Northern Powergrid Holdings Company and the European Investment Bank (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
4.38£130,000,000 Finance Contract, dated December 2, 2015, by and between Northern Powergrid (Yorkshire) plc and the European Investment Bank (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
4.39Guarantee and Indemnity Agreement, dated December 8, 2015, by and between Northern Powergrid Holdings Company and the European Investment Bank (incorporated by reference to Exhibit 4.4 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
4.40Deed of Amendment and Consent, dated March 1, 2016, by and between Northern Powergrid Holdings Company, Northern Powergrid (Yorkshire) plc and the European Investment Bank (incorporated by reference to Exhibit 4.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2016).
4.41Trust Deed, dated as of May 24, 2019, among Northern Electric Finance plc, Northern Powergrid (Northeast) Limited, and HSBC Corporate Trustee Company (UK) Limited, relating to the £150,000,000 in principal amount of the 2.75% Guaranteed Bonds due 2049 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
4.41Trust Deed, dated as of October 9, 2019, among Northern Powergrid (Yorkshire) plc and HSBC Corporate Trustee Company (UK) Limited, relating to the £300,000,000 in principal amount of the 2.25% Guaranteed Bonds due 2059 (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
4.43Trust Deed, dated as of June 16, 2020, by and between Northern Powergrid (Northeast) plc and HSBC Corporate Trustee Company (UK) Limited, Trustee, relating to the £300,000,000 in principal amount of 1.875% Green Bonds due 2062 (incorporated by reference to Exhibit 4.3 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
4.44Fiscal Agency Agreement, dated as of April 20, 2011, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $200,000,000 in principal amount of the 4.25% Senior Notes due 2021 (incorporated by reference to Exhibit 4.27 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2011).
4.45Fiscal Agency Agreement, dated February 12, 2007, by and between Northern Natural Gas Company and The Bank of New York Trust Company, N.A., Fiscal Agent, relating to the $150,000,000 in principal amount of the 5.80% Senior Bonds due 2037 (incorporated by reference to Exhibit 99.1 to the Berkshire Hathaway Energy Company Current Report on Form 8-K dated February 12, 2007).
4.45Fiscal Agency Agreement, dated August 27, 2012, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $250,000,000 in principal amount of the 4.10% Senior Bonds due 2042 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2012).
4.46Fiscal Agency Agreement, dated as of July 12, 2018, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the $450,000,000 in principal amount of the 4.30% Senior Bonds due 2049 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2018).
4.47Amendment No. 1 to the Fiscal Agency Agreement, dated as of July 17, 2018, by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to an additional $200,000,000 in principal amount of the 4.30% Senior Bonds due 2049 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
4.48Master Trust Indenture, dated November 21, 2005, by and between AltaLink Investments, L.P., AltaLink Investment Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.94 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
Exhibit No. Description
4.53Third Supplemental Indenture, dated December 15, 2010, by and between AltaLink Investments, L.P., AltaLink Investment Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.96 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.50Series 15-1 Supplemental Indenture, dated March 6, 2015, by and between AltaLink Investments, L.P., AltaLink Investment Management Ltd. and BNY Trust Company of Canada, relating to C$200,000,000 in principal amount of the 2.244% Series 15-1 Senior Bonds due 2022 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).
4.512016 Supplemental Indenture, dated December 9, 2016, by and between AltaLink Investments, L.P., AltaLink Investment Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.53 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2016).
4.52Amended and Restated Master Trust Indenture, dated April 28, 2003, by and between AltaLink, L.P., AltaLink Management Ltd. and BMO Trust Company (incorporated by reference to Exhibit 4.99 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.53Seventh Supplemental Indenture, dated April 28, 2003, by and between AltaLink, L.P., AltaLink Management Ltd. and BMO Trust Company (incorporated by reference to Exhibit 4.100 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.54Ninth Supplemental Indenture, dated May 9, 2006, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.101 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.55Tenth Supplemental Indenture, dated May 21, 2008, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.102 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.56Twelfth Supplemental Indenture, dated August 18, 2010, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.103 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.57Sixteenth Supplemental Indenture, dated November 15, 2012, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.104 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.58Seventeenth Supplemental Indenture, dated May 22, 2013, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.105 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.59Eighteenth Supplemental Indenture, dated October 24, 2014, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.106 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.60Nineteenth Supplemental Indenture, dated October 24, 2014, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.107 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
4.61Twentieth Supplemental Indenture, dated June 30, 2015, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, relating to C$350,000,000 in principal amount of the 4.09% Series 2015-1 Medium-Term Notes due 2045 (incorporated by reference to Exhibit 4.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2015).
4.62Twenty-First Supplemental Indenture, dated December 14, 2018, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada (incorporated by reference to Exhibit 4.64 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2018).
4.64Twenty-Third Supplemental Indenture, dated as of September 11, 2020, by and between AltaLink, L.P., AltaLink Management Ltd. and BNY Trust Company of Canada, as trustee, relating to the C$225,000,000 in principal amount of the 1.509% Series 2020-1 Senior Secured Notes due 2021 (incorporated by reference to Exhibit 4.5 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
Exhibit No. Description
4.64Indenture, dated as of February 24, 2012, by and between Topaz Solar Farms LLC and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the $850,000,000 in principal amount of the 5.75% Series A Senior Secured Notes due 2039 (incorporated by reference to Exhibit 4.56 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2011).
4.65First Supplemental Indenture, dated as of April 15, 2013, between Topaz Solar Farms LLC, as Issuer, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the $250,000,000 in principal amount of the 4.875% Series B Senior Secured Notes due 2039 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).
4.66Indenture, dated as of June 27, 2013, between Solar Star Funding, LLC, as Issuer, and Wells Fargo Bank, National Association, as Trustee, relating to the $1,000,000,000 in principal amount of the 5.375% Series A Senior Secured Notes due 2035 (incorporated by reference to Exhibit 4.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2013).
4.67First Supplemental Indenture, dated as of March 12, 2015, between Solar Star Funding, LLC, as Issuer, and Wells Fargo Bank, National Association, as Trustee, relating to the $325,000,000 in principal amount of the 3.95% Series B Senior Secured Notes due 2035 (incorporated by reference to Exhibit 4.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2015).
10.1$3,500,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among Berkshire Hathaway Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, MUFG Union Bank, N.A, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.2Amended and Restated £150,000,000 Facility Agreement, dated as of October 18, 2019, among Northern Powergrid Holdings Company, as Guarantor, Northern Powergrid (Yorkshire) plc and Northern Powergrid (Northeast) Limited, as Borrowers, and Santander UK plc, Lloyds Bank plc and National Westminster Bank plc, as Original Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2019).
10.3Amended and Restated Credit Agreement, dated as of January 24, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.3 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2019).
10.4Fourth Amended and Restated Credit Agreement, dated as of January 24, 2020, among AltaLink, L.P., as borrower, AltaLink Management, Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.5 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2019).
10.5Fifth Amended and Restated Credit Agreement, dated as of January 24, 2020, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.4 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2019).
10.6Credit Agreement, dated as of April 27, 2020, among AltaLink, L.P., as borrower, AltaLink Management Ltd., as general partner, The Bank of Nova Scotia, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.1 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.7Credit Agreement, dated as of April 27, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders (incorporated by reference to Exhibit 10.2 to the Berkshire Hathaway Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
10.8Berkshire Hathaway Energy Company Executive Voluntary Deferred Compensation Plan restated effective as of January 1, 2007 (incorporated by reference to Exhibit 10.9 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2007).
10.9Berkshire Hathaway Energy Company Long-Term Incentive Partnership Plan as Amended and Restated January 1, 2014 (incorporated by reference to Exhibit 10.9 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2014).
Exhibit No. Description
14.1Berkshire Hathaway Energy Company Code of Ethics For Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to the Berkshire Hathaway Energy Company Annual Report on Form 10-K for the year ended December 31, 2015).
21.1Subsidiaries of the Registrant.
23.1Consent of Deloitte & Touche LLP.
24.1Power of Attorney.
31.1Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
PACIFICORP
3.5Third Restated Articles of Incorporation of PacifiCorp (incorporated by reference to Exhibit (3)a to the PacifiCorp Annual Report on Form 10-K for the year ended December 31, 1996).
3.6Bylaws of PacifiCorp, as amended May 23, 2005 (incorporated by reference to Exhibit 3.2 to the PacifiCorp Annual Report on Form 10-K for the year ended March 31, 2005).
10.10*Summary of Key Terms of Compensation Arrangements with PacifiCorp's Named Executive Officers and Directors.
10.11*PacifiCorp Executive Voluntary Deferred Compensation Plan (incorporated by reference to Exhibit 10.3 to the PacifiCorp Annual Report on Form 10-K for the year ended December 31, 2007).
10.12*Supplemental Executive Retirement Plan (incorporated by reference to Exhibit 10.7 to the PacifiCorp Annual Report on Form 10-K for the year ended March 31, 2005).
10.13*Amendment No. 10 to PacifiCorp Supplemental Executive Retirement Plan dated June 2, 2006 (incorporated by reference to Exhibit 10.5 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
10.14*Amendment No. 11 to PacifiCorp Supplemental Executive Retirement Plan dated June 2, 2006 (incorporated by reference to Exhibit 10.6 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
10.15*Amendment No. 1 to the PacifiCorp Executive Voluntary Deferred Compensation Plan dated October 28, 2008 (incorporated by reference to Exhibit 10.10 to the PacifiCorp Annual Report on Form 10-K for the year ended December 31, 2009).
10.16*Amendment No. 2 to the PacifiCorp Executive Voluntary Deferred Compensation Plan dated October 16, 2012 (incorporated by reference to Exhibit 10.11 to the PacifiCorp Annual Report on Form 10-K for the year ended December 31, 2012).
10.17*PacifiCorp Long Term Incentive Partnership Plan effective January 1, 2014 and Restated Effective December 1, 2019 (incorporated by reference to Exhibit 10.15 to the PacifiCorp Annual Report on Form 10-K for the year ended December 31, 2019).
14.2Code of Ethics (incorporated by reference to Exhibit 14.1 to the PacifiCorp Transition Report on Form 10-K for the nine-month period ended December 31, 2006).
23.2Consent of Deloitte & Touche LLP.
31.3Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.3Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.4Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit No. Description
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.68Mortgage and Deed of Trust dated as of January 9, 1989, between PacifiCorp and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, incorporated by reference to Exhibit 4-E to the PacifiCorp Form 8-B, as supplemented and modified by 31 Supplemental Indentures, each incorporated by reference, as follows:
10.18$600,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.2 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.19$600,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among PacifiCorp, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, JPMorgan Chase Bank, N.A., as Administrative Agent, and the LC Issuing Banks (incorporated by reference to Exhibit 10.3 to the PacifiCorp Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
95Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Exhibit No. Description
MIDAMERICAN ENERGY
3.7Restated Articles of Incorporation of MidAmerican Energy Company, as amended October 27, 1998. (incorporated by reference to Exhibit 3.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 1998).
3.8Restated Bylaws of MidAmerican Energy Company, as amended July 24, 1996. (incorporated by reference to Exhibit 3.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 1996).
14.3Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. (incorporated by reference to Exhibit 14.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2003).
23.3Consent of Deloitte & Touche LLP.
31.5Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.6Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.5Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.6Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
MIDAMERICAN FUNDING
3.9Articles of Organization of MidAmerican Funding, LLC (incorporated by reference to Exhibit 3.1 to the MidAmerican Funding, LLC Registration Statement No. 333-90553 dated November 8, 1999).
3.10Operating Agreement of MidAmerican Funding, LLC (incorporated by reference to Exhibit 3.2 to the MidAmerican Funding, LLC Registration Statement No. 333-90553 dated November 8, 1999).
3.11Amendment No. 1 to the Operating Agreement of MidAmerican Funding, LLC dated as of February 9, 2010 (incorporated by reference to Exhibit 3.3 to the MidAmerican Funding, LLC Annual Report on Form 10-K for the year ended December 31, 2009).
14.4Code of Ethics for Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (incorporated by reference to Exhibit 14.2 to the MidAmerican Funding, LLC Annual Report on Form 10-K for the year ended December 31, 2003).
31.7Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.8Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.7Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.8Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY, MIDAMERICAN ENERGY AND MIDAMERICAN FUNDING
4.69Form of Indenture, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Registration Statement No. 333-59760 dated January 31, 2002).
4.70First Supplemental Indenture, dated as of February 8, 2002, by and between MidAmerican Energy Company and The Bank of New York, Trustee (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2004).
4.71Fourth Supplemental Indenture, dated November 1, 2005, by and between MidAmerican Energy Company and The Bank of New York Trust Company, NA, Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2005).
4.72Indenture, dated as of October 1, 2006, by and between MidAmerican Energy Company and The Bank of New York Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
Exhibit No. Description
4.73First Supplemental Indenture, dated as of October 6, 2006, by and between MidAmerican Energy Company and The Bank of New York Trust Company, N.A., Trustee relating to the 5.80% Notes due 2036 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2006).
4.74Indenture, dated as of September 9, 2013, between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated September 13, 2013).
4.75First Supplemental Indenture, dated as of September 19, 2013, between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated September 19, 2013).
4.76Specimen of 3.70% First Mortgage Bonds due 2023 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated September 19, 2013).
4.77Specimen of 4.80% First Mortgage Bonds due 2043 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated September 19, 2013).
4.78Amendment No. 1 to the First Supplemental Indenture, dated as of April 3, 2014, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated April 3, 2014).
4.79Second Supplemental Indenture, dated as of April 3, 2014, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated April 3, 2014).
4.80Specimen of 3.50% First Mortgage Bonds due 2024 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated April 3, 2014).
4.81Specimen of 4.40% First Mortgage Bonds due 2044 (incorporated by reference to Exhibit 4.5 to the MidAmerican Energy Company Current Report on Form 8-K dated April 3, 2014).
4.82Amendment No. 1 to the Second Supplemental Indenture, dated as of October 15, 2015, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2015).
4.83Third Supplemental Indenture, dated as of October 15, 2015, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2015).
4.84Specimen of 3.50% First Mortgage Bonds due 2024 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2015).
4.85Specimen of 4.25% First Mortgage Bonds due 2046 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2015).
4.86Fourth Supplemental Indenture, dated as of December 8, 2016, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.96 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2016).
4.87Fifth Supplemental Indenture, dated as of February 1, 2017, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated February 1, 2017).
4.88Specimen of 3.10% First Mortgage Bonds due 2027 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated February 1, 2017).
4.89Specimen of 3.95% First Mortgage Bonds due 2047 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated February 1, 2017).
Exhibit No. Description
4.90Sixth Supplemental Indenture, dated as of December 14, 2017, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.91 to the MidAmerican Energy Company Annual Report on Form 10-K for the year ended December 31, 2017).
4.91Seventh Supplemental Indenture, dated as of February 1, 2018, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated February 1, 2018).
4.92Specimen of 3.65% First Mortgage Bonds due 2048 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated February 1, 2018).
4.93Eighth Supplemental Indenture, dated January 9, 2019, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Current Report on Form 8-K dated January 9, 2019).
4.94Specimen of 3.65% First Mortgage Bonds due 2029 (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated January 9, 2019).
4.95Specimen of 4.25% First Mortgage Bonds due 2049 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated January 9, 2019).
4.96Amendment No. 1 to the Eighth Supplemental Indenture, dated as of October 15, 2019, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2019).
4.97Ninth Supplemental Indenture, dated as of October 15, 2019, by and between MidAmerican Energy Company and The Bank of New York Mellon Trust Company, N.A., to the Indenture dated as of September 9, 2013 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2019).
4.98Specimen of 3.15% First Mortgage Bond due 2050 (incorporated by reference to Exhibit 4.4 to the MidAmerican Energy Company Current Report on Form 8-K dated October 15, 2019).
4.99Mortgage, Security Agreement, Fixture Filing and Financing Statement, dated as of September 9, 2013, from MidAmerican Energy Company to The Bank of New York Mellon Trust Company, N.A., as collateral trustee (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Current Report on Form 8-K dated September 13, 2013).
4.100Intercreditor and Collateral Trust Agreement, dated as of September 9, 2013, among MidAmerican Energy Company, The Bank of New York Mellon Trust Company, N.A., as trustee, and The Bank of New York Mellon Trust Company, N.A., as collateral trustee (incorporated by reference to Exhibit 4.3 to the MidAmerican Energy Company Current Report on Form 8-K dated September 13, 2013).
4.101Form of Indenture, between MidAmerican Energy Company and the Trustee, (Senior Unsecured Debt Securities) (incorporated by reference to Exhibit 4.1 to the MidAmerican Energy Company Registration Statement No. 333-192077 dated November 4, 2013).
4.102Form of Indenture, between MidAmerican Energy Company and the Trustee, (Subordinated Unsecured Debt Securities) (incorporated by reference to Exhibit 4.2 to the MidAmerican Energy Company Registration Statement No. 333-192077 dated November 4, 2013).
10.20$900,000,000 Amended and Restated Credit Agreement, dated as of May 31, 2019, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Mizuho Bank, LTD., as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.4 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
10.21$600,000,000, 364-Day Credit Agreement, dated as of May 12, 2020, among MidAmerican Energy Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, and Mizuho Bank, Ltd., as Administrative Agent (incorporated by reference to Exhibit 10.3 to the MidAmerican Energy Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2020).
Exhibit No. Description
BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN FUNDING
4.103Indenture and First Supplemental Indenture, dated March 11, 1999, by and between MidAmerican Funding, LLC and IBJ Whitehall Bank & Trust Company, Trustee, relating to the $325 million Senior Bonds (incorporated by reference to Exhibits 4.1 and 4.2 to the MidAmerican Funding, LLC Registration Statement No. 333-905333 dated November 8, 1999).
NEVADA POWER
3.12Restated Articles of Incorporation of Nevada Power Company, dated July 28, 1999 (incorporated by reference to Exhibit 3(B) to the Nevada Power Company Annual Report on Form 10-K for the year ended December 31, 1999).
3.13Amended and Restated By-Laws of Nevada Power Company as amended December 21, 2017 (incorporated by reference to Exhibit 3.1 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
4.104Financing Agreement dated May 1, 2017 between Clark County, Nevada and Nevada Power Company (relating to Clark County, Nevada's $39,500,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Project) Series 2017) (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
4.105Financing Agreement dated May 1, 2017 between the Coconino County, Arizona Pollution Control Corporation and Nevada Power Company (relating to the Coconino County, Arizona Pollution Control Corporation's $53,000,000 Pollution Control Refunding Revenue Bonds (Nevada Power Company Projects) Series 2017A and 2017B) (incorporated by reference to Exhibit 4.2 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
10.22Transmission Use and Capacity Exchange Agreement between Nevada Power Company, Sierra Pacific Power Company and Great Basin Transmission, LLC dated August 20, 2010 (incorporated by reference to Exhibit 10.1 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2010).
14.5Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to the Nevada Power Company Annual Report on Form 10-K for the year ended December 31, 2013).
23.4Consent of Deloitte & Touche LLP.
31.9Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.10Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.9Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.10Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
4.106General and Refunding Mortgage Indenture, dated May 1, 2001, between Nevada Power Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.1(a) to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
4.107First Supplemental Indenture, dated as of May 1, 2001 (incorporated by reference to Exhibit 4.1(b) to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
4.108Second Supplemental Indenture, dated as of October 1, 2001 (incorporated by reference to Exhibit 4(A) to the Nevada Power Company Annual Report on Form 10-K for the year ended December 31, 2001).
4.109Officer's Certificate establishing the terms of Nevada Power Company's 6.65% General and Refunding Mortgage Notes, Series N, due 2036 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Form 10-Q for the quarter ended March 31, 2006).
Exhibit No. Description
4.110Officer's Certificate establishing the terms of Nevada Power Company's 6.75% General and Refunding Mortgage Notes, Series R, due 2037 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated June 27, 2007).
4.111Officer's Certificate establishing the terms of Nevada Power Company 5.375% General and Refunding Mortgage Notes, Series X, due 2040 (incorporated by reference to Exhibit 4.1 to Nevada Power Company Current Report on Form 8-K dated September 10, 2010).
4.112Officer's Certificate establishing the terms of Nevada Power Company 5.45% General and Refunding Mortgage Notes, Series Y, due 2041 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated May 10, 2011).
4.113Officer's Certificate establishing the terms of Nevada Power Company's General and Refunding Mortgage Notes, Series AA (Nos. AA-1 and AA-2) (incorporated by reference to Exhibit 4.3 to the Nevada Power Company Current Report on Form 8-K dated May 25, 2017).
4.114Officer's Certificate establishing the terms of Nevada Power Company's 3.70% General and Refunding Mortgage Notes, Series CC, due 2029 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated January 30, 2019).
4.115Officer's Certificate establishing the terms of Nevada Power Company's 2.40% General and Refunding Mortgage Notes, Series DD, due 2030 (incorporated by reference to Exhibit 4.1 to the Nevada Power Company Current Report on Form 8-K dated January 30, 2020).
4.116Officer's Certificate establishing the terms of Nevada Power Company's 3.125% General and Refunding Mortgage Notes, Series EE, due 2050 (incorporated by reference to Exhibit 4.2 to the Nevada Power Company Current Report on Form 8-K dated January 30, 2020).
10.23$400,000,000 Third Amended and Restated Credit Agreement, dated as of May 31, 2019, among Nevada Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.5 to the Nevada Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
SIERRA PACIFIC
3.14Restated Articles of Incorporation of Sierra Pacific Power Company, dated October 25, 2006 (incorporated by reference to Exhibit 3.1 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for quarter ended September 30, 2006).
3.15Amended and Restated By-Laws of Sierra Pacific Power Company as amended December 21, 2017 (incorporated by reference to Exhibit 3.2 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2018).
4.117Financing Agreement dated May 1, 2016 between Washoe County, Nevada and Sierra Pacific Power Company (relating to Washoe County, Nevada's $80,000,000 Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2016C, 2016D and 2016E) (incorporated by reference to Exhibit 4.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated May 24, 2016).
4.118Financing Agreement dated May 1, 2016 between Washoe County, Nevada and Sierra Pacific Power Company (relating to Washoe County, Nevada's $213,930,000 Gas Facilities Refunding Revenue Bonds, Gas and Water Facilities Refunding Revenue Bonds and Water Facilities Refunding Revenue Bonds (Sierra Pacific Power Company Projects) Series 2016A, 2016B, 2016F and 2016G (incorporated by reference to Exhibit 4.2 to the Sierra Pacific Power Company Current Report on Form 8-K dated May 24, 2016).
4.119Financing Agreement dated May 1, 2016 between Humboldt County, Nevada and Sierra Pacific Power Company (relating to Humboldt County, Nevada's $49,750,000 Pollution Control Refunding Revenue Bonds (Sierra Pacific Power Company Project) Series 2016A and 2016B (incorporated by reference to Exhibit 4.3 to the Sierra Pacific Power Company Current Report on Form 8-K dated May 24, 2016).
10.24Transmission Use and Capacity Exchange Agreement between Nevada Power Company, Sierra Pacific Power Company and Great Basin Transmission, LLC dated August 20, 2010 (incorporated by reference to Exhibit 10.1 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended September 30, 2010).
Exhibit No. Description
14.6Code of Ethics for Chief Executive Officer, Chief Financial Officer and Other Covered Officers (incorporated by reference to Exhibit 14.1 to the Sierra Pacific Power Company Annual Report on Form 10-K for the year ended December 31, 2013).
31.11Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.12Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.11Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.12Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
4.120General and Refunding Mortgage Indenture, dated as of May 1, 2001, between Sierra Pacific Power Company and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.2(a) to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
4.121Second Supplemental Indenture, dated as of October 30, 2006, to subject additional properties of Sierra Pacific Power Company located in the State of California to the lien of the General and Refunding Mortgage Indenture and to correct defects in the original Indenture (incorporated by reference to Exhibit 4(A) to the Sierra Pacific Power Company Annual Report on Form 10-K for the year ended December 31, 2006).
4.122Officer's Certificate establishing the terms of Sierra Pacific Power Company's 6.75% General and Refunding Mortgage Notes, Series P, due 2037 (incorporated by reference to Exhibit 4.2 to the Sierra Pacific Power Company Current Report on Form 8-K dated June 27, 2007).
4.123Officer's Certificate establishing the terms of Sierra Pacific Power Company's 3.375% General and Refunding Mortgage Notes, Series T, due 2023 (incorporated by reference to Exhibit 4.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated August 14, 2013).
4.124Officer's Certificate establishing the terms of Sierra Pacific Power Company's 2.60% General and Refunding Mortgage Notes, Series U, due 2026 (incorporated by reference to Exhibit 4.1 to the Sierra Pacific Power Company Current Report on Form 8-K dated April 15, 2016).
4.125Officer's Certificate establishing the terms of Sierra Pacific Power Company's General and Refunding Mortgage Notes, Series V (Nos. V-1, V-2 and V-3) (incorporated by reference to Exhibit 4.4 to the Sierra Pacific Power Company Current Report on Form 8-K dated May 24, 2016).
10.25$250,000,000 Third Amended and Restated Credit Agreement, dated as of May 31, 2019, among Sierra Pacific Power Company, as Borrower, the Banks, Financial Institutions and Other Institutional Lenders, as Initial Lenders, Wells Fargo Bank, National Association, as Administrative Agent and the LC Issuing Banks (incorporated by reference to Exhibit 10.6 to the Sierra Pacific Power Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2019).
EASTERN ENERGY GAS
3.16Articles of Organization of Dominion Energy Gas Holdings, LLC (incorporated by reference to Exhibit 3.1 to the Dominion Energy Gas Holdings, LLC Form S-4 dated April 4, 2014).
3.17Articles of Amendment to the Articles of Incorporation of Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 3.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 2, 2020).
3.18Operating Agreement of Eastern Energy Gas Holdings, LLC, as amended and restated, effective November 2, 2020 (incorporated by reference to Exhibit 3.2 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 2, 2020).
4.126Description of Eastern Energy Gas Holdings, LLC's Limited Liability Company Membership Interests (incorporated by reference to Exhibit 4.20 to the Dominion Energy Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2019).
10.26Distribution and Assumption Agreement (incorporated by reference to Exhibit 10.1 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 2, 2020).
Exhibit No. Description
10.27Distribution, Contribution and Assumption Agreement (incorporated by reference to Exhibit 10.2 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 2, 2020).
23.5Consent of Deloitte & Touche LLP.
31.13Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.14Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.13Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.14Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
BERKSHIRE HATHAWAY ENERGY AND EASTERN ENERGY GAS
4.127Indenture, dated as of October 1, 2013, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee (incorporated by reference to Exhibit 4.1, Form S-4, File No. 333-195066 dated April 4, 2014).
Exhibit No. Description
4.128Second Supplemental Indenture, dated as of October 1, 2013, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 3.55% Senior Notes due 2023 (incorporated by reference to Exhibit 4.3, Form S-4, File No. 333-195066 dated April 4, 2014).
4.129Third Supplemental Indenture, dated as of October 1, 2013, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 4.80% Senior Notes due 2043 (incorporated by reference to Exhibit 4.4, Form S-4, File No. 333-195066, dated April 4, 2014).
4.130Fifth Supplemental Indenture, dated as of December 1, 2014, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 3.60% Senior Notes due 2024 (incorporated by reference to Exhibit 4.3 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated December 8, 2014).
4.131Sixth Supplemental Indenture, dated as of December 1, 2014, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 4.60% Senior Notes due 2044 (incorporated by reference to Exhibit 4.4 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated December 8, 2014).
4.132Eighth Supplemental Indenture, dated as of May 1, 2016, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 3.80% Senior Notes due 2031 (incorporated by reference to Exhibit 4.1.a to the Eastern Energy Gas Holdings, LLC Form 10-Q for the quarter ended June 30, 2016).
4.133Ninth Supplemental Indenture, dated as of June 1, 2016, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 1.45% Senior Notes due 2026 (incorporated by reference to Exhibit 4.1.b to the Eastern Energy Gas Holdings, LLC Form 10-Q for the quarter ended June 30, 2016).
4.134Tenth Supplemental Indenture, dated as of June 1, 2016, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 2.875% Senior Notes due 2023 (incorporated by reference to Exhibit 4.1.c to the Eastern Energy Gas Holdings, LLC Form 10-Q for the quarter ended June 30, 2016).
4.135Eleventh Supplemental Indenture, dated June 1, 2018, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the Floating Rate Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated June 19, 2018).
4.136Twelfth Supplemental Indenture, dated November 1, 2019, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 2.50% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 21, 2019).
4.137Thirteenth Supplemental Indenture, dated November 1, 2019, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 3.0% Senior Notes due 2029 (incorporated by reference to Exhibit 4.3 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 21, 2019).
4.138Fourteenth Supplemental Indenture, dated November 1, 2019, by and between Dominion Energy Gas Holdings, LLC and Deutsche Bank Trust Company Americas, Trustee, relating to the 3.90% Senior Notes due 2049 (incorporated by reference to Exhibit 4.4 to the Eastern Energy Gas Holdings, LLC Current Report on Form 8-K dated November 21, 2019).
4.139Description of Dominion Energy Gas Holdings, LLC's 4.60% Series C Senior Notes due 2044 (incorporated by reference to Exhibit 4.21 to the Dominion Energy Gas Holdings, LLC Annual Report on Form 10-K for the year ended December 31, 2019).
10.28$400,000,000 Inter-Company Credit Agreement, dated as of November 1, 2020, by and between BHE GT&S, LLC and Eastern Energy Gas Holdings, LLC (incorporated by reference to Exhibit 10.3 to the Eastern Energy Gas Holdings, LLC Quarterly Report on Form 10-Q for the quarter ended September 30, 2020).
Exhibit No. Description
ALL REGISTRANTS
101The following financial information from each respective Registrant's Annual Report on Form 10-K for the year ended December 31, 2020 is formatted in iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.
104Cover Page Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.
(a) Not available electronically on the SEC website as it was filed in paper previous to the electronic system currently in place.
* Management contract or compensatory plan.
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, each Registrant has not filed as an exhibit to this Form 10-K certain instruments with respect to long-term debt not registered in which the total amount of securities authorized thereunder does not exceed 10% of the total assets of the respective Registrant. Each Registrant hereby agrees to furnish a copy of any such instrument to the Commission upon request.
SIGNATURES
BERKSHIRE HATHAWAY ENERGY COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
BERKSHIRE HATHAWAY ENERGY COMPANY
/s/ William J. Fehrman*
William J. Fehrman
Director, President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURES
PACIFICORP
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
PACIFICORP
/s/ Nikki L. Kobliha
Nikki L. Kobliha
Director, Vice President, Chief Financial Officer and
Treasurer
(principal financial and accounting officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURES
MIDAMERICAN ENERGY COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
MIDAMERICAN ENERGY COMPANY
/s/ Kelcey A. Brown
Kelcey A. Brown
Director, President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SignatureTitleDate
/s/ Kelcey A. BrownDirector, President and Chief Executive OfficerFebruary 26, 2021
Kelcey A. Brown(principal executive officer)
/s/ Thomas B. SpecketerDirector, Vice President and Chief Financial OfficerFebruary 26, 2021
Thomas B. Specketer(principal financial and accounting officer)
SIGNATURES
MIDAMERICAN FUNDING, LLC
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
MIDAMERICAN FUNDING, LLC
/s/ Kelcey A. Brown
Kelcey A. Brown
Manager and President
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SIGNATURES
NEVADA POWER COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
NEVADA POWER COMPANY
/s/ Douglas A. Cannon
Douglas A. Cannon
Director, President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SIGNATURES
SIERRA PACIFIC POWER COMPANY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
SIERRA PACIFIC POWER COMPANY
/s/ Douglas A. Cannon
Douglas A. Cannon
Director, President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SIGNATURES
EASTERN ENERGY GAS HOLDINGS, LLC
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on this 26th day of February 2021.
EASTERN ENERGY GAS HOLDINGS, LLC
/s/ Paul E. Ruppert
Paul E. Ruppert
President and Chief Executive Officer
(principal executive officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
No annual report to security holders covering each respective Registrant's last fiscal year or proxy material has been sent to security holders.