PACIFICORP /OR/ - Quarter Report: 2020 June (Form 10-Q)

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•	general economic, political and business conditions, as well as changes in, and compliance with, laws and regulations, including income tax reform, initiatives regarding deregulation and restructuring of the utility industry, and reliability and safety standards, affecting the respective Registrant's operations or related industries;

•	changes in, and compliance with, environmental laws, regulations, decisions and policies that could, among other items, increase operating and capital costs, reduce facility output, accelerate facility retirements or delay facility construction or acquisition;

•	the outcome of regulatory rate reviews and other proceedings conducted by regulatory agencies or other governmental and legal bodies and the respective Registrant's ability to recover costs through rates in a timely manner;

•	changes in economic, industry, competition or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and private generation measures and programs, that could affect customer growth and usage, electricity and natural gas supply or the respective Registrant's ability to obtain long-term contracts with customers and suppliers;

•	performance, availability and ongoing operation of the respective Registrant's facilities, including facilities not operated by the Registrants, due to the impacts of market conditions, outages and repairs, transmission constraints, weather, including wind, solar and hydroelectric conditions, and operating conditions;

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the effects of catastrophic and other unforeseen events, which may be caused by factors beyond the control of each respective Registrant or by a breakdown or failure of the Registrants' operating assets, including severe storms, floods, fires, earthquakes, explosions, landslides, an electromagnetic pulse, mining incidents, litigation, wars, terrorism, pandemics (including potentially in relation to COVID-19), embargoes, and cyber security attacks, data security breaches, disruptions, or other malicious acts;

•	a high degree of variance between actual and forecasted load or generation that could impact a Registrant's hedging strategy and the cost of balancing its generation resources with its retail load obligations;

•	changes in prices, availability and demand for wholesale electricity, coal, natural gas, other fuel sources and fuel transportation that could have a significant impact on generating capacity and energy costs;

•	the financial condition, creditworthiness and operational stability of the respective Registrant's significant customers and suppliers;

•	changes in business strategy or development plans;

•	availability, terms and deployment of capital, including reductions in demand for investment-grade commercial paper, debt securities and other sources of debt financing and volatility in interest rates;

•	changes in the respective Registrant's credit ratings;

•	risks relating to nuclear generation, including unique operational, closure and decommissioning risks;

•	hydroelectric conditions and the cost, feasibility and eventual outcome of hydroelectric relicensing proceedings;

•	the impact of certain contracts used to mitigate or manage volume, price and interest rate risk, including increased collateral requirements, and changes in commodity prices, interest rates and other conditions that affect the fair value of certain contracts;

•	the impact of inflation on costs and the ability of the respective Registrants to recover such costs in regulated rates;

•	fluctuations in foreign currency exchange rates, primarily the British pound and the Canadian dollar;

•	increases in employee healthcare costs;

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•	the impact of investment performance and changes in interest rates, legislation, healthcare cost trends, mortality and morbidity on pension and other postretirement benefits expense and funding requirements;

•	changes in the residential real estate brokerage, mortgage and franchising industries and regulations that could affect brokerage, mortgage and franchising transactions;

•	the ability to successfully integrate future acquired operations into a Registrant's business;

•	the expected timing and likelihood of completion of the proposed transaction with Dominion Energy, Inc., including the ability to obtain the required regulatory approvals and the terms and conditions of such regulatory approvals;

•	unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future facilities and infrastructure additions;

•	the availability and price of natural gas in applicable geographic regions and demand for natural gas supply;

•	the impact of new accounting guidance or changes in current accounting estimates and assumptions on the financial results of the respective Registrants; and

•	other business or investment considerations that may be disclosed from time to time in the Registrants' filings with the SEC or in other publicly disseminated written documents.

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Item 1.	Financial Statements

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Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

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Item 1.	Financial Statements

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(1)	General

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(2)	Business Acquisitions

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(3)	Property, Plant and Equipment, Net

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(4)	Investments and Restricted Cash and Cash Equivalents and Investments

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(5)	Recent Financing Transactions

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(6)	Income Taxes

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(7)	Employee Benefit Plans

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(8)	Fair Value Measurements

•	Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

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Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•	Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

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(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $67 million and $79 million as of June 30, 2020 and December 31, 2019, respectively.

(2)	Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

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(9)	Commitments and Contingencies

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(10)	Revenue from Contracts with Customers

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(1)	The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations.

(2)	Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group.

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(11)	BHE Shareholders' Equity

(12)	Components of Other Comprehensive Income (Loss), Net

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(13)	Segment Information

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(1)	The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.

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Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

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PacifiCorp's net income decreased $1 million, primarily due to lower utility margin of $22 million, higher interest expense of $8 million, higher pension and post-retirement costs of $4 million and lower interest and dividend income of $4 million, partially offset by lower operations and maintenance expense of $12 million, primarily due to lower labor and benefits costs and the timing of maintenance, higher allowances for equity and borrowed funds used during construction of $11 million and higher PTCs recognized of $9 million, primarily due to repowering certain wind-powered generating facilities. Utility margin decreased primarily due to unfavorable retail customer volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 4.2%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather and an increase in the average number of customers.

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MidAmerican Funding's net income increased $55 million, primarily due to higher PTCs recognized of $35 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, higher electric utility margin, lower operations and maintenance expense and higher cash surrender value of corporate-owned life insurance policies, partially offset by lower allowances for equity and borrowed funds used during construction of $11 million and higher interest expense of $4 million. Electric utility margin increased primarily due to higher retail customer volumes and lower generation and purchased power costs, partially offset by lower wholesale revenue. Electric retail customer volumes increased 1.8%, primarily due to the favorable impact of weather and 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.

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NV Energy's net income increased $17 million, primarily due to higher electric utility margin of $11 million, higher cash surrender value of corporate-owned life insurance policies and lower income tax expense from the favorable impacts of ratemaking. Electric utility margin increased primarily due to price impacts from changes in sales mix, partially offset by unfavorable retail customer volumes. Electric retail customer volumes, including distribution only service customers, decreased 1.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

•	Northern Powergrid's net income decreased $5 million, primarily due to lower distribution revenue of $11 million from 12.8 % lower units distributed, largely due to the impacts of COVID-19, offset by increased tariff rates.

•	BHE Pipeline Group's net income increased $16 million due to higher transportation revenue of $11 million and the favorable, after-tax, impact of a rate case settlement at Northern Natural Gas of $11 million, partially offset by higher depreciation and amortization expense of $3 million from higher plant placed in-service.

•	BHE Transmission's net income increased $9 million, primarily due to a favorable regulatory decision received in April 2020 at AltaLink and lower non-regulated interest expense at BHE Canada.

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BHE Renewables' net income increased $18 million due to higher wind earnings of $27 million and higher solar earnings of $5 million due to higher generation, partially offset by lower geothermal earnings of $8 million, primarily due to higher operations and maintenance expense and lower generation, and lower natural gas earnings of $6 million, primarily due to lower margins. Wind earnings were higher due to favorable tax equity investment earnings of $26 million, which improved due to $35 million of earnings from projects reaching commercial operation, partially offset by lower commitment fee income of $8 million.

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HomeServices' net income decreased $31 million, primarily due to an unfavorable contingent earn-out remeasurement and lower earnings at brokerage due to a 21% decrease in closed units, in large part from the impacts of COVID-19, offset by lower operating expenses, partially offset by higher earnings at mortgage primarily due to higher refinance activity from the favorable interest rate environment.

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BHE and Other's net loss improved $354 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $406 million, higher margin of $19 million from favorable changes in unrealized positions on derivative contracts at MidAmerican Energy Services, LLC and higher cash surrender value of corporate-owned life insurance policies, partially offset by $55 million of lower federal income tax credits recognized on a consolidated basis and higher interest expense.

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PacifiCorp's net income decreased $5 million, primarily due to lower utility margin, higher interest expense of $14 million, higher pension and post-retirement costs of $7 million and lower interest and dividend income of $6 million, partially offset by higher allowances for equity and borrowed funds used during construction of $21 million, higher PTCs recognized of $17 million, primarily due to repowering certain wind-powered generating facilities, and lower operations and maintenance expense of $14 million, primarily due to lower labor and benefits costs. Utility margin decreased due to unfavorable retail customer volumes, lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms, lower wholesale volumes and price impacts from changes in sales mix, partially offset by lower coal-fueled and natural gas-fueled generation costs. Retail customer volumes decreased 2.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, and the unfavorable impact of weather, partially offset by an increase in the average number of customers.

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MidAmerican Funding's net income increased $15 million, primarily due to higher PTCs recognized of $57 million from higher wind generation, which was driven by repowering and new wind projects placed in-service, and lower operations and maintenance expense, partially offset by lower electric and natural gas utility margins, lower allowances for equity and borrowed funds used during construction of $21 million, lower cash surrender value of corporate-owned life insurance policies and higher interest expense of $10 million. Electric utility margin decreased due to lower wholesale revenue and price impacts from changes in sales mix, partially offset by lower generation and purchased power costs and higher retail customer volumes. Electric retail customer volumes increased 0.5% due to increased usage for certain industrial customers, partially offset by the impacts of COVID-19, which resulted in lower commercial and industrial customer usage and higher residential customer usage. Natural gas utility margin decreased due to 12.9% lower retail customer volumes primarily due to the unfavorable impact of weather.

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NV Energy's net income increased $8 million, primarily due to higher electric utility margin of $12 million and lower income tax expense from the favorable impacts of ratemaking, partially offset by higher depreciation and amortization expense of $9 million, from higher plant placed in-service, and lower cash surrender value of corporate-owned life insurance policies. Electric utility margin increased due to price impacts from changes in sales mix, partially offset by unfavorable retail customer volumes. Electric retail customer volumes, including distribution only service customers, decreased 0.9%, primarily due to the impacts of COVID-19, which resulted in lower industrial and distribution only service customer usage and higher residential customer usage, partially offset by the favorable impact of weather.

•	Northern Powergrid's net income increased $2 million, primarily due to lower interest expense of $5 million and favorable pension costs, partially offset by lower distribution revenues of $3 million from 7.0% lower units distributed, largely due to the impacts of COVID-19, offset by increased tariff rates.

•	BHE Pipeline Group's net income increased $14 million due to higher transportation revenue of $24 million and the favorable, after-tax, impact of a rate case settlement at Northern Natural Gas of $10 million, partially offset by higher depreciation and amortization expense of $6 million, higher interest expense of $5 million and lower storage revenue of $4 million.

•	BHE Transmission's net income increased $8 million due to lower non-regulated interest expense at BHE Canada, a favorable regulatory decision received in April 2020 at AltaLink and $3 million of higher net income at BHE U.S. Transmission mainly due to improved equity earnings from the Electric Transmission Texas, LLC investment.

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BHE Renewables' net income increased $65 million due to higher wind earnings of $77 million and higher solar earnings of $14 million due to higher generation and pricing and lower operations and maintenance expense, partially offset by lower geothermal earnings of $16 million, primarily due to higher operations and maintenance expense and lower generation, and lower natural gas earnings of $9 million, primarily due to lower margins. Wind earnings were higher primarily due to favorable tax equity investment earnings of $73 million, which improved due to $72 million of earnings from projects reaching commercial operation.

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•	HomeServices' net income increased $1 million, primarily due to higher earnings at mortgage largely due to higher refinance activity from the favorable interest rate environment, partially offset by an unfavorable contingent earn-out remeasurement and lower earnings at brokerage due to an 11% decrease in closed units, in large part from the impacts of COVID-19, offset by lower operating expenses.

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BHE and Other's net loss improved $372 million, primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $503 million and higher margin of $15 million from favorable changes in unrealized positions on derivative contracts at MidAmerican Energy Services, LLC, partially offset by consolidated state income tax benefits recognized in 2019, $42 million of lower federal income tax credits recognized on a consolidated basis, higher interest expense and lower cash surrender value of corporate-owned life insurance policies.

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(1)	BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.

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Construction of wind-powered generating facilities at MidAmerican Energy totaling $388 million and $473 million for the six-month periods ended June 30, 2020 and 2019, respectively. MidAmerican Energy anticipates costs associated with the construction of wind-powered generating facilities will total an additional $457 million for 2020. Wind XI, a 2,000-MW project constructed over several years, was completed in January 2020. Wind XII is a 592-MW project, including 202 MWs placed in-service as of June 30, 2020, with the remaining facilities expected to be placed in-service by the end of 2020. MidAmerican Energy obtained pre-approved ratemaking principles for both of these projects and expects all of these wind-powered generating facilities to qualify for 100% of federal 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. Additionally, MidAmerican Energy continues to evaluate wind-powered and other renewable generating facilities that would not be subject to pre-approved ratemaking principles. MidAmerican Energy currently has three such wind-powered generation projects under construction totaling 319 MWs that are expected to be placed in-service by the end of 2020 and to qualify for 100% of federal PTCs available.

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Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $19 million and $118 million for the six-month periods ended June 30, 2020 and 2019, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $138 million for the remainder of 2020. Of the 998 MWs of current repowering projects not in-service as of June 30, 2020, 591 MWs are currently expected to qualify for 80% of the federal PTCs available for ten years following each facility's return to service and 407 MWs are expected to qualify for 60% of such credits.

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Construction of wind-powered generating facilities at PacifiCorp totaling $395 million and $138 million for the six-month periods ended June 30, 2020 and 2019, respectively. Construction includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and the energy production is expected to qualify for 100% of the federal PTCs available for ten years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $802 million for 2020.

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Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $46 million and $215 million for the six-month periods ended June 30, 2020 and 2019, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and the remaining repowering projects are expected to be placed in-service at various dates in 2020. Planned spending for the repowered generating facilities totals $107 million for the remainder of 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal PTCs available for ten years following each facility's return to service.

•	Electric transmission includes PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in service in 2020, additional Energy Gateway Transmission segments expected to be placed in service in 2023 and AltaLink's directly assigned projects from the AESO.

•	Other growth includes projects to deliver power and services to new markets, new customer connections, enhancements to existing customer connections and investments in solar generation.

•	Operating includes ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid, investments in routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand, and environmental spending relating to emissions control equipment and the management of CCRs.

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Item 1.	Financial Statements

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(1)	General

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(2)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

(3)	Property, Plant and Equipment, Net

(1)	Computer software costs included in intangible plant are initially assigned a depreciable life of 5 to 10 years.

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(4)	Recent Financing Transactions

(5)	Income Taxes

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(6)	Employee Benefit Plans

(7)	Risk Management and Hedging Activities

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(1)	PacifiCorp's commodity derivatives are generally included in rates and as of June 30, 2020 and December 31, 2019, a regulatory asset of $68 million and $62 million, respectively, was recorded related to the net derivative liability of $68 million and $63 million, respectively.

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(8)	Fair Value Measurements

•	Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date.

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Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•	Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.

(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $40 million and $47 million as of June 30, 2020 and December 31, 2019, respectively.

(2)	Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

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(9)	Commitments and Contingencies

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(10)	Revenue from Contracts with Customers

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Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

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(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.

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$18 million of lower retail revenue due to lower volumes, partially offset by price impacts from changes in sales mix. Retail customer volumes decreased 4.2% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, partially offset by favorable impacts of weather, primarily in Utah and Oregon, and an increase in the average number of customers;

•	$4 million of higher coal-fueled generation costs primarily due to higher average prices;

•	$4 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•	$3 million of lower wholesale revenue primarily due to lower average market prices.

•	$5 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes; and

•	$4 million of lower wheeling expenses.

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$66 million of lower retail revenue from lower volumes and price impacts from changes in sales mix. Retail customer volumes decreased 2.9% primarily due to the impacts of COVID‑19, resulting in lower commercial and industrial customer usage and higher residential customer usage, and unfavorable impacts of weather primarily in Oregon and Washington, partially offset by an increase in the average number of customers;

•	$35 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms; and

•	$15 million of lower wholesale revenue due to lower volumes, partially offset by the impact of higher average market prices.

•	$59 million of lower coal-fueled generation costs due to lower volumes, partially offset by higher coal prices;

•	$19 million of lower natural gas-fueled generation costs due to lower natural gas prices and lower volumes;

•	$7 million of higher other revenue due to impacts of the Oregon RAC settlement (offset in depreciation expense); and

•	$3 million of lower purchased electricity costs due to lower average market prices, partially offset by higher volumes.

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Transmission system investment primarily reflects initial costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, a major segment of PacifiCorp's Energy Gateway Transmission expansion program expected to be placed in-service in 2020 and investment in additional Energy Gateway Transmission segments expected to be placed in service in 2023. Forecast spending for the Aeolus-Bridger/Anticline line totals $158 million in 2020.

•	Wind investment includes the following:

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Construction of wind-powered generating facilities at PacifiCorp totaling $395 million and $138 million for the six-month periods ended June 30, 2020 and 2019, respectively. Construction includes the 1,190 MWs of new wind-powered generating facilities that are expected to be placed in-service in 2020 and the energy production is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp anticipates costs associated with the construction of wind-powered generating facilities will total an additional $802 million for 2020.

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Repowering existing wind-powered generating facilities at PacifiCorp totaling $46 million and $216 million for the six-month periods ended June 30, 2020 and 2019, respectively. Certain repowering projects were placed in service in 2019 and the remaining repowering projects are expected to be placed in-service at various dates in 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity PTCs available for 10 years following each facility's return to service. PacifiCorp anticipates costs for these activities will total an additional $107 million for 2020.

•	Remaining investments relate to operating projects that consist of advanced meter infrastructure costs, routine expenditures for generation, transmission and distribution, planned spend for wildfire mitigation and other infrastructure needed to serve existing and expected demand.

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Item 1.	Financial Statements

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(1)	General

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(2)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

(3)	Property, Plant and Equipment, Net

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(4)	Recent Financing Transactions

(5)	Income Taxes

(6)	Employee Benefit Plans

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(7)	Fair Value Measurements

•	Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date.

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Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•	Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data.

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(1)	Represents netting under master netting arrangements and a net cash collateral receivable of $- million and $1 million as of June 30, 2020 and December 31, 2019, respectively.

(2)	Amounts are included in cash and cash equivalents and investments and restricted investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost.

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(8)	Commitments and Contingencies

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(9)	Revenue from Contracts with Customers

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(1)	Other retail includes provisions for rate refunds, for which any actual refunds will be reflected in the applicable customer classes upon resolution of the related regulatory proceeding.

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(10)	Segment Information

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(1)	General

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(2)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

(3)	Property, Plant and Equipment, Net

(4)	Recent Financing Transactions

(5)	Income Taxes

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(6)	Employee Benefit Plans

(7)	Fair Value Measurements

(8)	Commitments and Contingencies

(9)	Revenue from Contracts with Customers

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(10)	Segment Information

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Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations

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(1)	GWh amounts are net of energy used by the related generating facilities.

(2)	All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities.

(3)	The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.

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(1)	Higher retail utility margin of $10 million primarily due to -

•	an increase of $12 million from the favorable impact of weather;

•	an increase of $2 million from price impacts from changes in sales mix and non-weather-related factors, 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; and

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a decrease of $5 million from lower recoveries through bill riders, net of energy costs, due to a decrease of $14 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by higher recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and transmission costs (offset in operations and maintenance expense);

(2)	Higher Multi-Value Projects ("MVP") transmission revenue of $3 million; and

(3)	Lower wholesale utility margin of $13 million due to lower margins per unit, reflecting lower market prices, net of lower energy costs, partially offset by higher sales volumes of 10.0%.

(1)	Lower wholesale utility margin of $23 million due to lower margins per unit, from lower market prices, partially offset by lower energy costs, and lower sales volumes of 10.9%;

(2)	Lower retail utility margin of $16 million primarily due to -

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a decrease of $19 million from lower recoveries through bill riders, net of energy costs, primarily due to a decrease of $33 million in electric energy efficiency program revenue (offset in operations and maintenance expense), partially offset by recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit) and transmission costs (offset in operations and maintenance expense);

•	a decrease of $14 million from price impacts from changes in sales mix;

•	an increase of $16 million from non-weather-related factors, 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; and

•	an increase of $2 million from the favorable impact of weather; and

(3)	Higher MVP transmission revenue of $2 million.

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(1)	A decrease of $6 million from lower natural gas energy efficiency program revenue (offset in operations and maintenance expense);

(2)	An increase of $1 million from the favorable impact of weather; and

(3)	An increase of $1 million from rider recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit).

(1)	A decrease of $16 million from lower natural gas energy efficiency program revenue (offset in operations and maintenance expense);

(2)	A decrease of $7 million from the unfavorable impact of weather in the first quarter; and

(3)	A decrease of $2 million from non-weather rate and usage variances, in part due to sales mix; and

(4)	An increase of $2 million from rider recoveries related to the ratemaking treatment of 2017 Tax Reform (offset in income tax benefit).

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The construction of wind-powered generating facilities in Iowa. Wind XI, a 2,000-MW project constructed over several years, was completed in January 2020. Wind XII is a 592-MW project, including 202 MWs placed in-service as of June 30, 2020 and facilities expected to be placed in-service by the end of 2020. MidAmerican Energy obtained pre-approved ratemaking principles for both of these projects and expects all of these wind-powered generating facilities to qualify for 100% of PTCs available. PTCs from these projects are excluded from MidAmerican Energy's Iowa energy adjustment clause until these generation assets are reflected in base rates.

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The repowering of the oldest of MidAmerican Energy's wind-powered generating facilities in Iowa. The repowering projects entail the replacement of significant components of the facilities, which is expected to qualify such facilities for the re-establishment of PTCs for ten years following each facility's return to service at rates that depend upon the year in which construction begins. Of the 998 MWs of current repowering projects not in-service as of June 30, 2020, 591 MWs are currently expected to qualify for 80% of the PTCs available for ten years following each facility's return to service and 407 MWs are expected to qualify for 60% of such credits.

•	Remaining costs primarily relate to routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand.

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Item 1.	Financial Statements

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(1)	General

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(2)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

(3)	Property, Plant and Equipment, Net

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(4)	Regulatory Matters

(5)	Recent Financing Transactions

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(7)	Fair Value Measurements

•	Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.

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Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•	Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.

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(1)	Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

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(8)	Commitments and Contingencies

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(9)	Revenue from Contracts with Customers

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(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2)

The average total cost of energy per MWh and sources of energy excludes - GWhs and 37 GWhs of coal and 318 GWhs and 426 GWhs of gas generated energy that is purchased at cost by related parties for the second quarter of 2020 and 2019, respectively. The average total cost of energy per MWh and sources of energy excludes - GWhs and 118 GWhs of coal and 1,028 GWhs and 923 GWhs of gas generated energy that is purchased at cost by related parties for the first six months of 2020 and 2019, respectively.

(3)	GWh amounts are net of energy used by the related generating facilities.

(4)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

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•

$12 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.3%, primarily due to the impacts of COVID-19, which resulted in lower industrial, distribution only service and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather and

•	$5 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

•	$4 million of lower wholesale revenue and

•	$2 million of higher revenue reductions related to customer service agreements.

•

$9 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 0.4%, primarily due to the impacts of COVID-19, which resulted in lower industrial and distribution only service customer usage and higher residential customer usage, partially offset by the favorable impact of weather and

•	$5 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

•	$4 million of higher revenue reductions related to customer service agreements and

•	$2 million of lower wholesale revenue.

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Item 1.	Financial Statements

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(1)	General

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(2)	Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

(3)	Property, Plant and Equipment, Net

(4)	Regulatory Matters

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(5)	Recent Financing Transactions

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(7)	Employee Benefit Plans

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(8)	Fair Value Measurements

•	Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.

•

Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•	Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.

(1)	Amounts are included in cash and cash equivalents on the Balance Sheets. The fair value of these money market mutual funds approximates cost.

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(9)	Commitments and Contingencies

(10)	Revenue from Contracts with Customers

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(11)	Segment Information

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(1)	Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.

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(1)	Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2)	GWh amounts are net of energy used by the related generating facilities.

(3)	Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

(4)	The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.

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•	$2 million due to higher energy efficiency program rates (offset in operations and maintenance expense).

•	$2 million of lower wholesale revenue.

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•	$2 million due to price impacts from changes in sales mix, partially offset by lower retail customer volumes. Retail customer volumes, including distribution only service customers, decreased 1.7%, primarily due to the impacts of COVID-19, which resulted in lower industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather,

•	$2 million due to higher energy efficiency program rates (offset in operations and maintenance expense) and

•	$1 million of residential customer growth.

•	$1 million of lower wholesale revenue.

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Item 3.	Quantitative and Qualitative Disclosures About Market Risk

Item 4.	Controls and Procedures

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Item 1.	Legal Proceedings

Item 1A.	Risk Factors

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Item 3.	Defaults Upon Senior Securities

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Item 4.	Mine Safety Disclosures

Item 5.	Other Information

Item 6.	Exhibits

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Exhibit No.	Description

4.1	Fifteenth 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).

4.2	Fourteenth 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).

4.3	Trust 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.

10.1	Credit 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.

10.2	Credit Agreement, dated as of April 27, 2020, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders.

15.1	Awareness Letter of Independent Registered Public Accounting Firm.

31.1	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

15.2	Awareness Letter of Independent Registered Public Accounting Firm.

31.3	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.3	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

4.4	Thirty-First Supplemental Indenture, dated as of April 1, 2020, to PacifiCorp's Mortgage and Deed of Trust dated as of January 9, 1989 (incorporated by reference to Exhibit 4.1 to the PacifiCorp Current Report on Form 8-K dated April 8, 2020).

95	Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act.

15.3	Awareness Letter of Independent Registered Public Accounting Firm.

31.5	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.5	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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Exhibit No.	Description

10.3	$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.

31.7	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.7	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.8	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

15.4	Awareness Letter of Independent Registered Public Accounting Firm.

31.9	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.10	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.9	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.10	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

31.11	Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.12	Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.11	Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.12	Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101

The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, is formatted in XBRL (eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in summary and detail.

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