10-Q 1 bhe93019form10-q.htm 9.30.19 FORM 10-Q Document


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended September 30, 2019
or
[  ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from ______ to _______
Commission
File Number
 
Exact name of registrant as specified in its charter;
State or other jurisdiction of incorporation or organization
 
IRS Employer
Identification No.
001-14881
 
BERKSHIRE HATHAWAY ENERGY COMPANY
 
94-2213782
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
001-05152
 
PACIFICORP
 
93-0246090
 
 
(An Oregon Corporation)
 
 
 
 
825 N.E. Multnomah Street
 
 
 
 
Portland, Oregon 97232
 
 
 
 
888-221-7070
 
 
 
 
 
 
 
333-90553
 
MIDAMERICAN FUNDING, LLC
 
47-0819200
 
 
(An Iowa Limited Liability Company)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
333-15387
 
MIDAMERICAN ENERGY COMPANY
 
42-1425214
 
 
(An Iowa Corporation)
 
 
 
 
666 Grand Avenue, Suite 500
 
 
 
 
Des Moines, Iowa 50309-2580
 
 
 
 
515-242-4300
 
 
 
 
 
 
 
000-52378
 
NEVADA POWER COMPANY
 
88-0420104
 
 
(A Nevada Corporation)
 
 
 
 
6226 West Sahara Avenue
 
 
 
 
Las Vegas, Nevada 89146
 
 
 
 
702-402-5000
 
 
 
 
 
 
 
000-00508
 
SIERRA PACIFIC POWER COMPANY
 
88-0044418
 
 
(A Nevada Corporation)
 
 
 
 
6100 Neil Road
 
 
 
 
Reno, Nevada 89511
 
 
 
 
775-834-4011
 
 
 
 
 
 
 
 
 
N/A
 
 
 
 
(Former name or former address, if changed from last report)
 
 



Registrant
Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None
Registrant
Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY
None
PACIFICORP
None
MIDAMERICAN FUNDING, LLC
None
MIDAMERICAN ENERGY COMPANY
None
NEVADA POWER COMPANY
None
SIERRA PACIFIC POWER COMPANY
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Registrant
Yes
No
BERKSHIRE HATHAWAY ENERGY COMPANY
X
 
PACIFICORP
X
 
MIDAMERICAN FUNDING, LLC
 
X
MIDAMERICAN ENERGY COMPANY
X
 
NEVADA POWER COMPANY
X
 
SIERRA PACIFIC POWER COMPANY
X
 
Indicate by check mark whether the registrants have submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit such files). Yes  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Registrant
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
BERKSHIRE HATHAWAY ENERGY COMPANY
 
 
X
 
 
PACIFICORP
 
 
X
 
 
MIDAMERICAN FUNDING, LLC
 
 
X
 
 
MIDAMERICAN ENERGY COMPANY
 
 
X
 
 
NEVADA POWER COMPANY
 
 
X
 
 
SIERRA PACIFIC POWER COMPANY
 
 
X
 
 
If an emerging growth company, indicate by check mark if the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  o
Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes  o  No  x



All shares of outstanding common stock of Berkshire Hathaway Energy Company are privately held by a limited group of investors. As of October 31, 2019, 76,549,232 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of PacifiCorp are indirectly owned by Berkshire Hathaway Energy Company. As of October 31, 2019, 357,060,915 shares of common stock, no par value, were outstanding.
All of the member's equity of MidAmerican Funding, LLC is held by its parent company, Berkshire Hathaway Energy Company, as of October 31, 2019.
All shares of outstanding common stock of MidAmerican Energy Company are owned by its parent company, MHC Inc., which is a direct, wholly owned subsidiary of MidAmerican Funding, LLC. As of October 31, 2019, 70,980,203 shares of common stock, no par value, were outstanding.
All shares of outstanding common stock of Nevada Power Company are owned by its parent company, NV Energy, Inc., which is an indirect, wholly owned subsidiary of Berkshire Hathaway Energy Company. As of October 31, 2019, 1,000 shares of common stock, $1.00 stated value, were outstanding.
All shares of outstanding common stock of Sierra Pacific Power Company are owned by its parent company, NV Energy, Inc. As of October 31, 2019, 1,000 shares of common stock, $3.75 par value, were outstanding.
This combined Form 10-Q is separately filed by Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes no representation as to information relating to the other companies.




TABLE OF CONTENTS
 
PART I
 
 
PART II
 


i


Definition of Abbreviations and Industry Terms

When used in Forward-Looking Statements, Part I - Items 2 through 3, and Part II - Items 1 through 6, the following terms have the definitions indicated.
Berkshire Hathaway Energy Company and Related Entities
BHE
 
Berkshire Hathaway Energy Company
Berkshire Hathaway
 
Berkshire Hathaway Inc.
Berkshire Hathaway Energy or the Company
 
Berkshire Hathaway Energy Company and its subsidiaries
PacifiCorp
 
PacifiCorp and its subsidiaries
MidAmerican Funding
 
MidAmerican Funding, LLC and its subsidiaries
MidAmerican Energy
 
MidAmerican Energy Company
NV Energy
 
NV Energy, Inc. and its subsidiaries
Nevada Power
 
Nevada Power Company and its subsidiaries
Sierra Pacific
 
Sierra Pacific Power Company
Nevada Utilities
 
Nevada Power Company and Sierra Pacific Power Company
Registrants
 
Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, MidAmerican Energy, Nevada Power and Sierra Pacific
Northern Powergrid
 
Northern Powergrid Holdings Company
BHE Pipeline Group
 
Consists of Northern Natural Gas Company and Kern River Gas Transmission Company
Northern Natural Gas
 
Northern Natural Gas Company
Kern River
 
Kern River Gas Transmission Company
BHE Transmission
 
Consists of BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada
 
BHE Canada Holdings Corporation
AltaLink
 
AltaLink, L.P.
BHE U.S. Transmission
 
BHE U.S. Transmission, LLC
BHE Renewables
 
Consists of BHE Renewables, LLC and CalEnergy Philippines
HomeServices
 
HomeServices of America, Inc. and its subsidiaries
Utilities
 
PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company
Domestic Regulated Businesses
 
PacifiCorp, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Northern Natural Gas Company and Kern River Gas Transmission Company
Topaz
 
Topaz Solar Farms LLC
Agua Caliente
 
Agua Caliente Solar, LLC
 
 
 
Certain Industry Terms
 
 
2017 Tax Reform
 
The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018
AB 1054
 
California Assembly Bill 1054
AESO
 
Alberta Electric System Operator
AFUDC
 
Allowance for Funds Used During Construction
AUC
 
Alberta Utilities Commission
CPUC
 
California Public Utilities Commission
CSAPR
 
Cross-State Air Pollution Rule
DEAA
 
Deferred Energy Accounting Adjustment
Dth
 
Decatherm
EBA
 
Energy Balancing Account
ECAM
 
Energy Cost Adjustment Mechanism
EPA
 
United States Environmental Protection Agency

ii


FERC
 
Federal Energy Regulatory Commission
FRMMA
 
Fire Risk Mitigation Memorandum Account
GAAP
 
Accounting principles generally accepted in the United States of America
GEMA
 
Gas and Electricity Markets Authority
GHG
 
Greenhouse Gases
GWh
 
Gigawatt Hour
GTA
 
General Tariff Application
IPUC
 
Idaho Public Utilities Commission
IRP
 
Integrated Resource Plan
IUB
 
Iowa Utilities Board
kV
 
Kilovolt
MW
 
Megawatt
MWh
 
Megawatt Hour
NAAQS
 
National Ambient Air Quality Standards
Ofgem
 
Office of Gas and Electric Markets
OPUC
 
Oregon Public Utility Commission
PUCN
 
Public Utilities Commission of Nevada
RAC
 
Renewable Adjustment Clause
REC
 
Renewable Energy Credit
RPS
 
Renewable Portfolio Standards
RRA
 
Renewable Energy Credit and Sulfur Dioxide Revenue Adjustment Mechanism
SB 901
 
California Senate Bill 901
SEC
 
United States Securities and Exchange Commission
SIP
 
State Implementation Plan
TAM
 
Transition Adjustment Mechanism
UPSC
 
Utah Public Service Commission
WPSC
 
Wyoming Public Service Commission
WUTC
 
Washington Utilities and Transportation Commission

Forward-Looking Statements

This report contains statements that do not directly or exclusively relate to historical facts. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can typically be identified by the use of forward-looking words, such as "will," "may," "could," "project," "believe," "anticipate," "expect," "estimate," "continue," "intend," "potential," "plan," "forecast" and similar terms. These statements are based upon the relevant Registrant's current intentions, assumptions, expectations and beliefs and are subject to risks, uncertainties and other important factors. Many of these factors are outside the control of each Registrant and could cause actual results to differ materially from those expressed or implied by such forward-looking statements. These factors include, among others:
•
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;

iii


•
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;
•
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, 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;
•
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;
•
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.
 
Further details of the potential risks and uncertainties affecting the Registrants are described in the Registrants' filings with the SEC, including Part II, Item 1A and other discussions contained in this Form 10-Q. Each Registrant undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing factors should not be construed as exclusive.


iv


Item 1.
Financial Statements
Berkshire Hathaway Energy Company and its subsidiaries
 
 
 
 
 
 
 
 
 
PacifiCorp and its subsidiaries
 
 
 
 
 
 
 
 
MidAmerican Energy Company
 
 
 
 
 
 
 
 
MidAmerican Funding, LLC and its subsidiaries
 
 
 
 
 
 
 
 
Nevada Power Company and its subsidiaries
 
 
 
 
 
 
 
 
Sierra Pacific Power Company
 
 
 
 
 
 
 
 



1


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



2


Berkshire Hathaway Energy Company and its subsidiaries
Consolidated Financial Section


3


PART I
Item 1.
Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
Berkshire Hathaway Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of September 30, 2019, the related consolidated statements of operations, comprehensive income and changes in equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2018, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2018 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of the Company's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Des Moines, Iowa
November 1, 2019

4


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,141

 
$
627

Restricted cash and cash equivalents
238

 
227

Trade receivables, net
2,075

 
2,038

Inventories
862

 
844

Mortgage loans held for sale
1,060

 
468

Amounts held in trust
304

 
145

Other current assets
680

 
798

Total current assets
6,360

 
5,147

 
 

 
 

Property, plant and equipment, net
71,324

 
68,087

Goodwill
9,643

 
9,595

Regulatory assets
2,817

 
2,896

Investments and restricted cash and cash equivalents and investments
5,775

 
4,903

Other assets
1,994

 
1,561

 
 
 
 

Total assets
$
97,913

 
$
92,189


The accompanying notes are an integral part of these consolidated financial statements.


5


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable
$
1,939

 
$
1,809

Accrued interest
504

 
469

Accrued property, income and other taxes
709

 
599

Accrued employee expenses
406

 
275

Short-term debt
3,119

 
2,516

Current portion of long-term debt
1,976

 
2,081

Other current liabilities
1,350

 
1,021

Total current liabilities
10,003

 
8,770

 
 

 
 

BHE senior debt
8,230

 
8,577

BHE junior subordinated debentures
100

 
100

Subsidiary debt
27,603

 
25,492

Regulatory liabilities
7,249

 
7,346

Deferred income taxes
9,195

 
9,047

Other long-term liabilities
3,793

 
3,134

Total liabilities
66,173

 
62,466

 
 

 
 

Commitments and contingencies (Note 10)
 
 


 
 

 
 

Equity:
 

 
 

BHE shareholders' equity:
 

 
 

Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding
—

 
—

Additional paid-in capital
6,355

 
6,371

Long-term income tax receivable
(457
)
 
(457
)
Retained earnings
27,789

 
25,624

Accumulated other comprehensive loss, net
(2,079
)
 
(1,945
)
Total BHE shareholders' equity
31,608

 
29,593

Noncontrolling interests
132

 
130

Total equity
31,740

 
29,723

 
 
 
 

Total liabilities and equity
$
97,913

 
$
92,189


The accompanying notes are an integral part of these consolidated financial statements.


6


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Energy
$
4,337

 
$
4,419

 
$
11,729

 
$
11,818

Real estate
1,307

 
1,218

 
3,419

 
3,252

Total operating revenue
5,644

 
5,637

 
15,148

 
15,070

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Energy:
 
 
 
 
 
 
 
Cost of sales
1,230

 
1,271

 
3,471

 
3,565

Operations and maintenance
845

 
901

 
2,469

 
2,534

Depreciation and amortization
795

 
667

 
2,243

 
2,110

Property and other taxes
130

 
142

 
427

 
428

Real estate
1,194

 
1,133

 
3,210

 
3,067

Total operating expenses
4,194

 
4,114

 
11,820

 
11,704

 
 
 
 
 
 
 
 
Operating income
1,450

 
1,523

 
3,328

 
3,366

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(475
)
 
(453
)
 
(1,428
)
 
(1,380
)
Capitalized interest
23

 
17

 
56

 
44

Allowance for equity funds
56

 
30

 
126

 
75

Interest and dividend income
25

 
27

 
91

 
85

(Losses) gains on marketable securities, net
(234
)
 
260

 
(296
)
 
(336
)
Other, net
2

 
19

 
67

 
50

Total other income (expense)
(603
)
 
(100
)
 
(1,384
)
 
(1,462
)
 
 
 
 
 
 
 
 
Income before income tax benefit and equity income (loss)
847

 
1,423

 
1,944

 
1,904

Income tax (benefit) expense
(302
)
 
23

 
(526
)
 
(366
)
Equity (loss) income
(4
)
 
9

 
(12
)
 
35

Net income
1,145

 
1,409

 
2,458

 
2,305

Net income attributable to noncontrolling interests
8

 
8

 
15

 
19

Net income attributable to BHE shareholders
$
1,137

 
$
1,401

 
$
2,443

 
$
2,286


The accompanying notes are an integral part of these consolidated financial statements.
 

7


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Net income
$
1,145

 
$
1,409

 
$
2,458

 
$
2,305

 
 
 
 
 
 
 
 
Other comprehensive (loss) income, net of tax:
 
 
 
 
 
 
 
Unrecognized amounts on retirement benefits, net of tax of $(4), $-, $(6) and $12
(26
)
 
(1
)
 
(40
)
 
50

Foreign currency translation adjustment
(172
)
 
(2
)
 
(66
)
 
(236
)
Unrealized gains (losses) on cash flow hedges, net of tax of $3, $(1), $(8) and $(1)
7

 
1

 
(28
)
 
2

Total other comprehensive loss, net of tax
(191
)
 
(2
)
 
(134
)
 
(184
)
 
 

 
 

 
 

 
 

Comprehensive income
954

 
1,407

 
2,324

 
2,121

Comprehensive income attributable to noncontrolling interests
8

 
8

 
15

 
19

Comprehensive income attributable to BHE shareholders
$
946

 
$
1,399

 
$
2,309

 
$
2,102


The accompanying notes are an integral part of these consolidated financial statements.


8


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
 
BHE Shareholders' Equity
 
 
 
 
 
 
 
 
 
 
Long-term
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
Additional
 
Income
 
 
 
Other
 
 
 
 
 
Common
 
Paid-in
 
Tax
 
Retained
 
Comprehensive
 
Noncontrolling
 
Total
 
Shares
 
Stock
 
Capital
 
Receivable
 
Earnings
 
Loss, Net
 
Interests
 
Equity
Balance, June 30, 2018
77

 
$
—

 
$
6,358

 
$
(494
)
 
$
23,976

 
$
(1,665
)
 
$
129

 
$
28,304

Net income
—

 
—

 
—

 
—

 
1,401

 
—

 
8

 
1,409

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(2
)
 
—

 
(2
)
Common stock repurchases
—

 
—

 
(1
)
 
—

 
(16
)
 
—

 
—

 
(17
)
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(5
)
 
(5
)
Other equity transactions
—

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
(1
)
Balance, September 30, 2018
77

 
$
—

 
$
6,357

 
$
(494
)
 
$
25,361

 
$
(1,667
)
 
$
131

 
$
29,688

 
 

 
 

 
 

 
 
 
 

 
 

 
 

 
 

Balance, December 31, 2017
77

 
$
—

 
$
6,368

 
$
—

 
$
22,206

 
$
(398
)
 
$
132

 
$
28,308

Adoption of ASU 2016-01
—

 
—

 
—

 
—

 
1,085

 
(1,085
)
 
—

 
—

Net income
—

 
—

 
—

 
—

 
2,286

 
—

 
16

 
2,302

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(184
)
 
—

 
(184
)
Reclassification of long-term income tax receivable
—

 
—

 
—

 
(609
)
 
—

 
—

 
—

 
(609
)
Long-term income tax receivable adjustments
—

 
—

 
—

 
115

 
(115
)
 
—

 
—

 
—

Common stock repurchases
—

 
—

 
(6
)
 
—

 
(101
)
 
—

 
—

 
(107
)
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(17
)
 
(17
)
Other equity transactions
—

 
—

 
(5
)
 
—

 
—

 
—

 
—

 
(5
)
Balance, September 30, 2018
77

 
$
—

 
$
6,357

 
$
(494
)
 
$
25,361

 
$
(1,667
)
 
$
131

 
$
29,688

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2019
77

 
$
—

 
$
6,355

 
$
(457
)
 
$
26,651

 
$
(1,888
)
 
$
126

 
$
30,787

Net income
—

 
—

 
—

 
—

 
1,137

 
—

 
7

 
1,144

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(191
)
 
—

 
(191
)
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(6
)
 
(6
)
Other equity transactions
—

 
—

 
—

 
—

 
1

 
—

 
5

 
6

Balance, September 30, 2019
77

 
$
—

 
$
6,355

 
$
(457
)
 
$
27,789

 
$
(2,079
)
 
$
132

 
$
31,740

 
 

 
 

 
 

 
 
 
 

 
 

 
 

 
 

Balance, December 31, 2018
77

 
$
—

 
$
6,371

 
$
(457
)
 
$
25,624

 
$
(1,945
)
 
$
130

 
$
29,723

Net income
—

 
—

 
—

 
—

 
2,443

 
—

 
14

 
2,457

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(134
)
 
—

 
(134
)
Common stock repurchases
—

 
—

 
(16
)
 
—

 
(277
)
 
—

 
—

 
(293
)
Distributions
—

 
—

 
—

 
—

 
—

 
—

 
(16
)
 
(16
)
Other equity transactions
—

 
—

 
—

 
—

 
(1
)
 
—

 
4

 
3

Balance, September 30, 2019
77

 
$
—

 
$
6,355

 
$
(457
)
 
$
27,789

 
$
(2,079
)
 
$
132

 
$
31,740


The accompanying notes are an integral part of these consolidated financial statements.

9


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
2,458

 
$
2,305

Adjustments to reconcile net income to net cash flows from operating activities:
 

 
 

Losses on marketable securities, net
296

 
336

Depreciation and amortization
2,278

 
2,147

Allowance for equity funds
(126
)
 
(75
)
Equity loss (income), net of distributions
43

 
17

Changes in regulatory assets and liabilities
108

 
263

Deferred income taxes and amortization of investment tax credits
(92
)
 
(116
)
Other, net
44

 
40

Changes in other operating assets and liabilities, net of effects from acquisitions:
 
 
 
Trade receivables and other assets
(594
)
 
(192
)
Derivative collateral, net
(19
)
 
9

Pension and other postretirement benefit plans
(40
)
 
(61
)
Accrued property, income and other taxes, net
195

 
190

Accounts payable and other liabilities
109

 
168

Net cash flows from operating activities
4,660

 
5,031

 
 

 
 

Cash flows from investing activities:
 

 
 

Capital expenditures
(4,898
)
 
(4,203
)
Acquisitions, net of cash acquired
(28
)
 
(105
)
Purchases of marketable securities
(242
)
 
(287
)
Proceeds from sales of marketable securities
223

 
266

Equity method investments
(1,144
)
 
(236
)
Other, net
54

 
48

Net cash flows from investing activities
(6,035
)
 
(4,517
)
 
 

 
 

Cash flows from financing activities:
 

 
 

Proceeds from BHE senior debt
—

 
3,166

Repayments of BHE senior debt
—

 
(650
)
Common stock repurchases
(293
)
 
(107
)
Proceeds from subsidiary debt
3,463

 
2,353

Repayments of subsidiary debt
(1,821
)
 
(2,297
)
Net proceeds from (repayments of) short-term debt
594

 
(2,694
)
Purchase of redeemable noncontrolling interest
—

 
(131
)
Other, net
(42
)
 
(32
)
Net cash flows from financing activities
1,901

 
(392
)
 
 

 
 

Effect of exchange rate changes
(3
)
 
(3
)
 
 

 
 

Net change in cash and cash equivalents and restricted cash and cash equivalents
523

 
119

Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
883

 
1,283

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
1,406

 
$
1,402


The accompanying notes are an integral part of these consolidated financial statements.

10


BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)
General

Berkshire Hathaway Energy Company ("BHE") is a holding company that owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding, LLC ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. ("NV Energy") (which primarily consists of Nevada Power Company ("Nevada Power") and Sierra Pacific Power Company ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. (collectively with its subsidiaries, "HomeServices"). The Company, 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, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2019 and for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2018 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies, except as disclosed in Note 4, during the nine-month period ended September 30, 2019.



11


(2)
Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
Depreciable
 
September 30,
 
December 31,
 
Life
 
2019
 
2018
Regulated assets:
 
 
 
 
 
Utility generation, transmission and distribution systems
5-80 years
 
$
78,596

 
$
76,707

Interstate natural gas pipeline assets
3-80 years
 
7,637

 
7,524

 
 
 
86,233

 
84,231

Accumulated depreciation and amortization
 
 
(26,719
)
 
(25,894
)
Regulated assets, net
 
 
59,514

 
58,337

 
 
 
 

 
 

Nonregulated assets:
 
 
 

 
 

Independent power plants
5-30 years
 
6,966

 
6,826

Other assets
3-30 years
 
1,606

 
1,424

 
 
 
8,572

 
8,250

Accumulated depreciation and amortization
 
 
(2,075
)
 
(1,610
)
Nonregulated assets, net
 
 
6,497

 
6,640

 
 
 
 

 
 

Net operating assets
 
 
66,011

 
64,977

Construction work-in-progress
 
 
5,313

 
3,110

Property, plant and equipment, net
 
 
$
71,324

 
$
68,087


Construction work-in-progress includes $5.1 billion as of September 30, 2019 and $2.9 billion as of December 31, 2018, related to the construction of regulated assets.


12


(3)
Investments and Restricted Cash and Cash Equivalents and Investments

Investments and restricted cash and cash equivalents and investments consists of the following (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Investments:
 
 
 
BYD Company Limited common stock
$
1,124

 
$
1,435

Rabbi trusts
395

 
371

Other
181

 
168

Total investments
1,700

 
1,974

 
 

 
 

Equity method investments:
 
 
 
BHE Renewables tax equity investments
2,695

 
1,661

Electric Transmission Texas, LLC
553

 
527

Bridger Coal Company
83

 
99

Other
173

 
153

Total equity method investments
3,504

 
2,440

 
 
 
 
Restricted cash and cash equivalents and investments:
 

 
 

Quad Cities Station nuclear decommissioning trust funds
571

 
504

Restricted cash and cash equivalents
265

 
256

Total restricted cash and cash equivalents and investments
836

 
760

 
 

 
 

Total investments and restricted cash and cash equivalents and investments
$
6,040

 
$
5,174

 
 
 
 
Reflected as:
 
 
 
Current assets
$
265

 
$
271

Noncurrent assets
5,775

 
4,903

Total investments and restricted cash and cash equivalents and investments
$
6,040

 
$
5,174


Investments

(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Unrealized (losses) gains recognized on marketable securities still held at the reporting date
$
(236
)
 
$
260

 
$
(297
)
 
$
(337
)
Net gains recognized on marketable securities sold during the period
2

 
—

 
1

 
1

(Losses) gains on marketable securities, net
$
(234
)
 
$
260

 
$
(296
)
 
$
(336
)


13


Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Cash and cash equivalents
$
1,141

 
$
627

Restricted cash and cash equivalents
238

 
227

Investments and restricted cash and cash equivalents and investments
27

 
29

Total cash and cash equivalents and restricted cash and cash equivalents
$
1,406

 
$
883


(4)    Leases

Adoption

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. The Company adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

The Company has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.

Leases

Lessee

The Company has non-cancelable operating leases primarily for office space, office equipment, generating facilities, land and rail cars and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require the Company 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. The Company does not include options in its lease calculations unless there is a triggering event indicating the Company is reasonably certain to exercise the option. The Company’s accounting policy is to not recognize lease obligations and corresponding right-of-use assets 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 ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.


14


The Company's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

The Company's 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. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and subsidiary debt, respectively, to conform to the current period presentation. The following table summarizes the Company's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
September 30,
 
2019
Right-of-use assets:
 
Operating leases
$
526

Finance leases
503

Total right-of-use assets
$
1,029

 
 
Lease liabilities:
 
Operating leases
$
574

Finance leases
517

Total lease liabilities
$
1,091


The following table summarizes the Company's lease costs (in millions):
 
Three-Month Period
 
Nine-Month Period
 
Ended September 30,
 
Ended September 30,
 
2019
 
2019
 
 
 
 
Variable
$
156

 
$
453

Operating
43

 
127

Finance:
 
 
 
Amortization
4

 
12

Interest
10

 
31

Short-term
2

 
6

Total lease costs
$
215

 
$
629

 
 
 
 
Weighted-average remaining lease term (years):
 
 
 
Operating leases
 
 
7.8

Finance leases
 
 
29.3

 
 
 
 
Weighted-average discount rate:
 
 
 
Operating leases
 
 
5.2
%
Finance leases
 
 
8.6
%


15


The following table summarizes the Company's supplemental cash flow information relating to leases (in millions):
 
Nine-Month Period
 
Ended September 30,
 
2019
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(106
)
Operating cash flows from finance leases
(32
)
Financing cash flows from finance leases
(14
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Operating leases
$
49

Finance leases
12


The Company has the following remaining lease commitments as of (in millions):
 
September 30, 2019
 
December 31, 2018(1)
 
Operating
 
Finance
 
Total
 
Operating
 
Capital
 
Total
2019
$
38

 
$
16

 
$
54

 
$
147

 
$
69

 
$
216

2020
139

 
70

 
209

 
128

 
68

 
196

2021
118

 
76

 
194

 
110

 
73

 
183

2022
96

 
69

 
165

 
87

 
67

 
154

2023
68

 
58

 
126

 
61

 
56

 
117

Thereafter
241

 
779

 
1,020

 
159

 
772

 
931

Total undiscounted lease payments
700

 
1,068

 
1,768

 
$
692

 
$
1,105

 
$
1,797

Less - amounts representing interest
(126
)
 
(551
)
 
(677
)
 
 
 
 
 
 
Lease liabilities
$
574

 
$
517

 
$
1,091

 
 
 
 
 
 

(1)     Amounts included for comparability and accounted for in accordance with ASC 840, "Leases".
(5)
Recent Financing Transactions

Long-Term Debt

In October 2019, MidAmerican Energy issued $600 million of its 3.15% First Mortgage Bonds due April 2050 and $250 million of its 3.65% First Mortgage Bonds due April 2029, which are part of the same series as the 3.65% First Mortgage Bonds issued in January 2019. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from December 20, 2018 to July 15, 2019, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project, MidAmerican Energy's 591-megawatt (nameplate capacity) Wind XII project and the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds.

In October 2019, Northern Powergrid (Yorkshire) plc issued £300 million of its 2.25% Bonds due October 2059 and intends to use the net proceeds for general corporate purposes.

In June 2019, Northern Natural Gas issued $200 million of its 4.30% Senior Bonds due January 2049. The bonds are part of the same series as the $450 million aggregate principal amount of 4.30% bonds due 2049 that were issued in July 2018. Northern Natural Gas intends to use the net proceeds to fund capital expenditures and for general corporate purposes.

In May 2019, Northern Electric Finance plc issued £150 million of its 2.75% Guaranteed Bonds due May 2049 and intends to use the net proceeds for general corporate purposes.

In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt partially incurred in January 2019 to repay all of PacifiCorp's $350 million 5.50% First Mortgage Bonds due January 2019 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.

16



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 January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029. Nevada Power used the net proceeds to repay all of Nevada Power's $500 million 7.125% General and Refunding Mortgage Notes, Series V, maturing in March 2019.

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. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from November 1, 2017 to December 14, 2018, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project, MidAmerican Energy's 591-megawatt (nameplate capacity) Wind XII project and the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds.

Credit Facilities

In October 2019, Northern Powergrid amended and restated its existing £150 million multicurrency revolving credit facility expiring April 2020, extending the expiration date to October 2022 with two one-year extension options.

In August 2019, MidAmerican Energy entered into a $400 million unsecured credit facility, which expires August 2020 and has a variable rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. The facility requires that MidAmerican Energy’s ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.

In May 2019, BHE extended, with lender consent, the expiration date for its existing $3.5 billion unsecured credit facility to June 2022 by exercising the first of two available one-year extensions.

In May 2019, PacifiCorp extended, with lender consent, the expiration date for each of its two existing $600 million unsecured credit facilities to June 2022 by exercising the remaining one-year extension option for one facility and exercising the first of two available one-year extensions for the second facility.

In May 2019, MidAmerican Energy extended, with lender consent, the expiration date for its existing $900 million unsecured credit facility to June 2022 by exercising the remaining one-year extension option.

In May 2019, Nevada Power and Sierra Pacific extended, with lender consent, the expiration date for its $400 million and $250 million secured credit facilities, respectively, to June 2022 by exercising the remaining one-year extension options.

(6)
Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
21
 %
 
21
 %
Income tax credits
(43
)
 
(19
)
 
(35
)
 
(29
)
State income tax, net of federal income tax benefit
(3
)
 
1

 
(6
)
 
(6
)
Income tax effect of foreign income
(1
)
 
—

 
(2
)
 
(3
)
Effects of ratemaking
(9
)
 
(2
)
 
(5
)
 
(3
)
Equity income
—

 
—

 
—

 
—

Other, net
(1
)
 
1

 
—


1

Effective income tax rate
(36
)%
 
2
 %
 
(27
)%
 
(19
)%


17


Income tax credits relate primarily to production tax credits from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

The Company's provision for income tax has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its United States federal and Iowa state income tax returns and the majority of all of its currently payable or receivable income tax is remitted to or received from Berkshire Hathaway. For the nine-month periods ended September 30, 2019 and 2018, the Company received net cash payments for federal income taxes from Berkshire Hathaway totaling $534 million and $450 million, respectively.

(7)
Employee Benefit Plans

Domestic Operations

Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Pension:
 
 
 
 
 
 
 
Service cost
$
4

 
$
5

 
$
12

 
$
15

Interest cost
27

 
26

 
82

 
78

Expected return on plan assets
(38
)
 
(41
)
 
(115
)
 
(123
)
Net amortization
8

 
8

 
24

 
23

Net periodic benefit cost (credit)
$
1

 
$
(2
)
 
$
3

 
$
(7
)
 
 
 
 
 
 
 
 
Other postretirement:
 
 
 
 
 
 
 
Service cost
$
1

 
$
1

 
$
6

 
$
6

Interest cost
6

 
7

 
20

 
19

Expected return on plan assets
(10
)
 
(9
)
 
(30
)
 
(31
)
Net amortization
—

 
(3
)
 
(3
)
 
(9
)
Net periodic benefit credit
$
(3
)
 
$
(4
)
 
$
(7
)
 
$
(15
)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $1 million, respectively, during 2019. As of September 30, 2019, $9 million and $- million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.


18


Foreign Operations

Net periodic benefit cost for the United Kingdom pension plan included the following components (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Service cost
$
3

 
$
5

 
$
11

 
$
15

Interest cost
13

 
14

 
39

 
42

Expected return on plan assets
(24
)
 
(25
)
 
(74
)
 
(78
)
Settlement
21

 
12

 
21

 
36

Net amortization
9

 
9

 
27

 
38

Net periodic benefit cost
$
22

 
$
15

 
$
24

 
$
53


Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £44 million during 2019. As of September 30, 2019, £33 million, or $42 million, of contributions had been made to the United Kingdom pension plan.

(8)    Asset Retirement Obligations

In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material in such facilities, which is a more extensive closure activity than previously assumed. In the first quarter of 2019, MidAmerican Energy increased the asset retirement obligations for its fossil-fueled generating facilities by $237 million related to the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023.

(9)
Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.
•
Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•
Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.


19


The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of September 30, 2019
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
—

 
$
36

 
$
103

 
$
(25
)
 
$
114

Interest rate derivatives
 
—

 
7

 
23

 
—

 
30

Mortgage loans held for sale
 
—

 
1,060

 
—

 
—

 
1,060

Money market mutual funds(2)
 
837

 
—

 
—

 
—

 
837

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
189

 
—

 
—

 
—

 
189

International government obligations
 
—

 
5

 
—

 
—

 
5

Corporate obligations
 
—

 
57

 
—

 
—

 
57

Municipal obligations
 
—

 
1

 
—

 
—

 
1

Agency, asset and mortgage-backed obligations
 
—

 
1

 
—

 
—

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
309

 
—

 
—

 
—

 
309

International companies
 
1,132

 
—

 
—

 
—

 
1,132

Investment funds
 
182

 
—

 
—

 
—

 
182

 
 
$
2,649


$
1,167


$
126


$
(25
)
 
$
3,917

Liabilities:
 
 

 
 

 
 

 
 

 
 

Commodity derivatives
 
$
(3
)

$
(142
)

$
(25
)

$
101

 
$
(69
)
Interest rate derivatives
 
(3
)
 
(21
)
 
(3
)
 
—

 
(27
)
 
 
$
(6
)
 
$
(163
)
 
$
(28
)
 
$
101

 
$
(96
)
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of December 31, 2018
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
1

 
$
91

 
$
108

 
$
(52
)
 
$
148

Interest rate derivatives
 
1

 
13

 
10

 
—

 
24

Mortgage loans held for sale
 
—

 
468

 
—

 
—

 
468

Money market mutual funds(2)
 
409

 
—

 
—

 
—

 
409

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
187

 
—

 
—

 
—

 
187

International government obligations
 
—

 
4

 
—

 
—

 
4

Corporate obligations
 
—

 
46

 
—

 
—

 
46

Municipal obligations
 
—

 
2

 
—

 
—

 
2

Agency, asset and mortgage-backed obligations
 
—

 
1

 
—

 
—

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
256

 
—

 
—

 
—

 
256

International companies
 
1,441

 
—

 
—

 
—

 
1,441

Investment funds
 
128

 
—

 
—

 
—

 
128

 
 
$
2,423

 
$
625

 
$
118

 
$
(52
)
 
$
3,114

Liabilities:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
(1
)
 
$
(180
)
 
$
(9
)
 
$
111

 
$
(79
)
Interest rate derivatives
 
—

 
(32
)
 
—

 
—

 
(32
)
 
 
$
(1
)
 
$
(212
)
 
$
(9
)
 
$
111

 
$
(111
)

20



(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $76 million and $59 million as of September 30, 2019 and December 31, 2018, respectively.
(2)
Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.
Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.


21


The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
 
 
Interest
 
 
 
Interest
 
Commodity
 
Rate
 
Commodity
 
Rate
 
Derivatives
 
Derivatives
 
Derivatives
 
Derivatives
2019:
 
 
 
 
 
 
 
Beginning balance
$
86

 
$
23

 
$
99

 
$
10

Changes included in earnings
1

 
158

 
6

 
305

Changes in fair value recognized in OCI
—

 
—

 
(1
)
 
—

Changes in fair value recognized in net regulatory assets
(17
)
 
—

 
(40
)
 
—

Purchases
—

 
—

 
4

 
—

Settlements
8

 
(161
)
 
10

 
(295
)
Ending balance
$
78

 
$
20

 
$
78

 
$
20

2018:
 
 
 
 
 
 
 
Beginning balance
$
83

 
$
17

 
$
94

 
$
9

Changes included in earnings
(1
)
 
54

 
3

 
140

Changes in fair value recognized in OCI
1

 
—

 
1

 
—

Changes in fair value recognized in net regulatory assets
3

 
—

 
(11
)
 
—

Purchases
1

 
—

 
2

 
—

Settlements
(3
)
 
(61
)
 
(5
)
 
(139
)
Ending balance
$
84

 
$
10

 
$
84

 
$
10


The Company's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):
 
As of September 30, 2019
 
As of December 31, 2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
37,909

 
$
44,979

 
$
36,250

 
$
38,874


(10)
Commitments and Contingencies

Fuel, Capacity and Transmission Contract Commitments

In October 2019, Nevada Power terminated a power purchase agreement, due to the supplier's failure to satisfy its performance obligations as detailed in the agreement, that had minimum annual payments of approximately $60 million in 2019 through 2023 and $1,145 million in 2024 and thereafter, as of December 31, 2018.

22




Construction Commitments

During the nine-month period ended September 30, 2019, PacifiCorp and MidAmerican Energy entered into firm construction commitments totaling $1.1 billion for the remainder of 2019 through 2021 related to repowering and development of certain existing and new wind facilities in Wyoming, Montana, Washington and Iowa.

Easements

During the nine-month period ended September 30, 2019, PacifiCorp and MidAmerican Energy entered into non-cancelable easements with minimum payments totaling $593 million through 2060 for land in Wyoming, Montana and Iowa, on which some of its wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the nine-month period ended September 30, 2019, PacifiCorp and MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payments totaling $618 million through 2032.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz Solar Farm LLC ("Topaz") and owns a 49% interest in Agua Caliente Solar, LLC ("Agua Caliente"). Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until October 2039. As of September 30, 2019, the Company's consolidated balance sheet includes $1.0 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of September 30, 2019, the Company's equity investment in Agua Caliente totals $70 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente in 2019. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. In July 2019, the California Governor signed California Assembly Bill 1054 ("AB 1054") into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California that, among other items, authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities, including PG&E, participate by making the required contributions, among other things. In July 2019, PG&E notified the California Public Utilities Commission of its intent to participate in the insurance fund and such participation requires, among other items, PG&E to exit bankruptcy by June 30, 2020. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.


23


Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.    

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC has been supplementing the application with additional information about its financial, technical, and legal capacity to become the licensee. In July 2019, the KRRC provided the FERC with additional information about its financial capacity to become a licensee, including updated cost estimates, and its insurance, bonding and liability transfer package. The FERC is evaluating the KRRC's information and the proposed license transfer. The KRRC will continue to refine its insurance, bonding and liability transfer package, and PacifiCorp will review the KRRC's capacity to fulfill its indemnity obligation under the KHSA. If certain conditions in the amended KHSA are not satisfied (e.g., inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California, Oregon and other states, asked the court to rehear the case, which was denied. Subsequently, environmental groups, supported by numerous states, filed a petition for certiorari before the United States Supreme Court, which remains pending.

Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.


24


(11)
Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated energy and nonregulated energy, with further disaggregation of regulated energy by customer class and line of business, including a reconciliation to the Company's reportable segment information included in Note 14 (in millions):
 
 
For the Three-Month Period Ended September 30, 2019
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail electric
 
$
1,320

 
$
651

 
$
998

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
2,968

Retail gas
 
—

 
61

 
16

 
—

 
—

 
—

 
—

 
—

 
77

Wholesale
 
8

 
56

 
6

 
—

 
—

 
—

 
—

 
(1
)
 
69

Transmission and
   distribution
 
26

 
16

 
27

 
195

 
—

 
179

 
—

 
—

 
443

Interstate pipeline
 
—

 
—

 
—

 
—

 
221

 
—

 
—

 
(25
)
 
196

Other
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total Regulated
 
1,354

 
784

 
1,047

 
195

 
221

 
179

 
—

 
(27
)
 
3,753

Nonregulated
 
—

 
9

 
—

 
9

 
—

 
5

 
276

 
161

 
460

Total Customer Revenue
 
1,354

 
793

 
1,047

 
204

 
221

 
184

 
276

 
134

 
4,213

Other revenue
 
13

 
4

 
7

 
26

 
5

 
—

 
53

 
16

 
124

Total
 
$
1,367

 
$
797

 
$
1,054

 
$
230

 
$
226

 
$
184

 
$
329

 
$
150

 
$
4,337

 
 
For the Nine-Month Period Ended September 30, 2019
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail electric
 
$
3,613

 
$
1,561

 
$
2,183

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
7,356

Retail gas
 
—

 
416

 
74

 
—

 
—

 
—

 
—

 
—

 
490

Wholesale
 
47

 
232

 
34

 
—

 
—

 
—

 
—

 
(2
)
 
311

Transmission and
   distribution
 
76

 
47

 
75

 
634

 
—

 
514

 
—

 
—

 
1,346

Interstate pipeline
 
—

 
—

 
—

 
—

 
805

 
—

 
—

 
(86
)
 
719

Other
 
—

 
—

 
1

 
—

 
—

 
—

 
—

 
—

 
1

Total Regulated
 
3,736

 
2,256

 
2,367

 
634

 
805

 
514

 
—

 
(89
)
 
10,223

Nonregulated
 
—

 
25

 
—

 
27

 
—

 
13

 
599

 
442

 
1,106

Total Customer Revenue
 
3,736

 
2,281

 
2,367

 
661

 
805

 
527

 
599

 
353

 
11,329

Other revenue
 
57

 
18

 
22

 
75

 
4

 
—

 
146

 
78

 
400

Total
 
$
3,793

 
$
2,299

 
$
2,389

 
$
736

 
$
809

 
$
527

 
$
745

 
$
431

 
$
11,729


25


 
 
For the Three-Month Period Ended September 30, 2018
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail electric
 
$
1,323

 
$
647

 
$
1,002

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
2,971

Retail gas
 
—

 
83

 
13

 
—

 
—

 
—

 
—

 
—

 
96

Wholesale(2)
 
(10
)
 
82

 
9

 
—

 
—

 
—

 
—

 
(1
)
 
80

Transmission and
   distribution
 
30

 
14

 
28

 
196

 
—

 
171

 
—

 
—

 
439

Interstate pipeline
 
—

 
—

 
—

 
—

 
283

 
—

 
—

 
(25
)
 
258

Other
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total Regulated
 
1,343

 
826

 
1,052

 
196

 
283

 
171

 
—

 
(27
)
 
3,844

Nonregulated
 
—

 
2

 
—

 
10

 
—

 
3

 
235

 
176

 
426

Total Customer Revenue
 
1,343

 
828

 
1,052

 
206

 
283

 
174

 
235

 
149

 
4,270

Other revenue(3)
 
26

 
4

 
7

 
27

 
(24
)
 
—

 
85

 
24

 
149

Total
 
$
1,369

 
$
832

 
$
1,059

 
$
233

 
$
259

 
$
174

 
$
320

 
$
173

 
$
4,419

 
 
For the Nine-Month Period Ended September 30, 2018
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
BHE Pipeline Group
 
BHE Transmission
 
BHE Renewables
 
BHE and
Other(1)
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail electric
 
$
3,534

 
$
1,538

 
$
2,232

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(1
)
 
$
7,303

Retail gas
 
—

 
428

 
72

 
—

 
—

 
—

 
—

 
—

 
500

Wholesale
 
21

 
262

 
26

 
—

 
—

 
—

 
—

 
(3
)
 
306

Transmission and
   distribution
 
82

 
44

 
73

 
661

 
—

 
525

 
—

 
—

 
1,385

Interstate pipeline
 
—

 
—

 
—

 
—

 
893

 
—

 
—

 
(91
)
 
802

Other
 
—

 
—

 
1

 
—

 
—

 
—

 
—

 
—

 
1

Total Regulated
 
3,637

 
2,272

 
2,404

 
661

 
893

 
525

 
—

 
(95
)
 
10,297

Nonregulated
 
—

 
7

 
1

 
31

 
—

 
6

 
538

 
478

 
1,061

Total Customer Revenue
 
3,637

 
2,279

 
2,405

 
692

 
893

 
531

 
538

 
383

 
11,358

Other revenue(3)
 
109

 
18

 
21

 
65

 
(22
)
 
—

 
182

 
87

 
460

Total
 
$
3,746

 
$
2,297

 
$
2,426

 
$
757

 
$
871

 
$
531

 
$
720

 
$
470

 
$
11,818


(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 non-derivative forward contracts for energy sales at PacifiCorp.
(3)
Includes net payments to counterparties for the financial settlement of certain derivative contracts at BHE Pipeline Group.


26


Real Estate Services

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):

 
HomeServices
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Customer Revenue:
 
 
 
 
 
 
 
Brokerage
$
1,172

 
$
1,122

 
$
3,087

 
$
2,975

Franchise
20

 
18

 
53

 
52

Total Customer Revenue
1,192

 
1,140

 
3,140

 
3,027

Other revenue
115

 
78

 
279

 
225

Total
$
1,307

 
$
1,218

 
$
3,419

 
$
3,252


Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of September 30, 2019, by reportable segment (in millions):
 
Performance obligations expected to be satisfied:
 
 
 
Less than 12 months
 
More than 12 months
 
Total
BHE Pipeline Group
$
922

 
$
5,309

 
$
6,231


(12)
BHE Shareholders' Equity

For the nine-month periods ended September 30, 2019 and 2018, BHE repurchased 447,712 shares of its common stock for $293 million and 177,381 shares of its common stock for $107 million, respectively.

(13)
Components of Other Comprehensive Income (Loss), Net

The following table shows the change in AOCI attributable to BHE shareholders by each component of OCI, net of applicable income tax (in millions):
 
 
Unrecognized
 
Foreign
 
Unrealized
 
Unrealized
 
AOCI
 
 
Amounts on
 
Currency
 
Gains on
 
Gains (Losses)
 
Attributable
 
 
Retirement
 
Translation
 
Marketable
 
on Cash
 
To BHE
 
 
Benefits
 
Adjustment
 
Securities
 
Flow Hedges
 
Shareholders, Net
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
 
$
(383
)
 
$
(1,129
)
 
$
1,085

 
$
29

 
$
(398
)
Adoption of ASU 2016-01
 
—

 
—

 
(1,085
)
 
—

 
(1,085
)
Other comprehensive income (loss)
 
50

 
(236
)
 
—

 
2

 
(184
)
Balance, September 30, 2018
 
$
(333
)
 
$
(1,365
)
 
$
—

 
$
31

 
$
(1,667
)
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
 
$
(358
)
 
$
(1,623
)
 
$
—

 
$
36

 
$
(1,945
)
Other comprehensive loss
 
(40
)
 
(66
)
 
—

 
(28
)
 
(134
)
Balance, September 30, 2019
 
$
(398
)
 
$
(1,689
)
 
$
—

 
$
8

 
$
(2,079
)


27


(14)
Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
PacifiCorp
$
1,367

 
$
1,369

 
$
3,793

 
$
3,746

MidAmerican Funding
797

 
832

 
2,299

 
2,297

NV Energy
1,054

 
1,059

 
2,389

 
2,426

Northern Powergrid
230

 
233

 
736

 
757

BHE Pipeline Group
226

 
259

 
809

 
871

BHE Transmission
184

 
174

 
527

 
531

BHE Renewables
329

 
320

 
745

 
720

HomeServices
1,307

 
1,218

 
3,419

 
3,252

BHE and Other(1)
150

 
173

 
431

 
470

Total operating revenue
$
5,644

 
$
5,637

 
$
15,148

 
$
15,070

Depreciation and amortization:
 
 
 
 
 
 
 
PacifiCorp
$
272

 
$
203

 
$
686

 
$
602

MidAmerican Funding
184

 
133

 
540

 
499

NV Energy
121

 
114

 
361

 
341

Northern Powergrid
60

 
62

 
186

 
189

BHE Pipeline Group
28

 
27

 
85

 
99

BHE Transmission
59

 
61

 
177

 
184

BHE Renewables
71

 
68

 
210

 
198

HomeServices
11

 
14

 
35

 
37

BHE and Other(1)
—

 
(1
)
 
(2
)
 
(2
)
Total depreciation and amortization
$
806

 
$
681

 
$
2,278

 
$
2,147



28


 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating income:
 
 
 
 
 
 
 
PacifiCorp
$
333

 
$
386

 
$
885

 
$
917

MidAmerican Funding
234

 
278

 
444

 
444

NV Energy
313

 
307

 
547

 
540

Northern Powergrid
98

 
102

 
337

 
360

BHE Pipeline Group
87

 
105

 
398

 
388

BHE Transmission
91

 
82

 
244

 
244

BHE Renewables
183

 
176

 
298

 
308

HomeServices
113

 
85

 
209

 
185

BHE and Other(1)
(2
)
 
2

 
(34
)
 
(20
)
Total operating income
1,450


1,523

 
3,328


3,366

Interest expense
(475
)
 
(453
)
 
(1,428
)
 
(1,380
)
Capitalized interest
23

 
17

 
56

 
44

Allowance for equity funds
56

 
30

 
126

 
75

Interest and dividend income
25

 
27

 
91

 
85

(Losses) gains on marketable securities, net
(234
)
 
260

 
(296
)
 
(336
)
Other, net
2

 
19

 
67

 
50

Total income before income tax expense and equity income
$
847


$
1,423

 
$
1,944


$
1,904

Interest expense:
 
 
 
 
 
 
 
PacifiCorp
$
101

 
$
96

 
$
299

 
$
288

MidAmerican Funding
74

 
61

 
223

 
185

NV Energy
55

 
52

 
173

 
169

Northern Powergrid
33

 
34

 
102

 
107

BHE Pipeline Group
14

 
11

 
38

 
31

BHE Transmission
40

 
42

 
118

 
127

BHE Renewables
44

 
49

 
132

 
150

HomeServices
6

 
6

 
20

 
16

BHE and Other(1)
108

 
102

 
323

 
307

Total interest expense
$
475

 
$
453

 
$
1,428


$
1,380

Operating revenue by country:
 
 
 
 
 
 
 
United States
$
5,222

 
$
5,209

 
$
13,875

 
$
13,757

United Kingdom
229

 
232

 
734

 
754

Canada
183

 
174

 
526

 
531

Philippines and other
10

 
22

 
13

 
28

Total operating revenue by country
$
5,644

 
$
5,637

 
$
15,148

 
$
15,070

Income before income tax benefit and equity income (loss) by country:
 
 
 
 
 
 
 
United States
$
728

 
$
1,290

 
$
1,546

 
$
1,501

United Kingdom
49

 
59

 
228

 
220

Canada
55

 
43

 
134

 
125

Philippines and other
15

 
31

 
36

 
58

Total income before income tax benefit and equity income (loss) by country
$
847

 
$
1,423

 
$
1,944

 
$
1,904



29


 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Assets:
 
 
 
PacifiCorp
$
24,789

 
$
23,478

MidAmerican Funding
21,806

 
20,029

NV Energy
14,477

 
14,119

Northern Powergrid
7,334

 
7,427

BHE Pipeline Group
5,775

 
5,511

BHE Transmission
8,692

 
8,424

BHE Renewables
9,650

 
8,666

HomeServices
3,971

 
2,797

BHE and Other(1)
1,419

 
1,738

Total assets
$
97,913

 
$
92,189


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

The following table shows the change in the carrying amount of goodwill by reportable segment for the nine-month period ended September 30, 2019 (in millions):
 
 
 
 
 
 
 
 
 
BHE Pipeline Group
 
 
 
 
 
 
 
 
 
PacifiCorp
 
MidAmerican Funding
 
NV Energy
 
Northern Powergrid
 
 
BHE Transmission
 
BHE Renewables
 
HomeServices
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
$
1,129

 
$
2,102

 
$
2,369

 
$
952

 
$
73

 
$
1,448

 
$
95

 
$
1,427

 
$
9,595

Acquisitions
—

 
—

 
—

 
—

 
—

 
—

 
—

 
30

 
30

Foreign currency translation
—

 
—

 
—

 
(26
)
 
—

 
44

 
—

 
—

 
18

September 30, 2019
$
1,129

 
$
2,102

 
$
2,369

 
$
926

 
$
73

 
$
1,492

 
$
95

 
$
1,457

 
$
9,643


30


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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the Company during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other usage factors. This discussion should be read in conjunction with the Company's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

The Company'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) Limited and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which consists of 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, two interstate natural gas pipeline companies in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.

Results of Operations for the Third Quarter and First Nine Months of 2019 and 2018

Overview

Net income for the Company's reportable segments is summarized as follows (in millions):
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Net income attributable to BHE shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
278

 
$
270

 
$
8

 
3
 %
 
$
626

 
$
603

 
$
23

 
4
 %
MidAmerican Funding
279

 
479

 
(200
)
 
(42
)
 
622

 
685

 
(63
)
 
(9
)
NV Energy
206

 
201

 
5

 
2

 
316

 
311

 
5

 
2

Northern Powergrid
37

 
44

 
(7
)
 
(16
)
 
181

 
169

 
12

 
7

BHE Pipeline Group
66

 
79

 
(13
)
 
(16
)
 
295

 
286

 
9

 
3

BHE Transmission
65

 
55

 
10

 
18

 
172

 
164

 
8

 
5

BHE Renewables
167

 
139

 
28

 
20

 
335

 
304

 
31

 
10

HomeServices
82

 
60

 
22

 
37

 
150

 
127

 
23

 
18

BHE and Other
(43
)
 
74

 
(117
)
 
*

 
(254
)
 
(363
)
 
109

 
30

Total net income attributable to BHE shareholders
$
1,137

 
$
1,401

 
$
(264
)
 
(19
)
 
$
2,443

 
$
2,286

 
$
157

 
7


*    Not meaningful

Net income attributable to BHE shareholders decreased $264 million for the third quarter of 2019 compared to 2018. The third quarter of 2019 included a pre-tax unrealized loss of $234 million ($170 million after-tax) compared to a pre-tax unrealized gain in the third quarter of 2018 of $252 million ($182 million after-tax), respectively, on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted net income attributable to BHE shareholders for the third quarter of 2019 was $1,307 million, an increase of $88 million, or 7%, compared to adjusted net income attributable to BHE shareholders in the third quarter of 2018 of $1,219 million.


31


Net income attributable to BHE shareholders increased $157 million for the first nine months of 2019 compared to 2018. The first nine months of 2019 and 2018 included a pre-tax unrealized loss of $311 million ($226 million after-tax) and $346 million ($250 million after-tax), respectively, on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted net income attributable to BHE shareholders for the first nine months of 2019 was $2,669 million, an increase of $133 million, or 5%, compared to adjusted net income attributable to BHE shareholders in the first nine months of 2018 of $2,536 million.

In 2018, the Domestic Regulated Businesses began passing the benefits of lower income tax expense related to 2017 Tax Reform to customers through various regulatory mechanisms, including lower retail rates, higher depreciation expense and reductions to rate base. The decrease in net income attributable to BHE shareholders for the third quarter of 2019 compared to 2018 was due to the following:
•
PacifiCorp's net income increased $8 million primarily due to higher allowances for equity and borrowed funds of $18 million and lower operations and maintenance expense of $14 million, largely due to a decrease in expenses from lower wildfire reserves, partially offset by lower recognized production tax credits of $8 million from expiring production tax credits and higher interest expense of $5 million. Utility margin was relatively unchanged; however, retail customer volumes decreased 1.6% primarily due to lower customer usage and the unfavorable impact of weather, partially offset by an increase in the average number of customers.
•
MidAmerican Funding's net income decreased $200 million primarily due to lower income tax benefit of $148 million primarily due to a $172 million decrease in recognized production tax credits, partially offset by the effects of ratemaking, higher depreciation and amortization expense of $51 million due to $33 million of higher Iowa revenue sharing accruals and greater assets placed in-service, and higher interest expense of $13 million, partially offset by higher electric utility margin and higher allowances for equity and borrowed funds of $12 million. The decrease in production tax credits recognized was due to a change in the method of interim period recognition of $185 million, partially offset by higher actual generation. Electric utility margin increased due to lower generation and purchased power costs and higher retail customer volumes, partially offset by lower wholesale revenue, lower average retail rates and lower recoveries through bill riders. Electric retail customer volumes increased 1.7% from higher industrial volumes of 2.9% and the favorable impact of weather, partially offset by a decrease in residential and commercial volumes from lower customer usage.
•
NV Energy's net income increased $5 million primarily due to lower operations and maintenance expense of $44 million, largely due to lower political activity expenses and lower earnings sharing accruals at Nevada Power, and lower income tax expense of $13 million largely offset by lower electric utility margin of $32 million, unfavorable other, net of $8 million, primarily due to higher non-service pension expense, higher depreciation and amortization expense of $7 million and higher interest expense of $4 million. Electric utility margin decreased primarily due to lower retail customer volumes and lower transmission and wholesale revenue, partially offset by an increase in the average number of customers. Electric retail customer volumes decreased 2.6% primarily due to the impacts of weather, net of increased distribution only service customer volumes.
•
Northern Powergrid's net income decreased $7 million primarily due to higher overall pension expense of $10 million, largely resulting from higher pension settlement losses recognized, and the stronger United States dollar of $2 million.
•
BHE Pipeline Group's net income decreased $13 million primarily due to lower transportation revenue of $30 million, partially offset by lower property and other tax expense of $11 million due to a non-recurring state property tax refund in 2019.
•
BHE Transmission's net income increased $10 million primarily due to $12 million from favorable regulatory decisions received in August 2019 at AltaLink and higher equity earnings at Electric Transmission Texas, LLC.
•
BHE Renewables' net income increased $28 million primarily due to higher wind earnings of $18 million primarily due to higher earnings from tax equity investments, mainly due to $12 million of earnings from projects reaching commercial operation and $6 million of higher commitment fees, improved geothermal earnings of $14 million from higher generation and pricing and improved solar earnings of $5 million from higher generation, partially offset by lower hydro earnings of $8 million from lower rainfall.
•
HomeServices' net income increased $22 million primarily due to higher earnings at existing mortgage businesses of $17 million and net income from acquired businesses.
•
BHE and Other had a net loss of $43 million for the third quarter of 2019 compared to net income of $74 million for the third quarter of 2018. The difference of $117 million was primarily due to the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $352 million, partially offset by $255 million of higher federal income tax credits recognized on a consolidated basis in large part due to the change in the method of interim period recognition at MidAmerican Funding.

32



The increase in net income attributable to BHE shareholders for the first nine months of 2019 compared to 2018 was due to the following:
•
PacifiCorp's net income increased $23 million primarily due to higher allowances for equity and borrowed funds of $40 million, higher utility margin of $34 million and lower operations and maintenance expense of $14 million, mainly due to a decrease in expenses from lower wildfire reserves, partially offset by higher depreciation and amortization expense of $19 million from additional plant placed in-service, higher interest expense of $11 million and lower recognized production tax credits of $11 million from expiring production tax credits. Utility margin increased primarily due to higher average retail rates, lower coal-fueled generation costs, higher retail customer volumes and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by lower wholesale revenue, higher natural gas-fueled generation costs and higher purchased electricity costs. Retail customer volumes increased 0.3% primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage.
•
MidAmerican Funding's net income decreased $63 million primarily due to lower income tax benefit of $52 million primarily due to a $90 million decrease in recognized production tax credits, partially offset by the effects of ratemaking, higher depreciation and amortization expense of $41 million due to greater assets placed in-service, partially offset by $15 million of lower Iowa revenue sharing accruals, and higher interest expense of $38 million, partially offset by higher electric utility margin and higher allowances for equity and borrowed funds of $26 million. The decrease in production tax credits recognized was due to a change in the method of interim period recognition of $129 million, partially offset by higher actual generation. Electric utility margin increased due to lower generation and purchased power costs, higher recoveries through bill riders and higher retail customer volumes, partially offset by lower average retail rates and lower wholesale revenue. Electric retail customer volumes increased 0.9% as an increase in industrial volumes of 4.0% was largely offset by lower residential and commercial volumes from the unfavorable impact of weather and lower customer usage.
•
NV Energy's net income increased $5 million primarily due to lower operations and maintenance expense of $88 million, largely due to lower political activity expenses and lower earnings sharing accruals at Nevada Power, and lower income tax expense of $8 million, largely offset by lower electric utility margin of $58 million, higher depreciation and amortization expense of $20 million, unfavorable other, net of $8 million, primarily due to higher non-service pension expense, and higher interest expense of $5 million. Electric utility margin decreased due to lower retail customer volumes and lower average retail rates from a tax rate reduction rider effective April 1, 2018, partially offset by higher wholesale and transmission revenue and an increase in the average number of customers. Electric retail customer volumes decreased 1.3% primarily due to the impacts of weather, net of increased distribution only service customer volumes.
•
Northern Powergrid's net income increased $12 million primarily due to lower overall pension expense of $25 million, largely resulting from lower pension settlement losses recognized in 2019 compared to 2018, partially offset by the stronger United States dollar of $11 million.
•
BHE Pipeline Group's net income increased $9 million primarily due to higher transportation revenue of $23 million, lower property and other tax expense of $9 million due to a non-recurring state property tax refund in 2019 and favorable margin of $9 million on system balancing activities, partially offset by higher operations and maintenance expense of $18 million, primarily from increased asset modernization and pipeline integrity projects, and higher depreciation and amortization expense, net of the impact of period two rates at Kern River.
•
BHE Transmission's net income increased $8 million primarily due to $12 million from favorable regulatory decisions received in August 2019 at AltaLink and higher equity earnings at Electric Transmission Texas, LLC, partially offset by the stronger United States dollar of $4 million and the unfavorable impact of a reduction in the Alberta provincial corporate income tax rate from the remeasurement of nonregulated deferred tax assets.
•
BHE Renewables' net income increased $31 million primarily due to higher wind earnings of $33 million and higher geothermal earnings of $23 million largely due to higher generation and pricing, partially offset by lower hydro earnings of $14 million, primarily due to lower rainfall and a declining financial asset balance, and lower solar earnings of $10 million primarily due to lower insolation and a settlement received in 2018 from Solar Star transformer related outages in 2016. Wind earnings were favorable primarily due to earnings from new projects of $28 million, improved tax equity investment earnings of $18 million and a favorable change in the valuation of a power purchase agreement of $10 million, partially offset by lower earnings on existing projects of $12 million from lower generation and $13 million of unfavorable changes in the valuation of interest rate swap derivatives. Tax equity investment earnings were favorable due to $33 million of earnings from projects reaching commercial operation and $10 million of higher commitment fees, partially offset by $23 million of lower earnings from existing projects mainly due to derates caused by turbine blade repairs.

33


•
HomeServices' net income increased $23 million primarily due to higher earnings at existing mortgage businesses of $27 million and net income from acquired businesses, partially offset by lower earnings at existing brokerage businesses primarily from lower closed units and margins.
•
BHE and Other's net loss improved $109 million primarily due to $176 million of higher federal income tax credits recognized on a consolidated basis in large part due to the change in the method of interim period recognition at MidAmerican Funding and the change in the after-tax unrealized position of the Company's investment in BYD Company Limited of $24 million, partially offset by $76 million of income tax benefits recognized in 2018 related to the accrued repatriation tax on undistributed foreign earnings and foreign earnings and lower margin of $21 million from unrealized mark to market losses on contracts at MidAmerican Energy Services, LLC.

Reportable Segment Results

Operating revenue and operating income for the Company's reportable segments are summarized as follows (in millions):
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Operating revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
1,367

 
$
1,369

 
$
(2
)
 
—
 %
 
$
3,793

 
$
3,746

 
$
47

 
1
 %
MidAmerican Funding
797

 
832

 
(35
)
 
(4
)
 
2,299

 
2,297

 
2

 
—

NV Energy
1,054

 
1,059

 
(5
)
 
—

 
2,389

 
2,426

 
(37
)
 
(2
)
Northern Powergrid
230

 
233

 
(3
)
 
(1
)
 
736

 
757

 
(21
)
 
(3
)
BHE Pipeline Group
226

 
259

 
(33
)
 
(13
)
 
809

 
871

 
(62
)
 
(7
)
BHE Transmission
184

 
174

 
10

 
6

 
527

 
531

 
(4
)
 
(1
)
BHE Renewables
329

 
320

 
9

 
3

 
745

 
720

 
25

 
3

HomeServices
1,307

 
1,218

 
89

 
7

 
3,419

 
3,252

 
167

 
5

BHE and Other
150

 
173

 
(23
)
 
(13
)
 
431

 
470

 
(39
)
 
(8
)
Total operating revenue
$
5,644

 
$
5,637

 
$
7

 
—

 
$
15,148

 
$
15,070

 
$
78

 
1

 
Operating income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PacifiCorp
$
333

 
$
386

 
$
(53
)
 
(14
)%
 
$
885

 
$
917

 
$
(32
)
 
(3
)%
MidAmerican Funding
234

 
278

 
(44
)
 
(16
)
 
444

 
444

 
—

 
—

NV Energy
313

 
307

 
6

 
2

 
547

 
540

 
7

 
1

Northern Powergrid
98

 
102

 
(4
)
 
(4
)
 
337

 
360

 
(23
)
 
(6
)
BHE Pipeline Group
87

 
105

 
(18
)
 
(17
)
 
398

 
388

 
10

 
3

BHE Transmission
91

 
82

 
9

 
11

 
244

 
244

 
—

 
—

BHE Renewables
183

 
176

 
7

 
4

 
298

 
308

 
(10
)
 
(3
)
HomeServices
113

 
85

 
28

 
33

 
209

 
185

 
24

 
13

BHE and Other
(2
)
 
2

 
(4
)
 
*

 
(34
)
 
(20
)
 
(14
)
 
(70
)
Total operating income
$
1,450

 
$
1,523

 
$
(73
)
 
(5
)
 
$
3,328

 
$
3,366

 
$
(38
)
 
(1
)

*    Not meaningful

PacifiCorp

Operating revenue decreased $2 million for the third quarter of 2019 compared to 2018 due to lower retail revenue. Retail revenue decreased due to lower customer volumes of $19 million, largely offset by higher average retail rates of $17 million primarily due to lower net tax deferrals associated with 2017 Tax Reform and product mix. Retail customer volumes decreased 1.6% primarily due to lower customer usage and the unfavorable impact of weather, partially offset by an increase in the average number of residential and commercial customers.


34


Operating income decreased $53 million for the third quarter of 2019 compared to 2018 primarily due to higher depreciation and amortization expense of $69 million, primarily due to $65 million (offset in income tax expense) of accelerated depreciation for Oregon’s share of certain retired wind equipment due to repowering, partially offset by lower operations and maintenance expense of $14 million largely due to a decrease in expenses from lower wildfire reserves.

Operating revenue increased $47 million for the first nine months of 2019 compared to 2018 due to higher retail revenue of $81 million, partially offset by lower wholesale and other revenue of $34 million, primarily due to lower wholesale volumes. Retail revenue increased primarily due to higher average retail rates of $65 million due to lower net tax deferrals associated with 2017 Tax Reform and product mix and $17 million from higher customer volumes. Retail customer volumes increased 0.3% primarily due to an increase in the average number of residential and commercial customers and the favorable impact of weather, partially offset by lower customer usage.

Operating income decreased $32 million for the first nine months of 2019 compared to 2018 primarily due to higher depreciation and amortization expense of $84 million, partially offset by higher utility margin of $34 million and lower operations and maintenance expense of $14 million largely due to a decrease in expenses from lower wildfire reserves. The increase in depreciation and amortization expense reflects $65 million (offset in income tax expense) of accelerated depreciation for Oregon’s share of certain retired wind equipment due to repowering and higher plant in-service. Utility margin increased primarily due to higher average retail rates, lower coal-fueled generation costs, higher retail customer volumes and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by lower wholesale revenue, higher natural gas-fueled generation costs and higher purchased electricity costs.

MidAmerican Funding

Operating revenue decreased $35 million for the third quarter of 2019 compared to 2018 primarily due to lower demand-side management electric and natural gas revenue of $30 million (offset in operations and maintenance expense) and lower natural gas operating revenue, partially offset by higher other operating revenue of $7 million, primarily from nonregulated utility construction services, and higher electric operating revenue. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of gas sold (offset in cost of sales) and 5.9% lower retail sales volumes from the unfavorable impact of weather. Electric operating revenue increased due to higher retail revenue, partially offset by lower wholesale and other revenue of $19 million, which decreased due to a 20.9% decrease in wholesale volumes and lower average per-unit prices of $6 million. Electric retail revenue increased from higher recoveries through bill riders (substantially offset in cost of fuel and energy, operations and maintenance expense and income tax expense), primarily the energy adjustment clause, $6 million from the favorable impact of weather and $6 million from higher customer usage, primarily industrial, partially offset by $5 million from lower average rates due to sales mix. Electric retail customer volumes increased 1.7% primarily from higher industrial volumes of 2.9% and the favorable impact of weather, partially offset by a decrease in residential and commercial volumes from lower customer usage.

Operating income decreased $44 million for the third quarter of 2019 compared to 2018 primarily due to higher depreciation and amortization expense of $51 million and higher operations and maintenance expense, partially offset by higher electric utility margin. The increase in depreciation and amortization expense reflects higher Iowa revenue sharing accruals of $33 million and an increase related to new wind-powered generation and other plant additions. Operations and maintenance expense increased mainly due to increased electric generation costs and higher electric and natural gas distribution costs. Electric utility margin increased due to lower generation and purchased power costs, higher recoveries through bill riders and higher retail customer volumes, partially offset by lower wholesale revenue and lower average retail rates.

Operating revenue increased $2 million for the first nine months of 2019 compared to 2018 due to higher electric operating revenue and higher other operating revenue of $18 million, primarily from nonregulated utility construction services, partially offset by lower demand-side management electric and natural gas revenue of $46 million and lower natural gas operating revenue. Electric operating revenue increased due to higher retail revenue, partially offset by lower wholesale and other revenue of $14 million. Electric retail revenue increased from higher recoveries through bill riders, primarily the energy adjustment clause, and $44 million from higher customer usage, primarily industrial, partially offset by lower average rates of $32 million due to sales mix and $18 million from the unfavorable impact of weather. Electric retail customer volumes increased 0.9% as an increase in industrial volumes of 4.0% was largely offset by lower residential and commercial volumes from the unfavorable impact of weather and lower customer usage. Electric wholesale and other revenue decreased due to lower wholesale average per-unit prices of $15 million, partially offset by a 1.9% increase in wholesale volumes. Natural gas operating revenue decreased due to a lower average per-unit cost of gas sold, partially offset by 3.2% higher retail sales volumes from the favorable impact of weather in 2019.


35


Operating income was unchanged for the first nine months of 2019 compared to 2018 primarily due to higher electric utility margin, offset by higher depreciation and amortization expense of $41 million and higher operations and maintenance expense. Electric utility margin increased due to higher recoveries through bill riders, lower generation and purchased power costs and higher retail customer volumes, partially offset by lower average retail rates and lower wholesale revenue. The increase in depreciation and amortization expense reflects an increase related to new wind-powered generation and other plant additions, partially offset by lower Iowa revenue sharing accruals of $15 million. Operations and maintenance expense increased mainly due to higher electric generation costs and higher electric and natural gas distribution costs.

NV Energy

Operating revenue decreased $5 million for the third quarter of 2019 compared to 2018 primarily due to lower electric operating revenue of $9 million, partially offset by higher natural gas operating revenue of $3 million. Electric operating revenue decreased due to lower wholesale and other revenue of $5 million and lower retail revenue of $4 million. Electric retail revenue decreased primarily due to lower customer volumes of $29 million, partially offset by higher energy rates (offset in cost of fuel and energy) of $23 million and an increase in the average number of customers of $5 million. Electric retail customer volumes decreased 2.6% primarily due to the impacts of weather, net of increased distribution only service customer volumes.

Operating income increased $6 million for the third quarter of 2019 compared to 2018 due to lower operations and maintenance expense of $44 million, primarily due to lower political activity expenses and lower earnings sharing accruals at Nevada Power, partially offset by lower electric utility margin of $32 million and higher depreciation and amortization expense of $7 million. Electric utility margin decreased due to higher energy costs of $23 million and lower operating revenue. Energy costs increased due to higher net deferred power costs of $106 million, partially offset by lower purchased power costs of $56 million and a lower average cost of fuel for generation of $27 million.

Operating revenue decreased $37 million for the first nine months of 2019 compared to 2018 primarily due to lower electric operating revenue of $38 million. Electric operating revenue decreased due to lower retail revenue of $48 million, partially offset by higher wholesale and other revenue of $10 million. Electric retail revenue decreased primarily due to lower retail customer volumes of $47 million and a decrease from the tax rate reduction rider effective April 1, 2018 of $17 million, partially offset by higher energy rates (offset in cost of fuel and energy) of $10 million and an increase in the average number of customers of $10 million. Electric retail customer volumes decreased 1.3% primarily due to the impacts of weather, net of increased distribution only service customer volumes.

Operating income increased $7 million for the first nine months of 2019 compared to 2018 due to lower operations and maintenance expense of $88 million, primarily due to lower political activity expenses and lower earnings sharing accruals at Nevada Power, partially offset by lower electric utility margin of $58 million and higher depreciation and amortization expense of $20 million. Electric utility margin decreased due to the lower operating revenue and higher energy costs of $20 million. Energy costs increased due to higher net deferred power costs of $50 million and a higher average cost of fuel for generation of $12 million, partially offset by lower purchased power costs of $42 million.

Northern Powergrid

Operating revenue decreased $3 million for the third quarter of 2019 compared to 2018 primarily due to the stronger United States dollar of $13 million and lower distributed units of $4 million, partially offset by higher distribution tariff rates of $9 million and higher smart meter revenue of $2 million from increased smart meter asset additions. Operating income decreased $4 million for the third quarter of 2019 compared to 2018 primarily due to the stronger United States dollar of $6 million, higher distribution-related operations and maintenance expense and higher depreciation expense related to additional distribution network and smart meter investments, partially offset by the higher distribution and smart meter revenues.

Operating revenue decreased $21 million for the first nine months of 2019 compared to 2018 primarily due to the stronger United States dollar of $46 million and lower distributed units of $19 million, partially offset by higher distribution tariff rates of $29 million and higher smart meter revenue of $13 million from increased smart meter asset additions. Operating income decreased $23 million for the first nine months of 2019 compared to 2018 primarily due to the stronger United States dollar of $21 million, higher distribution-related operations and maintenance expense and higher depreciation expense related to additional distribution network and smart meter investments, partially offset by the higher distribution and smart meter revenues.


36


BHE Pipeline Group

Operating revenue decreased $33 million for the third quarter of 2019 compared to 2018 primarily due to $30 million of lower transportation revenue largely from lower rates and volumes and $3 million from refunds related to 2017 Tax Reform. Operating income decreased $18 million for the third quarter of 2019 compared to 2018 primarily due to lower transportation revenue of $30 million, partially offset by lower property and other tax expense of $11 million due to a non-recurring state property tax refund in 2019.

Operating revenue decreased $62 million for the first nine months of 2019 compared to 2018 due to lower gas sales of $58 million at Northern Natural Gas related to system balancing activities (largely offset in cost of sales) and lower transportation revenue of $3 million. Transportation revenue decreased from the impact of period two rates of $26 million (largely offset in depreciation and amortization expense) and $9 million from refunds related to 2017 Tax Reform at Kern River, largely offset by generally higher volumes and rates. Operating income increased $10 million for the first nine months of 2019 compared to 2018 primarily due to higher transportation revenue of $23 million, lower property and other tax expense of $9 million due to a non-recurring state property tax refund in 2019 and favorable margins of $9 million on system balancing activities, partially offset by higher operations and maintenance expense of $18 million, primarily from increased asset modernization and pipeline integrity projects, and higher depreciation and amortization expense, net of the impact of period two rates at Kern River.

BHE Transmission

Operating revenue increased $10 million for the third quarter of 2019 compared to 2018 primarily due to $12 million from favorable regulatory decisions received in August 2019, partially offset by the stronger United States dollar of $2 million. Operating income increased $9 million for the third quarter of 2019 compared to 2018 primarily due to the higher operating revenue.

Operating revenue decreased $4 million for the first nine months of 2019 compared to 2018 primarily due to the stronger United States dollar of $17 million, partially offset by $12 million from favorable regulatory decisions received in August 2019. Operating income was unchanged for the first nine months of 2019 compared to 2018 as the impact from the favorable regulatory decisions received in August 2019 was largely offset by the stronger United States dollar of $8 million.

BHE Renewables

Operating revenue increased $9 million for the third quarter of 2019 compared to 2018 primarily due to higher natural gas revenues of $15 million due to higher generation and pricing and higher solar revenues of $7 million due to higher insolation and pricing, partially offset by lower hydro revenues of $12 million from lower rainfall. Operating income increased $7 million for the third quarter of 2019 compared to 2018 primarily due to the higher operating revenue and lower other operations and maintenance expense of $5 million, partially offset by higher expenses related to new wind-powered generation of $5 million.

Operating revenue increased $25 million for the first nine months of 2019 compared to 2018 primarily due to higher wind revenues of $29 million and higher natural gas revenues of $21 million due to higher generation and pricing, partially offset by lower hydro revenues of $16 million due to lower rainfall and lower solar revenues of $10 million due to lower insolation. Wind revenues increased primarily due to $28 million from new projects and a favorable change in the valuation of a power purchase agreement of $10 million, partially offset by lower generation of $9 million at existing projects. Operating income decreased $10 million for the first nine months of 2019 compared to 2018 primarily due to higher expenses related to new wind-powered generation of $26 million and higher other operations and maintenance expense of $10 million, partially offset by the higher operating revenue.

HomeServices

Operating revenue increased $89 million for the third quarter of 2019 compared to 2018 due to higher revenue at existing businesses, primarily mortgage, of $63 million and an increase from acquired businesses of $26 million. Operating income increased $28 million for the third quarter of 2019 compared to 2018 primarily due to an increase at existing mortgage businesses of $21 million and an increase from acquired businesses of $5 million.

Operating revenue increased $167 million for the first nine months of 2019 compared to 2018 due to an increase from acquired businesses of $195 million and higher mortgage revenue at existing businesses of $63 million, partially offset by lower brokerage revenue at existing businesses of $91 million primarily due to a 5% decrease in closed units. Operating income increased $24 million for the first nine months of 2019 compared to 2018 primarily due to an increase at existing mortgage businesses of $37 million and an increase from acquired businesses of $13 million, partially offset by a decrease at existing brokerage companies of $30 million primarily from lower closed units and margins.


37


BHE and Other

Operating revenue decreased $23 million for the third quarter of 2019 compared to 2018 and $39 million for the first nine months of 2019 compared to 2018 primarily due to lower electricity and natural gas volumes at MidAmerican Energy Services, LLC. Operating loss increased $4 million for the third quarter of 2019 compared to 2018 and $14 million for the first nine months of 2019 compared to 2018 due to lower margin of $21 million from unrealized mark to market losses on contracts at MidAmerican Energy Services, LLC for the first nine months.

Consolidated Other Income and Expense Items

Interest expense

Interest expense is summarized as follows (in millions):
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Subsidiary debt
$
366

 
$
347

 
$
19

 
5
%
 
$
1,102

 
$
1,062

 
$
40

 
4
%
BHE senior debt and other
108

 
105

 
3

 
3

 
322

 
314

 
8

 
3

BHE junior subordinated debentures
1

 
1

 
—

 
—

 
4

 
4

 
—

 
—

Total interest expense
$
475

 
$
453

 
$
22

 
5

 
$
1,428

 
$
1,380

 
$
48

 
3


Interest expense increased $22 million for the third quarter of 2019 compared to 2018 and $48 million for the first nine months of 2019 compared to 2018 primarily due to debt issuances at BHE, PacifiCorp, MidAmerican Energy and BHE Pipeline Group and higher short-term borrowings, partially offset by scheduled maturities, principal payments and the impact of foreign currency exchange rate movements.

Capitalized interest

Capitalized interest increased $6 million for the third quarter of 2019 compared to 2018 and $12 million for the first nine months of 2019 compared to 2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy, partially offset by a lower construction work-in-progress balance at BHE Renewables.

Allowance for equity funds

Allowance for equity funds increased $26 million for the third quarter of 2019 compared to 2018 and $51 million for the first nine months of 2019 compared to 2018 primarily due to higher construction work-in-progress balances at PacifiCorp and MidAmerican Energy.

Interest and dividend income

Interest and dividend income decreased $2 million for the third quarter of 2019 compared to 2018 and increased $6 million for the first nine months of 2019 compared to 2018 primarily due to higher cash balances at PacifiCorp and NV Energy for the first nine months, partially offset by a declining financial asset balance at the Casecnan project.

(Losses) gains on marketable securities, net

(Losses) gains on marketable securities, net was unfavorable $(494) million for the third quarter of 2019 compared to 2018 and favorable $40 million for the first nine months of 2019 compared to 2018 primarily due to the change in the unrealized position on the Company's investment in BYD Company Limited of $(486) million and $35 million, respectively.


38


Other, net

Other, net decreased $17 million for the third quarter of 2019 compared to 2018 primarily due to higher non-service pension expense of $13 million, largely resulting from higher pension settlement losses recognized at Northern Powergrid, and lower investment earnings, partially offset by higher commitment fees of $6 million from new tax equity investments.

Other, net increased $17 million for the first nine months of 2019 compared to 2018 primarily due to higher investment earnings, higher commitment fees of $10 million and lower non-service pension expense of $7 million, largely resulting from lower pension settlement losses recognized in 2019 compared to 2018 at Northern Powergrid, partially offset by unfavorable changes in the valuation of interest rate swap derivatives of $13 million and a $7 million settlement received in 2018 due to transformer related outages at the Solar Star projects in 2016.

Income tax (benefit) expense

Income tax benefit increased $325 million for the third quarter of 2019 compared to 2018, including $134 million related to the change in the unrealized position of the Company's investment in BYD Company Limited. The effective tax rate was (36)% for the third quarter of 2019 and 2% for the third quarter of 2018. The effective tax rate decreased primarily due to the lower income before taxes from the Company's investment in BYD Company Limited, higher production tax credits recognized of $101 million and the favorable impacts of ratemaking of $51 million.

Income tax benefit increased $160 million for the first nine months of 2019 compared to 2018 and the effective tax rate was (27)% for the first nine months of 2019 and (19)% for the first nine months of 2018. The effective tax rate decreased primarily due to higher production tax credits recognized of $146 million and the favorable impacts of ratemaking of $66 million, partially offset by $76 million of benefits recognized in 2018 related to the accrued repatriation tax on undistributed foreign earnings and foreign earnings.

Production tax credits are recognized in earnings for interim periods based on the application of an estimated annual effective tax rate to pretax earnings. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold based on a per-kilowatt rate pursuant to the applicable federal income tax law and are eligible for the credit for 10 years from the date the qualifying generating facilities are placed in-service. Production tax credits recognized in 2019 were $675 million, or $146 million higher than 2018, while production tax credits earned in 2019 were $504 million, or $90 million higher than 2018. The difference between production tax credits recognized and earned of $171 million as of September 30, 2019 will be reflected in earnings over the remainder of 2019.

Equity (loss) income

Equity (loss) income was unfavorable $13 million for the third quarter of 2019 compared to 2018 and $47 million for the first nine months of 2019 compared to 2018 primarily due to higher pre-tax equity losses from tax equity investments at BHE Renewables.


39


Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 16 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, 2018 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of September 30, 2019, the Company's total net liquidity was as follows (in millions):
 
 
 
 
 
MidAmerican
 
NV
 
Northern
 
BHE
 
 
 
 
 
BHE
 
PacifiCorp
 
Funding
 
Energy
 
Powergrid
 
Canada
 
Other
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
55

 
$
331

 
$
47

 
$
356

 
$
66

 
$
67

 
$
219

 
$
1,141

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Credit facilities(1)
3,500

 
1,200

 
1,309

 
650

 
185

 
661

 
1,945

 
9,450

Less:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Short-term debt
(1,514
)
 
—

 
—

 
—

 
—

 
(315
)
 
(1,290
)
 
(3,119
)
Tax-exempt bond support and letters of credit
—

 
(256
)
 
(370
)
 
—

 
—

 
(5
)
 
—

 
(631
)
Net credit facilities
1,986

 
944

 
939

 
650

 
185

 
341

 
655

 
5,700

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total net liquidity
$
2,041

 
$
1,275

 
$
986

 
$
1,006

 
$
251

 
$
408

 
$
874

 
$
6,841

Credit facilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Maturity dates(1)
2022

 
2022

 
2020, 2022

 
2022

 
2020

 
2023

 
2019,
2020, 2022

 
 

(1) 
Refer to Note 5 of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for further discussion regarding the Company's recent financing transactions.

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018 were $4.7 billion and $5.0 billion, respectively. The decrease was primarily due to changes in working capital, partially offset by an increase in income tax receipts.

The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2019 and 2018 were $(6.0) billion and $(4.5) billion, respectively. The change was primarily due to higher funding of tax equity investments and higher capital expenditures of $695 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.


40


Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2019 was $1.9 billion. Sources of cash totaled $4.1 billion and consisted of proceeds from subsidiary debt issuances totaling $3.5 billion and net proceeds from short-term debt totaling $594 million. Uses of cash totaled $2.2 billion and consisted mainly of repayments of subsidiary debt totaling $1.8 billion and common stock repurchases totaling $293 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the nine-month period ended September 30, 2018 was $(392) million. Uses of cash totaled $5.9 billion and consisted mainly of net repayments of short-term debt totaling $2.7 billion, repayments of subsidiary debt totaling $2.3 billion, repayments of BHE senior debt of $650 million and the purchase of redeemable noncontrolling interest of $131 million. Sources of cash totaled $5.5 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and proceeds from subsidiary debt issuances totaling $2.4 billion.

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.


41


The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
 
Nine-Month Periods
 
Annual
 
Ended September 30,
 
Forecast
 
2018
 
2019
 
2019
Capital expenditures by business:
 
 
 
 
 
PacifiCorp
$
713

 
$
1,449

 
$
2,292

MidAmerican Funding
1,466

 
1,909

 
2,880

NV Energy
342

 
448

 
676

Northern Powergrid
446

 
372

 
537

BHE Pipeline Group
251

 
403

 
770

BHE Transmission
203

 
175

 
239

BHE Renewables
741

 
97

 
122

HomeServices
34

 
38

 
58

BHE and Other
7

 
7

 
8

Total
$
4,203

 
$
4,898

 
$
7,582


Capital expenditures by type:
 
 
 
 
 
Wind generation
$
1,696

 
$
2,060

 
$
2,831

Electric transmission
118

 
472

 
655

Other growth
504

 
514

 
819

Operating
1,885

 
1,852

 
3,277

Total
$
4,203

 
$
4,898

 
$
7,582


The Company's historical and forecast capital expenditures consisted mainly of the following:
•Wind generation includes the following:
◦
Construction of wind-powered generating facilities at MidAmerican Energy totaling $1.0 billion and $704 million for the nine-month periods ended September 30, 2019 and 2018, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $420 million for 2019. MidAmerican Energy has approval to construct up to 2,591 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2017 through 2020, including 1,345 MW (nominal ratings) placed in-service as of September 30, 2019. Additionally, MidAmerican Energy is constructing an additional 205 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2020, with a forecast investment of $300 million, including AFUDC. This project is not under pre-approved ratemaking principles. Production tax credits from this project are expected be included in MidAmerican Energy's Iowa energy adjustment clause. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available.
◦
Repowering certain existing wind-powered generating facilities at MidAmerican Energy totaling $332 million and $233 million for the nine-month periods ended September 30, 2019 and 2018, respectively. The repowering projects entail the replacement of significant components of older turbines. MidAmerican Energy anticipates costs for these activities will total an additional $165 million for 2019. Of the 1,307 MW of current repowering projects not in-service as of September 30, 2019, 136 MW are currently expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service, 764 MW are expected to qualify for 80% of such credits and 407 MW are expected to qualify for 60% of such credits.
◦
Construction of wind-powered generating facilities at PacifiCorp totaling $245 million and $5 million for the nine-month periods ended September 30, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $104 million for 2019, which includes a new 240 MW wind-powered generating facility. The new wind-powered generating facilities are expected to be placed in-service in 2020. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available for ten years once the equipment is placed in-service.

42


◦
Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $442 million and $70 million for the nine-month periods ended September 30, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $180 million for 2019. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service.
◦
Construction of wind-powered generating facilities at BHE Renewables totaling $13 million and $684 million for the nine-month periods ended September 30, 2019 and 2018, respectively.
•
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 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, environmental spending relating to emissions control equipment and the management of coal combustion residuals.

Other Renewable Investments

The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the project sponsors that require contributions. The Company has made contributions of $1,145 million for the nine-month period ended September 30, 2019. Additionally, the Company has commitments as of September 30, 2019, subject to satisfaction of certain specified conditions, to provide equity contributions of $656 million for the remainder of 2019 and $1,760 million in 2020 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.

Contractual Obligations

As of September 30, 2019, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2018 other than the power purchase agreement termination discussed below and the recent financing transactions and renewable tax equity investments previously discussed.

In October 2019, Nevada Power terminated a power purchase agreement, due to the supplier's failure to satisfy its performance obligations as detailed in the agreement, that had annual contractual cash obligations of approximately $60 million in 2019 through 2023 and $1,145 million in 2024 and thereafter, as of December 31, 2018.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018, and new regulatory matters occurring in 2019.

PacifiCorp

Retirement Plan Settlement Charge

During 2018, the PacifiCorp Retirement Plan incurred a settlement charge of $22 million 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 memo account to track the costs associated with pension and postretirement settlements and curtailments. In April 2019, WUTC approved PacifiCorp's requested deferral. In May 2019, the UPSC denied PacifiCorp's request. In June 2019 and July 2019, PacifiCorp filed testimony with the WPSC and OPUC, respectively. In October 2019, the request for a memo account was re-filed as an application with the CPUC. A hearing was held before the WPSC in October 2019 and a decision is expected before the end of 2019.

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2017 Tax Reform

2017 Tax Reform 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%. In 2018, PacifiCorp agreed to refund or defer the impact of the tax law change with each of its state regulatory commissions. The status of the remaining 2017 Tax Reform proceedings is noted in the applicable state sections below.

Utah

In March 2018, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $3 million, or 0.1%, in deferred net power costs from customers for the period January 1, 2017 through December 31, 2017, reflecting the difference between base and actual net power costs in the 2017 deferral period. The rate change was approved by the UPSC effective May 1, 2018 on an interim basis. A hearing was held in February 2019, and final approval was issued March 2019.

In March 2019, PacifiCorp filed its annual EBA with the UPSC seeking approval to recover $24 million, or 1.1%, in 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 is scheduled for February 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 must adopt a resolution with a goal to be on 100% renewable electricity by 2030 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. Several communities in Utah, including Salt Lake City, have either recently set renewable goals or are actively considering them.

Oregon

In December 2018, PacifiCorp proposed to reduce customer rates to reflect the lower annual current income tax expense in Oregon resulting from 2017 Tax Reform. PacifiCorp reached an all-party settlement on the amortization of the current income tax expense benefits and the deferral of the decision regarding the ratemaking treatment of excess deferred income tax balances until no later than PacifiCorp's next general rate proceeding. The settlement, which results in a rate reduction of $48 million, or 3.7%, effective February 1, 2019, was approved by the OPUC in January 2019.

In December 2018, PacifiCorp filed the 2019 RAC application requesting recovery of $37 million, or a 2.8% increase in rates, associated with repowering of approximately 900 MW of company-owned and installed wind facilities expected to be completed in 2019. In March 2019, the application was updated to request recovery of $32 million, or a 2.5% increase in rates. In August 2019, PacifiCorp filed an all-party settlement for the 2019 RAC. The settlement provides for an $11 million or 0.8% rate increase effective October 1, 2019, and a rate increase of $13 million or 1.0% effective December 1, 2019 for a total rate increase of $24 million or 1.8%. In September 2019, the commission approved the all-party settlement for the 2019 RAC. Per the terms of the settlement agreement, the October 1, 2019 rate increase of 0.7% was based upon a final cost update of $9 million that was filed in early September 2019. The December 1, 2019 rate increase is subject to final cost updates.

Additionally as part of the commission-approved settlement, parties agreed that the Oregon-allocated net book value of certain undepreciated equipment that is replaced as a result of repowering in 2019, which was approximately $157 million as of September 30, 2019, will be depreciated and offset with excess deferred income taxes resulting from 2017 Tax Reform. In September 2019, $65 million of the estimated $157 million was recognized based on repowering activities completed through September 30, 2019.

In April 2019, PacifiCorp submitted its annual TAM filing in Oregon requesting an annual decrease of $15 million, or an average rate decrease of 1.2%, based on forecasted net power costs and loads for calendar year 2020. The filing includes the customer benefits of repowering, including an increase in production tax credits. In September 2019, PacifiCorp filed an all-party settlement for the 2020 TAM. The settlement provides for a rate decrease of $20 million from the 2019 TAM, or an average rate decrease of 1.6%, effective January 1, 2020. In October 2019, the commission approved the all-party settlement.

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In May 2019, PacifiCorp filed an application for deferral of incremental costs associated with implementing wildfire mitigation measures in Oregon. Operations and maintenance costs associated with the implementation measures are estimated to be $5 million in 2019.

Wyoming

In April 2018, PacifiCorp filed a partial settlement related to the impact of 2017 Tax Reform with the WPSC that provided a rate reduction of $23 million, or 3.3%, effective July 1, 2018 through June 30, 2019, with the remaining tax savings to be deferred with offsets to other costs. In June 2018, PacifiCorp filed reports with the WPSC with the calculation of the full impact of the tax law change on revenue requirement of $28 million annually, comprised of $20 million in current tax savings and $8 million for the amortization of excess deferred income tax balances. In March 2019, the WPSC issued a written order approving the continued annual rate reduction of $23 million until base rates are reset in the next general rate proceeding and a $4 million offset to PacifiCorp's 2018 ECAM rates. The order reflected the $20 million of current tax savings and was updated to reflect a projection of $7 million for amortization of excess deferred income tax balances. In April 2019, PacifiCorp filed a new application updating the amount of benefits being returned to customers. PacifiCorp continued the interim rate reduction that includes the previously approved $23 million and an additional $4 million reduction to offset the 2019 ECAM, effective June 15, 2019. A hearing will be held before the WPSC in November 2019 and a decision is expected before the end of 2019.

In April 2019, PacifiCorp submitted a compliance filing to the WPSC regarding bonus tax depreciation resulting in a $2 million rate reduction for the period June 15, 2019 through June 14, 2020.

In February 2019, PacifiCorp filed a certificate of public convenience and necessity application with the WPSC requesting to repower the existing Foote Creek I wind facility, which was approved without conditions in April 2019. In connection with the repowering of Foote Creek, PacifiCorp acquired the joint owner's 21% interest in the facility in June 2019.

In April 2019, PacifiCorp filed its annual ECAM and RRA application with the WPSC. The filing requests approval to recover from customers $7 million, or approximately 1.0%, in deferred net power costs for the period January 1, 2018 through December 31, 2018. The rate change went into effect on an interim basis June 15, 2019. In August, a joint notice of no contest was filed with the WPSC on behalf of PacifiCorp and the Wyoming Industrial Energy Consumers, the only intervenor in the proceeding. Interim rates are expected to be approved as final before the end of 2019. PacifiCorp has proposed to offset this increase with other rate credits that went into effect on June 15, 2019.

In July 2019, Wyoming Senate Enrolled Act No. 74 went into effect. The legislation, among other things, requires electric utilities to make a good faith effort to sell a coal-fired 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 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. PacifiCorp is working with the WPSC and other stakeholders to determine the implementation process. The overall impacts of this legislation cannot be determined at this time.
 
Washington

In June 2019, PacifiCorp submitted its 2018 PCAM filing with WUTC seeking approval to credit $7 million to the PCAM balancing account. No rate changes were requested.

Idaho

In May 2018, the IPUC approved a rate reduction of $6 million, or 2.2%, effective June 1, 2018 through May 31, 2019, to pass back a portion of the current tax benefits associated with 2017 Tax Reform. In March 2019 an all-party settlement resolving the treatment of the remaining tax savings was filed with the IPUC. In May 2019, the IPUC approved the all-party settlement resulting in the rate reduction for current tax savings being adjusted to $8 million per year, effective June 1, 2019 and $3 million related to amortization of excess deferred income taxes from the 2017 Tax Reform being applied as an offset to the 2019 ECAM.


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In March 2019, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $15 million, or 0.4%, for deferred costs in 2018. 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, recovery of Deer Creek Mine investment and changes in production tax credits and renewable energy credits. In May 2019, the IPUC approved recovery of the $15 million, effective June 1, 2019 to be offset by the $3 million related to amortization of excess deferred income taxes stemming from the all-party settlement related to the 2017 Tax Reform.
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 is anticipated by April 2020.

On September 21, 2018, California's governor signed legislation to strengthen California's ability to prevent and recover from catastrophic wildfires, including SB 901. SB 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp filed its wildfire mitigation plan with the CPUC on February 6, 2019. The wildfire mitigation plan incorporates the requirements outlined in SB 901, including situational awareness, system hardening, vegetation management and procedures for proactive de-energization in certain high risk areas during times of extreme danger.

SB 901 also authorized utilities, including PacifiCorp, to establish two memorandum accounts to track costs related to California Wildfire Mitigation. In March 2019, PacifiCorp received approval to establish a FRMMA effective January 1, 2019 to track a range of fire risk mitigation activities incremental to what is already included in PacifiCorp's rates. The CPUC also granted PacifiCorp the ability to track costs related to complying with the implementation of Proactive Safety Power Shut-off, or de-energization events in the FRMMA.

In May 2019, the CPUC issued a decision approving PacifiCorp's 2019 Wildfire Mitigation Plan. In June 2019, following approval of its 2019 Wildfire Mitigation Plan, PacifiCorp filed to establish a second Wildfire Mitigation Plan Memorandum Account effective May 31, 2019, to track costs related to the implementation of its approved 2019 Plan. Cost recovery is contingent on the CPUC's review of activities tracked in the memorandum accounts.

SB 901 also required the CPUC to develop a financial stress test methodology to determine the maximum amount an electrical corporation's shareholders can pay for 2017 catastrophic wildfire damages without harming ratepayers or impacting the utility's ability to provide adequate and safe service. The CPUC's final decision in June 2019 regarding this test does not have an impact on PacifiCorp as its assets did not cause catastrophic wildfires in California in 2017.

In July 2019, California's governor signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California. The new law authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities participate by making the required contributions, among other things. In August, PacifiCorp notified the CPUC that it will not participate in the wildfire fund.

AB 1054 also amends CPUC requirements for recovery of wildfire-related costs regardless of participation in the insurance fund. The CPUC must allow cost recovery of the costs and expenses of a "covered wildfire" which is defined as a fire ignited on or after July 12, 2019, if they are determined to be just and reasonable, meaning the electrical corporation's conduct related to the ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available to the electrical corporation at the relevant point in time.

NV Energy (Nevada Power and Sierra Pacific)

Regulatory Rate Review

In June 2019, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue increase of $5 million but requested an annual revenue reduction of $5 million. In September 2019, Sierra Pacific filed an all-party settlement for the electric regulatory rate review. The settlement resolves all cost of capital and revenue requirement issues and provides for an annual revenue reduction of $5 million. The rate design portion of the regulatory rate review was not a part of the settlement and is expected to go to hearing in November 2019. An order is expected by the end of 2019 and, if approved, would be effective January 1, 2020.

In August 2019, as a part of the annual DEAA filing, the PUCN issued an order confirming the methodology of calculating the earnings sharing and directed Nevada Power, in its next regulatory rate review in June 2020, to address the return of the earnings sharing to customers.

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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. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. The Nevada Utilities have filed opening briefs and the intervening parties have filed answering briefs. Oral arguments on the petition have been scheduled for January 2020.

Optional Pricing Program

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Optional Pricing Program ("OPP"). The Nevada Utilities have designed the OPP to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the Nevada Revised Statutes, with a market-based pricing option that is based on renewable resources. The OPP provides for an energy rate that would replace the base tariff energy rate 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 but plan to refile a modified tariff in December 2019 that incorporates the considerations raised by intervenors.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one MW or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs. In June 2019, the Nevada Legislature passed Senate Bill 547 ("SB 547") which modifies the 704B process. The modifications outlined in SB 547, among others, require a utility to establish limits in their integrated resource plan on the amount of load that can take service under Chapter 704B, customers taking service under Chapter 704B continue to pay for public program costs and requires the alternative energy providers to be licensed by the PUCN. In addition, SB 547 requires customers to file a 704B application with the PUCN in January allowing for alignment with the capacity amount established in the integrated resource plan.

Since 2016, five fully bundled retail customers have transitioned to distribution only service and are acquiring energy from an energy supplier other than the Nevada Utilities. The total estimated peak demand of these customers was approximately 400 MW, as of the date their applications were filed with the PUCN, which represents approximately 5% of the annual hourly peak demand on the Nevada Utilities' electric system in 2018. The PUCN has imposed cumulative impact fees of $155 million on these customers which includes impact fee credits of $20 million established by the PUCN subsequent to the initial application approvals.

The Nevada Utilities have approximately 120 fully bundled retail customers that are eligible to file Chapter 704B applications. The PUCN has approved the applications of five additional fully bundled retail customers whose total estimated peak demand is approximately 95 MW, as of the date their applications were filed with the PUCN. The PUCN has imposed impact fees of $30 million on these customers. Subsequent to approval, three customers with a total estimated peak demand of approximately 85 MW and imposed impact fees of $27 million have withdrawn their applications leaving only two fully bundled customer applications open and approved. The PUCN has also approved the applications of four pending customers not yet receiving service. These six customers have not yet become distribution only service customers.


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As of September 2019, in addition to the approved 704B applications, the Nevada Utilities have also received communications from eight additional fully bundled or pending customers, three of which provided a letter of intent to file an application with the PUCN and five of which filed an application with the PUCN to purchase energy from another energy supplier and become distribution only service customers. The five applicants have subsequently withdrawn their applications leaving no 704B applications awaiting consideration for approval. The three customers who filed letters of intent are no longer eligible to pursue 704B applications under the previous process due to the passage of SB 547.

The Nevada Utilities are addressing further Chapter 704B activity by evaluating options that include aligning with customer initiatives, implementing alternative pricing plans including the OPP, educating current customers on the value of the Nevada Utilities' fully bundled service and evaluating legislative or administrative changes to the Chapter 704B process as a result of SB 547.

Northern Powergrid Distribution Companies

GEMA, through the Ofgem, published its RIIO-2 sector methodology consultation in December 2018, continuing the process of developing the next set of price control arrangements that will be implemented for transmission and gas distribution networks in Great Britain. Ofgem explicitly states that this consultation does not set out proposals for Northern Powergrid's next price control, which will begin in April 2023. However, it also states that some of the proposals may be capable of application to that price control. Regarding allowed return on capital, Ofgem stated in the December 2018 consultation that it considered a cost of equity of 4.0% (plus inflation calculated using the United Kingdom's consumer prices index including owner occupiers' housing costs) would be appropriate for energy networks, which is approximately 2.5 percentage points lower than the current comparable cost of equity. This cost of equity assumption is based on a proposed debt capitalization assumption for the next price control of 60%, which is five percentage points lower than the 65% debt capitalization assumption for the current price control.

In May 2019, Ofgem published its sector methodology decision for the RIIO-2 price controls that will apply to transmission and gas distribution starting in April 2021. The decision confirmed a continued intention to move to lower returns, although Ofgem increased its initial view on the cost of equity of 4.0% to 4.3%. The transmission and gas distribution price control reviews are now moving into a detailed implementation phase, with draft and final determinations due in the summer and fall of 2020. In August 2019, Ofgem published its initial consultation on the next electricity distribution price control review, which is due to set price controls from April 2023. This initial consultation will be followed by a framework decision in the fourth quarter of 2019, a methodology consultation (and decision) in 2020 and initial and final determinations in 2022.
 
BHE Pipeline Group

Northern Natural Gas

In July 2018, the FERC issued a final rule adopting procedures for determining whether natural gas pipelines were collecting unjust and unreasonable rates in light of the reduction in the federal corporate tax rate from 2017 Tax Reform. Pursuant to the final rule, 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 full cost and revenue study on April 1, 2019. On July 1, 2019, Northern Natural Gas filed a Section 4 rate case. Northern Natural Gas has requested increases in various rates, including transportation reservation rates ranging from approximately 35% in the Field Area to 90% in the Market Area to be implemented, subject to refund, effective January 1, 2020. On September 12, 2019, FERC consolidated the Section 5 investigation and the Section 4 rate case into one procedural process set for hearing commencing June 23, 2020.


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BHE Transmission

AltaLink

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 for customers for the next five years. The three-year application achieves flat tariffs by keeping operating and maintenance expenses flat, with the exception of salaries and wages and software licensing fees, transitioning to a new salvage recovery approach and continuing the use of the flow-through income tax method. In addition, similar to the refund approved by the AUC for the 2017-2018 GTA of C$31 million, AltaLink proposes to provide a further tariff reduction over the three years by refunding previously collected accumulated depreciation surplus of an additional C$31 million. In November 2018, the AUC approved the 2019 interim refundable transmission tariff at C$74 million per month effective January 2019.

AltaLink provided responses to information requests in November 2018 and additional responses in December 2018 and April 2019. In April 2019, AltaLink filed an update to its 2019-2021 GTA application primarily to reflect its 2018 actual results and the impact of the AUC's decision on AltaLink's 2014-2015 Deferral Account Reconciliation Application. The application update also included AltaLink's fire mitigation plan and a request for additional capital expenditures and operating expenses to enhance its current practices, operations and maintenance program to reduce the risk of fires. The application requests the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021 respectively, which are lower than the approved 2018 revenue requirement of C$904 million. The forecast revenue requirement is based on an 8.5% return on equity and 37% deemed equity approved by the AUC for 2019 and 2020 and assumes the same for 2021 as placeholders.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions from the April 2019 GTA of C$23 million of operating expenses and C$58 million of transmission capital maintenance and information technology capital expenditures over three years, as well as lower forecast interest rates and lower depreciation for the steel poles asset class. These reductions resulted in a C$38 million net decrease to the three-year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this may be partially 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 matters consisting of the new salvage study and salvage recovery approach, additional capital for operations and maintenance and capital programs to reduce risk of fires, and to comply with line clearance code compliance requirements, and certain retirements for towers and fixtures. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters will be examined by the AUC in a hearing scheduled for November 2019. If AltaLink is successful at hearing on the excluded matters and the negotiated settlement is approved, the revised revenue requirements will be C$873 million, C$870 million and C$870 million for 2019, 2020 and 2021, respectively, which are lower than the approved 2018 revenue requirement of C$904 million.

In August 2019, AltaLink responded to information requests with respect to its 2019-2021 negotiated settlement application and the excluded matters as described above. The hearing to examine the excluded matters is now scheduled for November 2019, and a decision from the AUC is expected in the second quarter of 2020.


2021 Generic Cost of Capital Proceeding

In December 2018, the AUC initiated a Generic Cost of Capital ("GCOC") proceeding to consider returning to a formula-based approach to determining the return on equity for a given year, starting with 2021. On April 4, 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. The AUC also issued a process timeline for the proceeding to commence in January 2020, with a hearing scheduled in April 2020.

Deferral Account Reconciliation Applications

In April 2017, AltaLink filed its application with the AUC with respect to AltaLink's 2014 projects and deferral accounts and specific 2015 projects. The application included approximately C$2.0 billion in net capital additions. In June 2017, the AUC ruled that the scope of the deferral account proceeding would not be extended to consider the utilization of assets for which final cost approval is sought. However, the AUC will initiate a separate proceeding to address the issue of transmission asset utilization and how the corporate and property law principles applied in the Utility Asset Disposition ("UAD") decision may relate.


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In December 2017, AltaLink amended its application to include the remaining capital projects completed in 2015. The amended 2014 and 2015 Deferral Account Reconciliation Application includes 110 completed projects with total gross capital additions, including AFUDC, of C$4,017 million. A hearing was held in September 2018 after the completion of an extensive information request process earlier in the year.

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, including AFUDC, 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 requested supporting documentation for certain specific items. In February 2019, AltaLink filed its 2014-2015 Deferral Account Reconciliation Application compliance filing to reflect the findings, conclusions and directions arising from these decisions. In its compliance filing, AltaLink requested approval of interest in the amount of C$10 million on total outstanding amount of C$110 million to be recovered through a one-time payment from the AESO, upon AUC approval. In addition, the AUC ruled that it will put in placeholder amounts for the approved costs of the assets in the 2014-2015 Deferral Account Reconciliation Application proceeding until the AUC-initiated proceeding to consider the issue of transmission asset utilization.

In March 2019, AltaLink responded to information requests from the AUC. In August 2019, the AUC issued its decision with respect to AltaLink’s 2014-2015 Deferral Account Reconciliation Application compliance filing. The AUC ruled that AltaLink has complied with all directives from the December 2018 and January 2019 decisions with the exception of C$2 million of capital costs that were transferred from a canceled project to a completed one. AltaLink was directed to remove this amount and recover the cost directly from FortisAlberta. The AUC also approved C$9 million of the C$10 million in interest requested by AltaLink in its compliance filing. In September 2019, AltaLink filed a second compliance filing reflecting the directives from the AUC's August 2019 decision. Final AUC approval is expected by the end of 2019.

In July 2019, AltaLink filed its 2016-2018 Deferral Account Reconciliation Application with the AUC after a ruling on confidentiality. The application includes 116 projects with total actual gross capital additions, including AFUDC, of C$976 million.

In October 2019, AltaLink provided responses to a large number of information requests regarding its 2016-2018 Deferral Account Reconciliation Application. The balance of the process steps and related schedule will be established following completion of the information request process. In October 2019, AltaLink filed its Edmonton Region Project as a standalone application. The capital cost of this project was included as a placeholder in its 2016-2018 Deferral Account Reconciliation Application.

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 will 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 and add the amount to AltaLink's rate base if the decision is upheld. The AUC directed the AESO to consult with AltaLink to provide a joint proposal to implement AltaLink's contribution proposal. 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 expected to be closed in November 2019.


First Nations Asset Transfer Application

In November 2018, the AUC approved, with conditions, AltaLink's application filed in April 2017 to sell and transfer approximately C$91 million of transmission assets located on reserve lands to new limited partnerships with First Nations. The transfers are part of the agreement which allowed AltaLink to route the Southwest Project on reserve land.

In December 2018, AltaLink filed an application with the Alberta Court of Appeal for permission to appeal the conditions imposed by the AUC's decision. In January 2019, AltaLink also filed an application for review and variance with the AUC. The application with the AUC was for review and variance of the conditions imposed by the AUC with respect to no cost recovery of certain incremental costs and no deferral account treatment for annual structure payments. In May 2019, the AUC issued a decision dismissing the application for review and variance on the basis that AltaLink had not met the requirements for a review of the findings in the original decision. In October 2019, the hearing for permission to appeal the AUC's decision was held. The Court of Appeal's decision will be issued in due course.

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In March 2019, AltaLink filed correspondence informing the AUC that the Blood Tribe intends to proceed with the transfer of assets related to KainaiLink, L.P.

In June 2019, AltaLink closed the transaction with the Piikani Nation by transferring transmission assets of C$53 million and long-term debt of C$33 million to PiikaniLink, L.P. The Piikani Nation purchased a 51% interest in PiikaniLink, L.P. for C$10 million.

BHE Renewables' Counterparty Risk

On January 29, 2019, PG&E Corporation and Pacific Gas and Electric Company (the "PG&E Utility") (together "PG&E") filed voluntary petitions for relief under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Northern District of California ("PG&E Bankruptcy Filing"). The Company owns 100% of Topaz and owns a 49% interest in Agua Caliente. Topaz is a 550-MW solar photovoltaic electric power generating facility located in California. Topaz sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale power purchase agreement ("PPA") that is in effect until October 2039. As of September 30, 2019, the Company's consolidated balance sheet includes $1.0 billion of property, plant and equipment, net and $0.9 billion of non-recourse project debt related to Topaz. Agua Caliente is a 290-MW solar photovoltaic electric power generating facility located in Arizona. Agua Caliente sells 100% of its energy, capacity and renewable energy credits generated from the facility to PG&E Utility under a 25-year wholesale PPA that is in effect until June 2039. As of September 30, 2019, the Company's equity investment in Agua Caliente totals $70 million and the project has $0.8 billion of non-recourse project debt owed to the United States Department of Energy. The PG&E Bankruptcy Filing is an event of default under the Topaz PPA ("PPA Default"). PG&E paid in full the invoices for December deliveries and all amounts invoiced to date for post-petition energy deliveries for both Topaz and Agua Caliente in 2019. PG&E has not paid for the power delivered from January 1 through January 28, 2019. The Company continues to perform on its obligations and deliver renewable energy to the PG&E Utility, and PG&E has publicly stated it will pay suppliers in full under normal terms for post-petition goods and services received. The Company maintains that, in light of the current facts and circumstances, the PPA Default could not reasonably be expected to result in a material adverse effect under the Topaz indenture and, therefore, no default has occurred under the Topaz indenture. In July 2019, the California Governor signed AB 1054 into law. AB 1054 is comprehensive legislation addressing wildfire risk in the state of California that, among other items, authorizes a wildfire fund which would operate as an insurance fund to support the creditworthiness of electrical utilities, if certain utilities, including PG&E, participate by making the required contributions, among other things. In July 2019, PG&E notified the CPUC of its intent to participate in the insurance fund and such participation requires, among other items, PG&E to exit bankruptcy by June 30, 2020. The Company believes it is more likely than not that no impairment exists and current debt obligations will be met, as post-petition contractual revenue payments are expected to be paid by PG&E Utility to the Topaz and Agua Caliente projects. The Company will continue to monitor the situation, including continued receipt of future PG&E payments and the future risk of the PPAs being rejected or modified through the bankruptcy process.

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, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and worked with Exelon Generation on solutions to that end. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the case was denied.


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On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation has filed protests at the FERC in response to each filing. The FERC has not yet issued a decision on the requests.

On April 10, 2019, PJM Interconnection, L.L.C. ("PJM") notified the FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked the FERC to clarify that it would not require the PJM to re-run the auction in the event the FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM's request to clarify that any alteration of PJM's existing market rules would operate prospectively and directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings or their potential impact on the continued operation of Quad Cities Station.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in material compliance with all applicable laws and regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018, and new environmental matters occurring in 2019.

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 greenhouse gas emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global greenhouse gas emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. Under the terms of the Paris Agreement, ratifying countries are bound for a three-year period and must provide one-year's notice of their intent to withdraw. On June 1, 2017, President Trump announced the United States would withdraw from the Paris Agreement. Under the terms of the agreement, the withdrawal would be effective in November 2020. The cornerstone of the United States' commitment was the Clean Power Plan which was finalized by the EPA in 2015 but has since been proposed for repeal by the EPA.


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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-fueled with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the United States Court of Appeals for the District of Columbia Circuit ("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. The 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. The EPA accepted comment on the proposal through March 18, 2019. Until such time as the EPA undertakes further action on the proposed reconsideration or the court takes action, any new fossil-fueled generating facilities constructed by the relevant Registrants will be required to meet the GHG new source performance standards.

Clean Power Plan

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 compliance period would have begun in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030 and was expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. On February 9, 2016, the United States Supreme Court ordered that the EPA's emission guidelines for existing sources be stayed pending the disposition of the challenges to the rule in the D.C. Circuit and any action on a writ of certiorari before the United States Supreme Court. Oral argument was heard before the D.C. Circuit on September 27, 2016. The court has not yet issued its decision. On June 19, 2019, the EPA finalized the Affordable Clean Energy rule and fully repealed the Clean Power Plan. Under the Affordable Clean Energy rule, the EPA determined that the best system of emissions reduction for existing coal-fueled power plants is heat rate improvements based on a set of candidate technologies and measures that could improve heat rates. The EPA did not establish state emission limits or budgets. Instead, states will be required to develop unit-specific standards of performance that reflect the emission limitation achievable through application of the best system of emission reduction technologies. Measures taken to meet the standards of performance must be achieved at the source itself and standards of performance will be measured in terms of pounds of carbon dioxide per MWh. State compliance plans are due by September 2022, three years after the effective date of the rule. Litigation challenging the rule has already been filed in the D.C. Circuit and until all litigation is exhausted and state plans are developed, the full impacts on the Registrants cannot be determined. However, 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.

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.

Since 1997, NV Energy has been required to comply with a RPS. Current law requires the Nevada Utilities to meet 18% of their energy requirements with renewable resources for 2014, 20% for 2015 through 2019, 22% for 2020 and 2024, and 25% for 2025 and thereafter. The RPS also requires 5% of the portfolio requirement come from solar resources through 2015 and increasing to 6% in 2016. Nevada law also permits energy efficiency measures to be used to satisfy a portion of the RPS through 2025, subject to certain limitations. In November 2018, Nevada voters approved a measure to increase the state's RPS to 50% by 2030; the measure must be voted on and approved a second time, in November 2020, in order to take effect. In the interim, the Nevada Legislature passed Senate Bill ("SB") 358 in June 2019 which raises Nevada's renewable portfolio standards to 50% by 2030.

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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 No. 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, establishes three targets for reducing and eventually eliminating fossil-fueled generation from Washington retail electricity rates between 2025 and 2045. The coal phase-out standard requires all electric utilities to eliminate from rates, coal-fired resources by December 31, 2025. PacifiCorp has begun discussions with regulators and other Washington investor-owned utilities regarding compliance obligations and implementation.

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.

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.


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On December 27, 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. EPA proposes to determine that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112; however, EPA proposes to retain the emission standards and other requirements of the MATS rule, because EPA is not proposing to remove coal- and oil-fueled power plants from the list of sources regulated under Section 112. The public comment period on the proposal closed April 17, 2019. Until EPA takes final action on the rule, the relevant Registrants cannot fully determine the impacts of the proposed changes to the MATS rule.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of nitrogen oxides and sulfur dioxide, precursors of ozone and particulate matter, from up-wind states affecting the ability of states in the eastern United States to attain or maintain compliance with NAAQS. After numerous appeals, the CSAPR was promulgated to address interstate transport of sulfur dioxide and nitrogen oxides 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 nitrogen oxides emissions. The final "CSAPR Update Rule" was published in the Federal Register in October 2016. On December 6, 2018, the EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update Rule fully addresses Clean Air Act interstate transport obligations for the 2008 ozone NAAQS of 20 eastern states.

The various CSAPR rules have been litigated. In September 2019, the D.C. Circuit Court ruled in State of Wisconsin v. EPA, concerning the CSAPR Update Rule that, because the EPA allowed upwind states to continue their significant contributions to downwind air quality problems beyond the deadline for attainment with the 2008 ozone NAAQS, the CSAPR Update Rule provided only a partial remedy and remanded the CSAPR Update Rule back to the EPA. The court also held that the remaining framework for the CSAPR program was legally sound. The D.C. Circuit Court issued a second opinion in State of New York v. EPA on October 1, 2019, regarding challenges to the CSAPR Close-Out Rule. The court held that the CSAPR Close-Out Rule must also be vacated because it rested on an identical interpretation of the Clean Air Act as the CSAPR Update Rule. The deadline to petition for rehearing in both cases was October 28, 2019.

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 and does not anticipate that any impacts of the CSAPR update will be significant.

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, all of which are subject to the CSAPR. However, the provisions are not anticipated to have a material impact on Berkshire Hathaway Energy or MidAmerican Energy. 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 national ambient air quality standard 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 nitrogen oxides emissions. Until the EPA takes final action consistent with these judicial orders, the 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 best available retrofit technology ("BART") requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.


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The state of Utah issued a regional haze SIP requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the sulfur dioxide portion of the Utah regional haze SIP and disapproved the nitrogen oxides 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 nitrogen oxides controls and require the installation of selective catalytic reduction ("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 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") air quality dispersion model. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze state implementation plan revision, which incorporates a best available retrofit technology alternative into Utah's regional haze state implementation plan. The best available retrofit technology alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the state implementation plan and removes the requirement to install selective catalytic reduction technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality anticipates submitting the state implementation plan revision to the EPA for approval by the end of 2019.

The state of Wyoming issued two regional haze SIPs requiring the installation of sulfur dioxide, nitrogen oxides and particulate matter controls on certain PacifiCorp coal-fueled generating facilities in Wyoming. The EPA approved the sulfur dioxide 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 nitrogen oxides and particulate matter SIP and instead issue a FIP. The EPA withdrew its initial proposed actions on the nitrogen oxides 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-nitrogen oxides 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-nitrogen oxides 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 ("Wyodak 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 the Wyodak Facility 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 the Wyodak Facility, pending further action by the Tenth Circuit in the appeal. A stay remains in place and the case has not yet been set for oral argument. 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 October 2016, an application was filed with the Wyoming Department of Environmental Quality requesting a revision of the dates for the end of coal firing and the start of gas firing for Naughton Unit 3 to align with the requirements of the Wyoming SIP. The Wyoming Department of Environmental Quality approved a change to the requirements for Naughton Unit 3, extending the requirement to cease coal firing to no later than January 30, 2019, and complete the gas conversion by June 30, 2019. On March 17, 2017, Wyoming Department of Environmental Quality issued an extension to operate the unit as a coal-fueled unit through January 30, 2019. The Wyoming Department of Environmental Quality submitted a proposed revision to the Wyoming SIP, including a change to the Naughton Unit 3 compliance date, to the EPA for approval on November 28, 2017. On November 7, 2018, the EPA published its proposed approval of the Wyoming SIP relative to the Naughton 3 gas conversion. The comment period closed December 7, 2018. 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 determined in its 2019 IRP that converting Naughton Unit 3 to a natural gas-fueled generation resource provides economic benefits to customers. PacifiCorp’s 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 selective catalytic reduction, to be replaced with a permit imposing plant-wide emission limits to achieve better modeled visibility, fewer overall environmental impacts and lower costs of compliance. The proposal was issued for public comment in August 2019, and the state of Wyoming held a public hearing on August 23, 2019 to consider the proposal and public input. The state of Wyoming is developing responses to public comment and is anticipated to submit the proposal to EPA by the end of 2019.

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The state of Arizona issued a regional haze SIP requiring, among other things, the installation of sulfur dioxide, nitrogen oxides 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.

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. The terms of the agreement were incorporated into an amended Colorado regional haze SIP in 2017 and were submitted to the EPA for its review and approval. The EPA's approval of the amended Colorado regional haze SIP was published in the Federal Register on July 5, 2018, with an effective date of August 6, 2018.

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.

The Navajo Generating Station, in which Nevada Power is a joint owner with an 11.3% ownership share, is also a source that is subject to the regional haze BART requirements. In January 2013, the EPA announced a proposed FIP addressing BART and an alternative for the Navajo Generating Station that includes a flexible timeline for reducing nitrogen oxides emissions. The EPA issued a final FIP on August 8, 2014 adopting, with limited changes, the Navajo Generating Station proposal as a "better than BART" determination. Nevada Power filed the ERCR Plan in May 2014 that proposed to eliminate its ownership participation in the Navajo Generating Station in 2019, which was approved by the PUCN. In February 2017, the non-federal owners of the Navajo Generating Station announced the facility will shut down on or before December 23, 2019, unless new owners can be found. All current owners have since approved a lease extension with the Navajo Nation to allow operations to continue through 2019. On March 21, 2019, the Navajo Nation Council voted to end efforts to transition ownership and extend facility operations. The plant will cease operations by the end of 2019. Ownership transfer negotiations and closure preparations are ongoing and, until concluded, the relevant Registrant cannot determine whether additional action may be required.


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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. In the event that 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 Appeal 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 Firth 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. While most of the issues raised by effluent limitation guidelines are already being addressed through the coal combustion residuals rule and are not expected to impose significant additional requirements on the facilities, the impact of the rule cannot be fully determined until the reconsideration and remand actions are complete and any judicial review is conducted.


58


In April 2014, the EPA and the United States Army 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 on 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. The public comment period closed April 15, 2019. Until the rule is fully litigated and finalized, the Registrants cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs or increased requirements for compensatory mitigation.

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 coal combustion residuals. 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 Station 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. Refer to Note 13 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Item 8 of the Form 10-K and Note 10 of the Notes to Consolidated Financial Statements of PacifiCorp in Item 8 of the Form 10-K for the impacts on asset retirement obligations as a result of the final rule.


59


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 coal combustion residuals 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 coal combustion residuals 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 coal combustion residuals 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 coal combustion residuals 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, without vacatur, leaving 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 coal combustion residuals 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 coal combustion residuals 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 coal combustion residual 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 coal combustion residuals rule. The EPA accepted comments on the Phase 2 proposal through October 15, 2019. Additional substantive revisions to the rule are expected to be finalized by the EPA by December 2019 but have not yet been released for public comment. If adopted, certain elements of the proposal have the potential to reduce costs of compliance. Until such time as the additional rulemaking is final, the impacts on the Registrants cannot be determined.

Separately, on August 10, 2017, the EPA issued proposed permitting guidance on how states' coal combustion residuals permit programs should comply with the requirements of the final rule as authorized under the December 2016 Water Infrastructure Improvements for the Nation Act. Utilizing that guidance, the state of Oklahoma submitted an application to the EPA for 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 United States District Court for the District of Columbia 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 coal combustion residuals. To date, none of the states in which the Registrants operate has submitted an application to the EPA for approval of state permitting authority. The state of Utah adopted the federal final rule in September 2016, which required two landfills to submit permit applications by March 2017. It is anticipated that the state of Utah will submit an application for approval of its coal combustion residuals permit program prior to the end of 2020. 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 state rule in late 2019 and will submit an application to the EPA to implement a state permit program in early 2020. 

Notwithstanding the status of the final coal combustion residuals 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 coal combustion residuals 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.


60


Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2018. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2018.


61


PacifiCorp and its subsidiaries
Consolidated Financial Section


62


PART I
Item 1.
Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholders of
PacifiCorp

Results of Review of Interim Financial Information
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of September 30, 2019, the related consolidated statements of operations and changes in shareholders' equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.
 
We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2018, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results
This interim financial information is the responsibility of PacifiCorp's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to PacifiCorp in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

 
Portland, Oregon
November 1, 2019


63


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

 
 
As of
 
 
September 30,
 
December 31,
 
 
2019
 
2018
ASSETS
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
331

 
$
77

Trade receivables, net
 
659

 
640

Other receivables, net
 
55

 
92

Inventories
 
421

 
417

Other current assets
 
137

 
133

Total current assets
 
1,603

 
1,359

 
 
 
 
 
Property, plant and equipment, net
 
20,608

 
19,570

Regulatory assets
 
1,057

 
1,076

Other assets
 
358

 
308

 
 
 
 
 
Total assets
 
$
23,626

 
$
22,313


The accompanying notes are an integral part of these consolidated financial statements.

64


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 
 
As of
 
 
September 30,
 
December 31,
 
 
2019
 
2018
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
 
 
 
 
Accounts payable
 
$
732

 
$
597

Accrued interest
 
110

 
114

Accrued property, income and other taxes
 
174

 
75

Accrued employee expenses
 
122

 
79

Short-term debt
 
—

 
30

Current portion of long-term debt
 
—

 
350

Regulatory liabilities
 
63

 
77

Other current liabilities
 
172

 
193

Total current liabilities
 
1,373

 
1,515

 
 
 
 
 
Long-term debt
 
7,657

 
6,665

Regulatory liabilities
 
2,951

 
2,978

Deferred income taxes
 
2,554

 
2,543

Other long-term liabilities
 
796

 
767

Total liabilities
 
15,331

 
14,468

 
 
 
 
 
Commitments and contingencies (Note 10)
 
 
 
 
 
 
 
 
 
Shareholders' equity:
 
 
 
 
Preferred stock
 
2

 
2

Common stock - 750 shares authorized, no par value, 357 shares issued and outstanding
 
—

 
—

Additional paid-in capital
 
4,479

 
4,479

Retained earnings
 
3,826

 
3,377

Accumulated other comprehensive loss, net
 
(12
)
 
(13
)
Total shareholders' equity
 
8,295

 
7,845

 
 
 
 
 
Total liabilities and shareholders' equity
 
$
23,626

 
$
22,313


The accompanying notes are an integral part of these consolidated financial statements.


65


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Operating revenue
$
1,367

 
$
1,369

 
$
3,793

 
$
3,746

 
 

 
 
 
 
 
 

Operating expenses:
 
 
 
 
 
 
 
Cost of fuel and energy
464

 
465

 
1,313

 
1,300

Operations and maintenance
252

 
266

 
763

 
777

Depreciation and amortization
272

 
203

 
686

 
602

Property and other taxes
46

 
49

 
146

 
150

Total operating expenses
1,034

 
983

 
2,908

 
2,829

 
 

 
 
 
 
 
 

Operating income
333

 
386

 
885

 
917

 
 

 
 
 
 
 
 

Other income (expense):
 

 
 
 
 
 
 

Interest expense
(101
)
 
(96
)
 
(299
)
 
(288
)
Allowance for borrowed funds
11

 
5

 
26

 
13

Allowance for equity funds
21

 
9

 
51

 
24

Interest and dividend income
5

 
4

 
17

 
10

Other, net
6

 
10

 
22

 
26

Total other income (expense)
(58
)
 
(68
)
 
(183
)
 
(215
)
 
 

 
 
 
 
 
 

Income before income tax (benefit) expense
275

 
318

 
702

 
702

Income tax (benefit) expense
(3
)
 
48

 
77

 
100

Net income
$
278

 
$
270

 
$
625

 
$
602


The accompanying notes are an integral part of these consolidated financial statements.


66


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)

 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
Additional
 
 
 
Other
 
Total
 
 
Preferred
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Shareholders'
 
 
Stock
 
Stock
 
Capital
 
Earnings
 
Loss, Net
 
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2018

$
2


$
—


$
4,479


$
3,071


$
(15
)

$
7,537

Net income
 
—

 
—

 
—

 
270

 
—

 
270

Common stock dividends declared
 
—

 
—

 
—

 
(50
)
 
—

 
(50
)
Balance, September 30, 2018
 
$
2

 
$
—

 
$
4,479

 
$
3,291

 
$
(15
)
 
$
7,757

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
 
$
2

 
$
—

 
$
4,479

 
$
3,089

 
$
(15
)
 
$
7,555

Net income
 
—

 
—

 
—

 
602

 
—

 
602

Common stock dividends declared
 
—

 
—

 
—

 
(400
)
 
—

 
(400
)
Balance, September 30, 2018
 
$
2

 
$
—

 
$
4,479

 
$
3,291

 
$
(15
)
 
$
7,757

 
 
 

 
 

 
 

 
 

 
 

 
 

Balance, June 30, 2019
 
$
2

 
$
—

 
$
4,479

 
$
3,548

 
$
(12
)
 
$
8,017

Net income
 
—

 
—

 
—

 
278

 
—

 
278

Balance, September 30, 2019
 
$
2

 
$
—

 
$
4,479

 
$
3,826

 
$
(12
)
 
$
8,295

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
 
$
2

 
$
—

 
$
4,479

 
$
3,377

 
$
(13
)
 
$
7,845

Net income
 
—

 
—

 
—

 
625

 
—

 
625

Other comprehensive income
 
—

 
—

 
—

 
(1
)
 
1

 
—

Common stock dividends declared
 
—

 
—

 
—

 
(175
)
 
—

 
(175
)
Balance, September 30, 2019
 
$
2

 
$
—

 
$
4,479

 
$
3,826

 
$
(12
)
 
$
8,295


The accompanying notes are an integral part of these consolidated financial statements.


67


PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
625

 
$
602

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
686

 
602

Allowance for equity funds
(51
)
 
(24
)
Changes in regulatory assets and liabilities
(31
)
 
127

Deferred income taxes and amortization of investment tax credits
(78
)
 
(53
)
Other, net
(3
)
 
(1
)
Changes in other operating assets and liabilities:
 
 
 

Trade receivables, other receivables and other assets
21

 
(21
)
Inventories
(4
)
 
4

Derivative collateral, net
5

 
4

Accrued property, income and other taxes, net
99

 
204

Accounts payable and other liabilities
(2
)
 
36

Net cash flows from operating activities
1,267

 
1,480

 
 
 
 

Cash flows from investing activities:
 
 
 

Capital expenditures
(1,449
)
 
(713
)
Other, net
9

 
2

Net cash flows from investing activities
(1,440
)
 
(711
)
 
 
 
 

Cash flows from financing activities:
 
 
 

Proceeds from long-term debt
990

 
593

Repayments of long-term debt
(350
)
 
(586
)
Net repayments of short-term debt
(30
)
 
(80
)
Dividends paid
(175
)
 
(400
)
Other, net
(2
)
 
(2
)
Net cash flows from financing activities
433

 
(475
)
 
 
 
 

Net change in cash and cash equivalents and restricted cash and cash equivalents
260

 
294

Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
92

 
29

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
352

 
$
323

 
The accompanying notes are an integral part of these consolidated financial statements.


68


PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)
General

PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2019 and for the three- and nine-month periods ended September 30, 2019 and 2018. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019 and 2018 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2018 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies, except as disclosed in Note 4, during the nine-month period ended September 30, 2019.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents consist substantially of funds representing escrow accounts for disputes, vendor retention, custodial and nuclear decommissioning funds. Restricted amounts are included in other current assets and other assets on the Consolidated Balance Sheets. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Cash and cash equivalents
$
331

 
$
77

Restricted cash included in other current assets
19

 
13

Restricted cash included in other assets
2

 
2

Total cash and cash equivalents and restricted cash and cash equivalents
$
352

 
$
92



69


(3)
Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
 
 
September 30,
 
December 31,
 
Depreciable Life
 
2019
 
2018
Utility Plant:
 
 
 
 
 
Generation
14 - 67 years
 
$
12,574

 
$
12,606

Transmission
58 - 75 years
 
6,468

 
6,357

Distribution
20 - 70 years
 
7,217

 
7,030

Intangible plant(1)
5 - 75 years
 
1,002

 
970

Other
5 - 60 years
 
1,429

 
1,436

Utility plant in service
 
 
28,690

 
28,399

Accumulated depreciation and amortization
 
 
(10,069
)
 
(10,034
)
Utility plant in-service, net
 
 
18,621

 
18,365

Other non-regulated, net of accumulated depreciation and amortization
47 years
 
10

 
10

Plant, net
 
 
18,631

 
18,375

Construction work-in-progress
 
 
1,977

 
1,195

Property, plant and equipment, net
 
 
$
20,608

 
$
19,570


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

(4)    Leases

Adoption

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. PacifiCorp adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative effect impact at the date of initial adoption.

PacifiCorp has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.


70


Leases

Lessee

PacifiCorp has non-cancelable operating leases primarily for land, office space, office equipment, and generating facilities and finance leases consisting primarily of office buildings, natural gas pipeline facilities, and generating facilities. These leases generally require PacifiCorp 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. PacifiCorp does not include options in its lease calculations unless there is a triggering event indicating PacifiCorp is reasonably certain to exercise the option. PacifiCorp's accounting policy is to not recognize lease obligations and corresponding right-of-use assets 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 ASC 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

PacifiCorp's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

PacifiCorp's 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. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation. The following table summarizes PacifiCorp's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
September 30,
 
2019
Right-of-use assets:
 
Operating leases
$
13

Finance leases
19

Total right-of-use assets
$
32

 
 
Lease liabilities:
 
Operating leases
$
13

Finance leases
19

Total lease liabilities
$
32



71


The following table summarizes PacifiCorp's lease costs (in millions):
 
Three-Month Period
 
Nine-Month Period
 
Ended September 30,
 
Ended September 30,
 
2019
 
2019
 
 
 
 
Variable
$
10

 
$
36

Operating
1

 
2

Finance:
 
 
 
Amortization
—

 
1

Interest
1

 
2

Short-term
—

 
1

Total lease costs
$
12

 
$
42

 
 
 
 
Weighted-average remaining lease term (years):

 
 
Operating leases
 
 
13.6

Finance leases
 
 
9.3

 
 
 
 
Weighted-average discount rate:
 
 
 
Operating leases
 
 
3.7
%
Finance leases
 
 
10.6
%

Cash payments associated with operating and finance lease liabilities approximated lease cost for the three- and nine-month periods ended September 30, 2019 and 2018, respectively.

PacifiCorp has the following remaining lease commitments as of (in millions):
 
September 30, 2019
 
December 31, 2018(1)
 
Operating
 
Finance
 
Total
 
Operating
 
Capital
 
Total
2019
$
1

 
$
1

 
$
2

 
$
3

 
$
4

 
$
7

2020
3

 
3

 
6

 
3

 
4

 
7

2021
2

 
7

 
9

 
3

 
7

 
10

2022
2

 
3

 
5

 
2

 
3

 
5

2023
2

 
2

 
4

 
2

 
2

 
4

Thereafter
7

 
16

 
23

 
7

 
16

 
23

Total undiscounted lease payments
17

 
32

 
49

 
$
20

 
$
36

 
$
56

Less - amounts representing interest
(4
)
 
(13
)
 
(17
)
 
 
 
 
 
 
Lease liabilities
$
13

 
$
19

 
$
32

 
 
 


 
 

(1)     Amounts included for comparability and accounted for in accordance with ASC 840, "Leases".  

(5)
Recent Financing Transactions

Long-Term Debt

In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay short-term debt that was partially incurred in January 2019 to repay all of PacifiCorp's $350 million 5.50% First Mortgage Bonds due January 2019 and intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.


72


Credit Facilities

In May 2019, PacifiCorp extended, with lender consent, the expiration date for each of its two existing $600 million unsecured credit facilities to June 2022 by exercising the remaining one-year extension option for one facility and exercising the first of two available one-year extensions for the second facility.

In March 2019, PacifiCorp completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, involving the cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations increased by $168 million.

(6)
Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
21
 %
 
21
 %
State income tax, net of federal income tax benefit
3

 
4

 
3

 
4

Federal income tax credits
(3
)
 
(5
)
 
(4
)
 
(5
)
Effects of ratemaking
(3
)
 
(4
)
 
(2
)
 
(4
)
Amortization of excess deferred income taxes
(18
)
 
—

 
(7
)
 
—

Other
(1
)
 
(1
)
 
—

 
(2
)
Effective income tax rate
(1
)%
 
15
 %
 
11
 %
 
14
 %

Income tax credits relate primarily to production tax credits earned by PacifiCorp's wind-powered generating facilities. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Amortization of excess deferred income taxes relates primarily to the amortization of $49 million of Oregon's allocated excess deferred income taxes pursuant to the Oregon Renewable Adjustment Clause settlement, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation on Oregon's share of replaced equipment associated with certain repowered wind facilities.



73


(7)
Employee Benefit Plans

Net periodic benefit credit for the pension and other postretirement benefit plans included the following components (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Pension:
 
 
 
 
 
 
 
Service cost
$
—

 
$
—

 
$
—

 
$
—

Interest cost
11

 
11

 
33

 
32

Expected return on plan assets
(17
)
 
(18
)
 
(50
)
 
(54
)
Net amortization
3

 
3

 
9

 
10

Net periodic benefit credit
$
(3
)
 
$
(4
)
 
(8
)
 
(12
)
 
 
 
 
 
 
 
 
Other postretirement:
 
 
 
 
 
 
 
Service cost
$
—

 
$
—

 
$
1

 
$
1

Interest cost
3

 
3

 
9

 
9

Expected return on plan assets
(6
)
 
(5
)
 
(16
)
 
(16
)
Net amortization
1

 
(1
)
 
1

 
(4
)
Net periodic benefit credit
$
(2
)
 
$
(3
)
 
(5
)
 
(10
)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $4 million and $- million, respectively, during 2019. As of September 30, 2019, $3 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)
Risk Management and Hedging Activities

PacifiCorp is exposed to the impact of market fluctuations in commodity prices and interest rates. PacifiCorp is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk as it has an obligation to serve retail customer load in its regulated service territories. PacifiCorp's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. Interest rate risk exists on variable-rate debt and future debt issuances. PacifiCorp does not engage in a material amount of proprietary trading activities.

PacifiCorp has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, PacifiCorp uses commodity derivative contracts, which may include forwards, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. PacifiCorp manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, PacifiCorp may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate PacifiCorp's exposure to interest rate risk. No interest rate derivatives were in place during the periods presented. PacifiCorp does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in PacifiCorp's accounting policies related to derivatives. Refer to Note 9 for additional information on derivative contracts.


74


The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
 
Other
 
 
 
Other
 
Other
 
 
 
Current
 
Other
 
Current
 
Long-term
 
 
 
Assets
 
Assets
 
Liabilities
 
Liabilities
 
Total
 
 
 
 
 
 
 
 
 
 
As of September 30, 2019
 
 
 
 
 
 
 
 
 
Not designated as hedging contracts(1):
 
 
 
 
 
 
 
 
 
Commodity assets
$
7

 
$
1

 
$
4

 
$
1

 
$
13

Commodity liabilities
(2
)
 
—

 
(34
)
 
(59
)
 
(95
)
Total
5

 
1

 
(30
)
 
(58
)
 
(82
)
 
 

 
 

 
 

 
 

 
 

Total derivatives
5

 
1

 
(30
)
 
(58
)
 
(82
)
Cash collateral receivable
—

 
—

 
20

 
34

 
54

Total derivatives - net basis
$
5

 
$
1

 
$
(10
)
 
$
(24
)
 
$
(28
)
 
 
 
 
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
 
 
 
 
Not designated as hedging contracts(1):
 
 
 
 
 
 
 
 
 
Commodity assets
$
36

 
$
4

 
$
10

 
$
1

 
$
51

Commodity liabilities
(9
)
 
(1
)
 
(67
)
 
(71
)
 
(148
)
Total
27

 
3

 
(57
)
 
(70
)
 
(97
)
 
 
 
 
 
 
 
 
 
 
Total derivatives
27

 
3

 
(57
)
 
(70
)
 
(97
)
Cash collateral (payable) receivable
(2
)
 
—

 
16

 
45

 
59

Total derivatives - net basis
$
25

 
$
3

 
$
(41
)
 
$
(25
)
 
$
(38
)

(1)
PacifiCorp's commodity derivatives are generally included in rates and as of September 30, 2019 and December 31, 2018, a regulatory asset of $81 million and $96 million, respectively, was recorded related to the net derivative liability of $82 million and $97 million, respectively.

The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Beginning balance
$
101

 
$
116

 
$
96

 
$
101

Changes in fair value
16

 
14

 
(12
)
 
48

Net losses reclassified to operating revenue
(11
)
 
(36
)
 
(27
)
 
(30
)
Net (losses) gains reclassified to cost of fuel and energy
(25
)
 
8

 
24

 
(17
)
Ending balance
$
81

 
$
102

 
$
81

 
$
102



75


Derivative Contract Volumes

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
 
Unit of
 
September 30,
 
December 31,
 
Measure
 
2019
 
2018
 
 
 
 
 
 
Electricity sales, net
Megawatt hours
 
(3
)
 
(6
)
Natural gas purchases
Decatherms
 
108

 
117


Credit Risk

PacifiCorp is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent PacifiCorp's counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, PacifiCorp analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, PacifiCorp enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtains third-party guarantees, letters of credit and cash deposits. If required, PacifiCorp exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts 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 PacifiCorp's creditworthiness. These rights can vary by contract and by counterparty. As of September 30, 2019, PacifiCorp's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt by Moody's Investor Service and Standard & Poor's Rating Services were investment grade.

The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $92 million and $113 million as of September 30, 2019 and December 31, 2018, respectively, for which PacifiCorp had posted collateral of $54 million and $61 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of September 30, 2019 and December 31, 2018, PacifiCorp would have been required to post $31 million and $35 million, respectively, of additional collateral. PacifiCorp's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.


76


(9)
Fair Value Measurements

The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

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

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

•
Level 3 — Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data.
 
The following table presents PacifiCorp's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1) 
 
Total
As of September 30, 2019
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
—

 
$
13

 
$
—

 
$
(7
)
 
$
6

Money market mutual funds(2)
 
322

 
—

 
—

 
—

 
322

Investment funds
 
25

 
—

 
—

 
—

 
25

 
 
$
347

 
$
13

 
$
—

 
$
(7
)
 
$
353

 
 
 
 
 
 
 
 
 
 
 
Liabilities - Commodity derivatives
 
$
—

 
$
(95
)
 
$
—

 
$
61

 
$
(34
)
 
 
 
 
 
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
—

 
$
51

 
$
—

 
$
(23
)
 
$
28

Money market mutual funds(2)
 
69

 
—

 
—

 
—

 
69

Investment funds
 
24

 
—

 
—

 
—

 
24

 
 
$
93

 
$
51

 
$
—

 
$
(23
)
 
$
121

 
 
 
 
 
 
 
 
 
 
 
Liabilities - Commodity derivatives
 
$
—

 
$
(148
)
 
$
—

 
$
82

 
$
(66
)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $54 million and $59 million as of September 30, 2019 and December 31, 2018, 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.


77


Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts. Refer to Note 8 for further discussion regarding PacifiCorp's risk management and hedging activities.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
 
 
As of September 30, 2019
 
As of December 31, 2018
 
 
Carrying
 
Fair
 
Carrying
 
Fair
 
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
 
Long-term debt
 
$
7,657

 
$
9,392

 
$
7,015

 
$
7,833


(10)
Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2019, PacifiCorp entered into firm construction commitments totaling $754 million for the remainder of 2019 through 2021 related to repowering and development of certain existing and new wind facilities in Wyoming, Montana and Washington.

Easements

During the nine-month period ended September 30, 2019, PacifiCorp entered into non-cancelable easements with minimum payments totaling $252 million through 2060 for land in Wyoming and Montana, on which some of its new wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the nine-month period ended September 30, 2019, PacifiCorp entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payments totaling $241 million through 2032.

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

78



Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA does not guarantee dam removal. Instead, it establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the Federal Energy Regulatory Commission ("FERC") license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four main-stem Klamath dams from PacifiCorp to the KRRC. Over the past two years, the KRRC has been supplementing the application with additional information about its financial, technical, and legal capacity to become the licensee. In July 2019, the KRRC provided the FERC with additional information about its financial capacity to become a licensee, including updated cost estimates, and its insurance, bonding and liability transfer package. The FERC is evaluating the KRRC's information and the proposed license transfer. The KRRC will continue to refine its insurance, bonding and liability transfer package, and PacifiCorp will review the KRRC's capacity to fulfill its indemnity obligation under the KHSA. If certain conditions in the amended KHSA are not satisfied (e.g., inadequate funding or inability of KRRC to satisfy its indemnification obligation) and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.

The United States Court of Appeals for the District of Columbia Circuit issued a decision in the Hoopa Valley Tribe v. FERC litigation, in January 2019, finding that the states of California and Oregon have waived their Clean Water Act, Section 401, water quality certification authority over the Klamath hydroelectric project relicensing. This decision has the potential to limit the ability of the States to impose water quality conditions on new and relicensed projects. Environmental interests, supported by California, Oregon and other states, asked the court to rehear the case, which was denied. Subsequently, environmental groups, supported by numerous states, filed a petition for certiorari before the United States Supreme Court, which remains pending.

Guarantees

PacifiCorp has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on PacifiCorp's consolidated financial results.


79


(11)
Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Customer Revenue:
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
Residential
$
478

 
$
478

 
$
1,316

 
$
1,284

Commercial
419

 
418

 
1,152

 
1,129

Industrial
306

 
305

 
887

 
862

Other retail
100

 
106

 
203

 
204

Total retail
1,303

 
1,307

 
3,558

 
3,479

Wholesale (1)
8

 
(10
)
 
47

 
21

Transmission
26

 
30

 
76

 
82

Other Customer Revenue
17

 
16

 
55

 
55

Total Customer Revenue
1,354

 
1,343

 
3,736

 
3,637

Other revenue
13

 
26

 
57

 
109

Total operating revenue
$
1,367

 
$
1,369

 
$
3,793

 
$
3,746


(1)
Includes net payments to counterparties for the financial settlement of certain non-derivative forward contracts for energy sales.


(12)
Related Party

Berkshire Hathaway includes BHE and its subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, PacifiCorp's provision for federal and state income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. For the nine-month periods ended September 30, 2019 and 2018, PacifiCorp made net cash payments for federal and state income tax to BHE totaling $128 million and $21 million, respectively.


80


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

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other usage factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2019 and 2018

Overview

Net income for the third quarter of 2019 was $278 million, an increase of $8 million, or 3%, compared to 2018. Net income increased primarily due to higher allowances for equity and borrowed funds of $18 million and lower operations and maintenance expense of $14 million, largely due to a decrease in expenses from lower wildfire reserves, partially offset by lower recognized production tax credits of $8 million from expiring production tax credits and higher interest expense of $5 million. Utility margin was relatively unchanged; however, retail customer volumes decreased 1.6% primarily due to lower usage and the unfavorable impact of weather, partially offset by an increase in the average number of customers. Energy generated decreased 10% for the third quarter of 2019 compared to 2018 primarily due to lower coal, natural gas and wind-powered generation, offset by higher hydroelectric generation. Wholesale electricity sales volumes decreased 47% and purchased electricity volumes increased 23%.

Net income for the first nine months of 2019 was $625 million, an increase of $23 million, or 4%, compared to 2018. Net income increased primarily due to higher allowances for equity and borrowed funds of $40 million, higher utility margin of $34 million and lower operations and maintenance expenses of $14 million, mainly due to a decrease in expenses from lower wildfire reserves, partially offset by higher depreciation and amortization expense of $19 million, excluding $65 million of depreciation expense (offset in income tax expense) for Oregon's share of certain retired wind equipment due to repowering, higher interest expense of $11 million, and lower recognized production tax credits of $11 million from expiring production tax credits. Utility margin increased primarily due to higher average retail rates, lower coal-fueled generation costs, higher retail customer volumes and higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms, partially offset by lower wholesale revenue, higher natural gas-fueled generation costs and higher purchased electricity costs. Retail customer volumes increased 0.3% primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower usage. Energy generated decreased 3% for the first nine months of 2019 compared to 2018 primarily due to lower coal, wind-powered, and hydroelectric generation, offset by higher natural gas generation. Wholesale electricity sales volumes decreased 37% and purchased electricity volumes decreased 8%.


81


Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
1,367

 
$
1,369

 
$
(2
)
 
—
 %
 
$
3,793

 
3,746

 
$
47

 
1%
Cost of fuel and energy
464

 
465

 
(1
)
 
—

 
1,313

 
1,300

 
13

 
1
Utility margin
903

 
904

 
(1
)
 
—

 
2,480

 
2,446

 
34

 
1
Operations and maintenance
252

 
266

 
(14
)
 
(5
)
 
763

 
777

 
(14
)
 
(2)
Depreciation and amortization
272

 
203

 
69

 
34

 
686

 
602

 
84

 
14
Property and other taxes
46

 
49

 
(3
)
 
(6
)
 
146

 
150

 
(4
)
 
(3)
Operating income
$
333

 
$
386

 
$
(53
)
 
(14
)
 
$
885

 
$
917

 
$
(32
)
 
(3)

82



A comparison of PacifiCorp's key operating results is as follows:
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
1,367

 
$
1,369

 
$
(2
)
 
—
 %
 
$
3,793

 
$
3,746

 
$
47

 
1
 %
Cost of fuel and energy
464

 
465

 
(1
)
 
—

 
1,313

 
1,300

 
13

 
1

Utility margin
$
903

 
$
904

 
$
(1
)
 
—

 
$
2,480

 
$
2,446

 
$
34

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales (GWh):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
4,298

 
4,347

 
(49
)
 
(1
)%
 
12,213

 
11,996

 
217

 
2
 %
Commercial
4,877

 
4,941

 
(64
)
 
(1
)
 
13,622

 
13,530

 
92

 
1

Industrial, irrigation and other
5,686

 
5,823

 
(137
)
 
(2
)
 
15,693

 
15,889

 
(196
)
 
(1
)
Total retail
14,861

 
15,111

 
(250
)
 
(2
)
 
41,528

 
41,415

 
113

 
—

Wholesale
962

 
1,802

 
(840
)
 
(47
)
 
3,778

 
5,963

 
(2,185
)
 
(37
)
Total sales
15,823

 
16,913

 
(1,090
)
 
(6
)
 
45,306

 
47,378

 
(2,072
)
 
(4
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
1,935

 
1,902

 
33

 
2
 %
 
1,928

 
1,896

 
32

 
2
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average revenue per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail
$
87.64

 
$
86.29

 
$
1.35

 
2
 %
 
$
85.65

 
$
83.92

 
$
1.73

 
2
 %
Wholesale
$
21.08

 
$
9.12

 
$
11.96

 
131
 %
 
$
26.58

 
$
21.62

 
$
4.96

 
23
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
271

 
208

 
63

 
30
 %
 
6,739

 
5,655

 
1,084

 
19
 %
Cooling degree days
1,462

 
1,532

 
(70
)
 
(5
)%
 
1,773

 
1,980

 
(207
)
 
(10
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWh)(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal
9,391

 
10,510

 
(1,119
)
 
(11
)%
 
25,059

 
26,231

 
(1,172
)
 
(4
)%
Natural gas
3,619

 
3,841

 
(222
)
 
(6
)
 
8,995

 
7,770

 
1,225

 
16

Hydroelectric(2)
480

 
467

 
13

 
3

 
2,211

 
2,640

 
(429
)
 
(16
)
Wind and other(2)
353

 
569

 
(216
)
 
(38
)
 
1,710

 
2,353

 
(643
)
 
(27
)
Total energy generated
13,843

 
15,387

 
(1,544
)
 
(10
)
 
37,975

 
38,994

 
(1,019
)
 
(3
)
Energy purchased
3,071

 
2,506

 
565

 
23

 
10,357

 
11,279

 
(922
)
 
(8
)
Total
16,914

 
17,893

 
(979
)
 
(5
)
 
48,332

 
50,273

 
(1,941
)
 
(4
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average cost of energy per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Energy generated(3)
$
19.17

 
$
19.45

 
$
(0.28
)
 
(1
)%
 
$
19.41

 
$
18.96

 
$
0.45

 
2
 %
Energy purchased
$
62.25

 
$
70.75

 
$
(8.50
)
 
(12
)%
 
$
49.88

 
$
44.43

 
$
5.45

 
12
 %

(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.

83



Utility margin decreased $1 million for the third quarter of 2019 compared to 2018 primarily due to:
•
$19 million of lower retail revenue from lower volumes. Retail volumes decreased 1.6% primarily due to lower residential and commercial usage in Utah, lower industrial usage in the eastern service territory, lower irrigation usage in Utah, Oregon and Washington, and the unfavorable impact of weather on residential and commercial customers in Oregon, partially offset by an increase in the average number of residential and commercial customers across the service territory and higher irrigation usage in Idaho;
•
$16 million of lower net deferrals of incurred net power costs in accordance with established adjustment mechanisms;
•
$14 million of higher purchased electricity costs, primarily due to higher volumes;
•
$7 million of lower wholesale revenue due to lower volumes; and
•
$6 million of lower wheeling revenues and higher wheeling costs.
The decreases above were partially offset by:
•
$34 million of lower coal and natural gas-fueled generation costs;
•
$17 million of higher retail revenue primarily due to lower net tax deferrals associated with the 2017 Tax Reform and higher average rates due to product mix; and
•
$11 million of higher wholesale revenue from higher average market prices.
Operations and maintenance decreased $14 million, or 5%, for the third quarter of 2019 compared to 2018 primarily due to a $10 million decrease in injuries and damages expense due to lower wildfire reserves and higher capitalized labor related to construction projects.

Depreciation and amortization increased $69 million, or 34%, for the third quarter of 2019 compared to 2018 primarily due to accelerated depreciation of $65 million (offset in income tax expense) for Oregon's share of certain retired wind equipment due to repowering and higher plant-in-service.

Property and other taxes decreased $3 million, or 6% for the third quarter of 2019 compared to 2018 due to lower property taxes, primarily in Utah.

Interest expense increased $5 million, or 5% for the third quarter of 2019 compared to 2018 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $18 million, or 129%, for the third quarter of 2019 compared to 2018 primarily due to higher qualified construction work-in-progress balances.

Income tax expense decreased $51 million, or 106%, for the third quarter of 2019 compared to 2018. The effective tax rate was (1)% for 2019 and 15% for 2018. The effective tax rate decreased primarily due to the amortization of $49 million of Oregon's allocated excess deferred income taxes pursuant to the Oregon RAC settlement, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering, partially offset by the impact of the 2017 Tax Reform settlements and expiring production tax credits.


84


Utility margin increased $34 million, or 1%, for the first nine months of 2019 compared to 2018 primarily due to:
•
$65 million of higher retail revenue from lower net tax deferrals associated with the 2017 Tax Reform and higher average rates due to product mix;
•
$17 million of higher retail revenue from higher volumes. Retail customer volumes increased 0.3% primarily due to an increase in the average number of residential and commercial customers across the service territory, the favorable impact of weather on residential customers across the service territory except Utah, higher commercial customer usage in Oregon, higher industrial customer usage in Washington and higher irrigation customer usage in Idaho, partially offset by lower residential customer usage in Utah, Oregon and Washington, lower industrial customer usage in Idaho, Oregon and Utah, lower irrigation customer usage in Utah and Oregon, lower commercial customer usage in Utah and Washington, and unfavorable impact of weather on residential and commercial customers in Utah and irrigation customers in Idaho;
•
$28 million of lower coal-fueled generation costs due to lower average volumes and prices; and
•
$10 million of higher net deferrals of incurred net power costs in accordance with established adjustment mechanisms.
The increases above were partially offset by:
•
$29 million of lower wholesale revenues from lower average volumes, partially offset by higher average market prices;
•
$27 million of higher natural gas-fueled generation costs from higher volumes;
•
$16 million of higher purchased electricity costs, primarily due to higher average market prices; and
•
$14 million of lower wheeling revenues and higher wheeling costs.
Operations and maintenance decreased $14 million, or 2% for the first nine months of 2019 compared to 2018 primarily due to a $9 million decrease in injuries and damages expense due to lower wildfire reserves, lower partner operated plant costs, a $5 million decrease in materials and supplies expense, primarily due to usage, and reduced labor and benefits expense primarily due to higher capitalized labor related to construction projects, partially offset by a $9 million increase in vegetation management costs.

Depreciation and amortization increased $84 million, or 14%, for the first nine months of 2019 compared to 2018 primarily due to accelerated depreciation of $65 million (offset in income tax expense) for Oregon's share of certain retired wind equipment due to repowering, an adjustment to the Oregon accelerated depreciation reserve based on the Oregon allocation factor in 2019 and higher plant-in-service.

Property and other taxes decreased $4 million, or 3% for the first nine months of 2019 compared to 2018 due to lower property taxes, primarily in Washington.

Interest expense increased $11 million, or 4% for the first nine months of 2019 compared to 2018 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $40 million, or 108%, for the first nine months of 2019 compared to 2018 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $7 million, or 70% for the first nine months of 2019 compared to 2018 primarily due to higher average cash and cash equivalents balances.

Income tax expense decreased $23 million, or 23%, for the first nine months of 2019 compared to 2018. The effective tax rate was 11% for 2019 and 14% for 2018. The effective tax rate decreased primarily due to the amortization of $49 million of Oregon's allocated excess deferred income taxes pursuant to the Oregon RAC settlement, whereby a portion of Oregon's allocated excess deferred income taxes was used to accelerate depreciation for Oregon's share of certain retired wind equipment due to repowering, partially offset by the impact of the 2017 Tax Reform settlements and expiring production tax credits.


85


Liquidity and Capital Resources
 
As of September 30, 2019, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents
 
$
331

 
 
 
Credit facilities
 
1,200

Less:
 
 
Tax-exempt bond support
 
(256
)
Net credit facilities
 
944

 
 
 
Total net liquidity
 
$
1,275

 
 
 
Credit facilities:
 
 
Maturity dates
 
2022

Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018 were $1,267 million and $1,480 million, respectively. The change was primarily due to increased payments for income taxes, lower collections from retail customers, and increased fuel payments

The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2019 and 2018 were $(1,440) million and $(711) million, respectively. The change is primarily due to an increase in capital expenditures of $736 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month period ended September 30, 2019 was $433 million. Sources of cash consisted of net proceeds from the issuance of long-term debt of $990 million. Uses of cash consisted substantially of $350 million for the repayment of long term debt, $175 million for common stock dividends paid to PPW Holdings LLC and $30 million for the repayment of short-term debt.

Net cash flows from financing activities for the nine-month period ended September 30, 2018 was $(475) million. Uses of cash consisted substantially of $586 million for the repayment of long-term debt, $400 million for common stock dividends paid to PPW Holdings LLC and $80 million for the repayment of short-term debt, offset by $593 million net proceeds from the issuance of long-term debt.
    
Short-term Debt

Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of September 30, 2019, PacifiCorp had no short-term debt outstanding. As of December 31, 2018, PacifiCorp had $30 million of short-term debt outstanding at a weighted average interest rate of 2.85%.

Long-term Debt
 
In March 2019, PacifiCorp issued $400 million of its 3.50% First Mortgage Bonds due June 2029 and $600 million of its 4.15% First Mortgage Bonds due February 2050. PacifiCorp used a portion of the net proceeds to repay the short-term debt that was partially incurred in January 2019 to repay all of PacifiCorp's $350 million of its 5.50% First Mortgage Bonds due January 2019. PacifiCorp intends to use the remaining net proceeds to fund capital expenditures and for general corporate purposes.


86


Credit Facilities

In March 2019, PacifiCorp completed a re-offering of variable rate tax-exempt bond obligations totaling $168 million, involving the cancellation, at PacifiCorp's request, of $170 million of letters of credit support by the issuing banks. As a result, PacifiCorp's credit facility support for outstanding variable rate tax-exempt bond obligations increased by $168 million.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue up to $1 billion additional first mortgage bonds through October 2021.

Future Uses of Cash

PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including regulatory approvals, PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
 
Nine-Month Periods
 
Annual
 
Ended September 30,
 
Forecast
 
2018
 
2019
 
2019
 
 
 
 
 
 
Transmission system investment
$
34

 
$
370

 
$
497

Wind investment
76

 
687

 
971

Operating and other
603

 
392

 
824

Total
$
713

 
$
1,449

 
$
2,292


PacifiCorp's historical and forecast capital expenditures include the following:

•
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. Planned spending for the Aeolus-Bridger/Anticline line totals $399 million in 2019.

•
Wind investment includes the following:

◦
Construction of wind-powered generating facilities at PacifiCorp totaling $245 million and $5 million for the nine-month periods ended September 30, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $104 million for 2019, which includes a new 240 MW wind-powered generating facility. The new wind-powered generating facilities are expected to be placed in-service in 2020. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal production tax credits available for ten years once the equipment is placed in-service.


87


◦
Repowering certain existing wind-powered generating facilities at PacifiCorp totaling $442 million and $70 million for the nine-month periods ended September 30, 2019 and 2018, respectively. PacifiCorp anticipates costs for these activities will total an additional $180 million for 2019. The repowering projects are expected to be placed in-service at various dates in 2019 and 2020. The energy production from such repowered facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for ten years following each facility's return to service.

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

Integrated Resource 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. As part of the 2019 IRP, in April 2019, PacifiCorp released an economic study of the coal fleet which informs how PacifiCorp will meet the long-term energy needs of its customers.

In October 2019, PacifiCorp filed its 2019 IRP with its state commissions. The 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 retirements and the need for incremental flexible capacity resources beginning in 2026. Delivery of new transmission infrastructure that will facilitate approximately 4,400 MW of new renewable energy resources, incremental to new renewable capacity that will come online by the end of 2020, and the addition of approximately 600 MW of new storage capacity is planned through 2023. The IRP outlines PacifiCorp's plan to procure these near-term generating facilities through a request for proposals process that will determine how many of the new resources identified in the IRP will be developed as owned assets or power purchase agreements. Over the next 20 years, the IRP calls for retiring approximately 4,500 MW of coal while adding approximately 9,000 MW of new renewable resources, incremental to new renewable capacity that will come online by the end of 2020, and approximately 2,800 MW of new storage capacity.

Requests for Proposals

PacifiCorp issues individual Request for Proposals ("RFP"), 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 renewable portfolio standard 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.

As required by applicable laws and regulations, PacifiCorp filed its draft 2017R RFP with the UPSC in June 2017 and with the OPUC in August 2017. The UPSC and the OPUC approved PacifiCorp's 2017R RFP in September 2017. The 2017R RFP sought up to approximately 1,270 MW of new wind resources that can interconnect to PacifiCorp's transmission system in Wyoming once a proposed high-voltage transmission line is constructed. The 2017R RFP also sought proposals for wind resources located outside of Wyoming capable of delivering all-in economic benefits for PacifiCorp's customers. The proposed high-voltage transmission line and new wind resources must be placed in service by December 31, 2020, to maximize potential federal production tax credit benefits for PacifiCorp's customers. PacifiCorp finalized its bid-selection process and established a final shortlist in February 2018. PacifiCorp plans to deliver 1,150 MW from three new wind facilities under various commercial structures including a power purchase agreement, a build-transfer agreement, and traditional self-build agreements. PacifiCorp has finalized a 200-MW power purchase agreement and a 200-MW build-transfer agreement for one of the three new wind facilities. PacifiCorp has also secured agreements for safe harbor wind turbine equipment, acquisition of development assets and balance-of-plant construction for the two remaining projects; one providing 250 MW and a second providing 500 MW. Agreements for acquisition of follow-on wind turbine equipment for the final two projects was completed in 2019.

Contractual Obligations

As of September 30, 2019, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2018, except as disclosed in Note 10.


88


Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local 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 PacifiCorp's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various 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 PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, pension and other postretirement benefits, income taxes and revenue recognition-unbilled revenue. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2018. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2018.


89


MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section


90


PART I
Item 1.
Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of September 30, 2019, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2018, and the related statements of operations, comprehensive income, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2018, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Des Moines, Iowa
November 1, 2019


91


MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
46

 
$
—

Trade receivables, net
352

 
367

Inventories
201

 
204

Other current assets
86

 
90

Total current assets
685

 
661

 
 
 
 
Property, plant and equipment, net
17,820

 
16,157

Regulatory assets
301

 
273

Investments and restricted investments
783

 
708

Other assets
105

 
121

 
 
 
 
Total assets
$
19,694

 
$
17,920


The accompanying notes are an integral part of these financial statements.

92


MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
611

 
$
575

Accrued interest
73

 
53

Accrued property, income and other taxes
273

 
300

Short-term debt
—

 
240

Current portion of long-term debt
—

 
500

Other current liabilities
148

 
122

Total current liabilities
1,105

 
1,790

 
 
 
 
Long-term debt
6,342

 
4,879

Regulatory liabilities
1,514

 
1,620

Deferred income taxes
2,546

 
2,322

Asset retirement obligations
789

 
552

Other long-term liabilities
321

 
311

Total liabilities
12,617

 
11,474

 
 
 
 
Commitments and contingencies (Note 10)

 

 
 
 
 
Shareholder's equity:
 
 
 
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding
—

 
—

Additional paid-in capital
561

 
561

Retained earnings
6,516

 
5,885

Total shareholder's equity
7,077

 
6,446

 
 
 
 
Total liabilities and shareholder's equity
$
19,694

 
$
17,920


The accompanying notes are an integral part of these financial statements.


93


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
712

 
$
727

 
$
1,792

 
$
1,785

Regulated natural gas and other
84

 
105

 
505

 
510

Total operating revenue
796

 
832

 
2,297

 
2,295

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Cost of fuel and energy
113

 
140

 
318

 
366

Cost of natural gas purchased for resale and other
45

 
50

 
302

 
296

Operations and maintenance
189

 
201

 
600

 
598

Depreciation and amortization
184

 
133

 
540

 
499

Property and other taxes
31

 
30

 
94

 
92

Total operating expenses
562

 
554

 
1,854

 
1,851

 
 
 
 
 
 
 
 
Operating income
234

 
278

 
443

 
444

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(68
)
 
(56
)
 
(207
)
 
(170
)
Allowance for borrowed funds
7

 
6

 
20

 
14

Allowance for equity funds
27

 
16

 
59

 
39

Other, net
4

 
13

 
34

 
34

Total other income (expense)
(30
)
 
(21
)
 
(94
)
 
(83
)
 
 
 
 
 
 
 
 
Income before income tax benefit
204

 
257

 
349

 
361

Income tax benefit
(78
)
 
(226
)
 
(282
)
 
(334
)
 
 
 
 
 
 
 
 
Net income
$
282

 
$
483

 
$
631

 
$
695


The accompanying notes are an integral part of these financial statements.


94


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions)

 
Common Stock
 
Additional Paid-in Capital
 
Retained
Earnings
 
Total Shareholder's
Equity
 
 
 
 
 
 
 
 
Balance, June 30, 2018
$
—

 
$
561

 
$
5,416

 
$
5,977

Net income
—

 
—

 
483

 
483

Other equity transactions
—

 
—

 
(1
)
 
(1
)
Balance, September 30, 2018
$
—

 
$
561

 
$
5,898

 
$
6,459

 
 
 
 
 
 
 
 
Balance, December 31, 2017
$
—

 
$
561

 
$
5,203

 
$
5,764

Net income
—

 
—

 
695

 
695

Balance, September 30, 2018
$
—

 
$
561

 
$
5,898

 
$
6,459

 
 
 
 
 
 
 
 
Balance, June 30, 2019
$
—

 
$
561

 
$
6,234

 
$
6,795

Net income
—

 
—

 
282

 
282

Balance, September 30, 2019
$
—

 
$
561

 
$
6,516

 
$
7,077

 
 
 
 
 
 
 
 
Balance, December 31, 2018
$
—

 
$
561

 
$
5,885

 
$
6,446

Net income
—

 
—

 
631

 
631

Balance, September 30, 2019
$
—

 
$
561

 
$
6,516

 
$
7,077


The accompanying notes are an integral part of these financial statements.


95


MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
631

 
$
695

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
540

 
499

Amortization of utility plant to other operating expenses
25

 
26

Allowance for equity funds
(59
)
 
(39
)
Deferred income taxes and amortization of investment tax credits
31

 
(35
)
Other, net
16

 
13

Changes in other operating assets and liabilities:
 
 
 
Trade receivables and other assets
(1
)
 
(46
)
Inventories
3

 
40

Contributions to pension and other postretirement benefit plans, net
(9
)
 
(10
)
Accrued property, income and other taxes, net
(28
)
 
(77
)
Accounts payable and other liabilities
62

 
(38
)
Net cash flows from operating activities
1,211

 
1,028

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(1,909
)
 
(1,466
)
Purchases of marketable securities
(139
)
 
(224
)
Proceeds from sales of marketable securities
126

 
198

Other, net
19

 
29

Net cash flows from investing activities
(1,903
)
 
(1,463
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from long-term debt
1,460

 
687

Repayments of long-term debt
(500
)
 
(350
)
Net repayments of short-term debt
(240
)
 
—

Other, net
—

 
(1
)
Net cash flows from financing activities
720

 
336

 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
28

 
(99
)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
56

 
282

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
84

 
$
183


The accompanying notes are an integral part of these financial statements.


96


MIDAMERICAN ENERGY COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

(1)
General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's nonregulated subsidiaries include Midwest Capital Group, Inc. and MEC Construction Services Co. MHC is the direct, wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2019, and for the three- and nine-month periods ended September 30, 2019 and 2018. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2018, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2019.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
 
As of
 
September 30,
 
December 31
 
2019
 
2018
 
 
 
 
Cash and cash equivalents
$
46

 
$
—

Restricted cash and cash equivalents in other current assets
38

 
56

Total cash and cash equivalents and restricted cash and cash equivalents
$
84

 
$
56



97


(3)
Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
 
 
September 30,
 
December 31,
 
Depreciable Life
 
2019
 
2018
Utility plant in service, net:
 
 
 
 
 
Generation
20-70 years
 
$
14,492

 
$
13,727

Transmission
52-75 years
 
2,012

 
1,934

Electric distribution
20-75 years
 
3,842

 
3,672

Natural gas distribution
29-75 years
 
1,776

 
1,724

Utility plant in service
 
 
22,122

 
21,057

Accumulated depreciation and amortization
 
 
(6,347
)
 
(5,941
)
Utility plant in service, net
 
 
15,775

 
15,116

Nonregulated property, net:
 
 
 
 
 
Nonregulated property gross
20-50 years
 
7

 
7

Accumulated depreciation and amortization
 
 
(1
)
 
(1
)
Nonregulated property, net
 
 
6

 
6

 
 
 
15,781

 
15,122

Construction work-in-progress
 
 
2,039

 
1,035

Property, plant and equipment, net
 
 
$
17,820

 
$
16,157


(4)
Leases

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which created FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. MidAmerican Energy adopted this guidance for all applicable contracts in effect as of January 1, 2019 under a modified retrospective method, and the adoption did not have a cumulative effect impact at the date of initial adoption nor a material impact on MidAmerican Energy's Financial Statements and disclosures included within Notes to Financial Statements.

(5)
Recent Financing Transactions

Long-Term Debt

In October 2019, MidAmerican Energy issued $600 million of its 3.15% First Mortgage Bonds due April 2050 and $250 million of its 3.65% First Mortgage Bonds due April 2029, which are part of the same series as the 3.65% First Mortgage Bonds issued in January 2019. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from December 20, 2018 to July 15, 2019, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project, MidAmerican Energy's 591-megawatt (nameplate capacity) Wind XII project and the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds.

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.


98


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. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from November 1, 2017 to December 14, 2018, with respect to investments in MidAmerican Energy's 2,000-megawatt (nameplate capacity) Wind XI project, MidAmerican Energy's 591-megawatt (nameplate capacity) Wind XII project and the repowering of certain of MidAmerican Energy's existing wind facilities, which were previously financed with MidAmerican Energy's general funds.

Credit Facilities

In August 2019, MidAmerican Energy entered into a $400 million unsecured credit facility, which expires August 2020 and has a variable rate based on the Eurodollar rate or a base rate, at MidAmerican Energy's option, plus a spread. The facility requires that MidAmerican Energy's ratio of consolidated debt, including current maturities, to total capitalization not exceed 0.65 to 1.0 as of the last day of any quarter.

In May 2019, MidAmerican Energy extended, with lender consent, the expiration date for its existing $900 million unsecured credit facility to June 2022 by exercising the remaining one-year extension option.

(6)
Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax benefit is as follows:
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
21
 %
 
21
 %
Income tax credits
(35
)
 
(95
)
 
(75
)
 
(97
)
State income tax, net of federal income tax benefit
(18
)
 
(10
)
 
(19
)
 
(9
)
Effects of ratemaking
(7
)
 
(4
)
 
(7
)
 
(7
)
Other, net
1

 
—

 
(1
)
 
(1
)
Effective income tax rate
(38
)%
 
(88
)%
 
(81
)%
 
(93
)%

Income tax credits relate primarily to production tax credits from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the three-month periods ended September 30, 2019 and 2018 were $69 million and $241 million, respectively, with $185 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019. Production tax credits recognized in income for the nine-month periods ended September 30, 2019 and 2018 were $259 million and $349 million, respectively, with $129 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Energy received net cash payments for income tax from BHE totaling $309 million and $232 million for the nine-month periods ended September 30, 2019 and 2018, respectively.


99


(7)
Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

Net periodic benefit credit for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Pension:
 
 
 
 
 
 
 
Service cost
$
2

 
$
2

 
$
5

 
$
6

Interest cost
7

 
7

 
22

 
21

Expected return on plan assets
(10
)
 
(11
)
 
(31
)
 
(33
)
Net amortization
—

 
1

 
—

 
2

Net periodic benefit credit
$
(1
)
 
$
(1
)
 
$
(4
)
 
$
(4
)
 
 
 
 
 
 
 
 
Other postretirement:
 
 
 
 
 
 
 
Service cost
$
1

 
$
1

 
$
4

 
$
4

Interest cost
2

 
2

 
7

 
6

Expected return on plan assets
(3
)
 
(3
)
 
(9
)
 
(10
)
Net amortization
(1
)
 
(1
)
 
(3
)
 
(3
)
Net periodic benefit credit
$
(1
)
 
$
(1
)
 
$
(1
)
 
$
(3
)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans are expected to be $7 million and $1 million, respectively, during 2019. As of September 30, 2019, $5 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(8)    Asset Retirement Obligations

In January 2018, MidAmerican Energy completed groundwater testing at its coal combustion residuals ("CCR") surface impoundments. Based on this information, MidAmerican Energy discontinued sending CCR to surface impoundments effective April 2018 and initiated analysis of additional actions to be taken. As a result of that analysis, MidAmerican Energy will remove all CCR material located below the water table and cap the material in such facilities, which is a more extensive closure activity than previously assumed. In the first quarter of 2019, MidAmerican Energy increased the asset retirement obligations for its fossil-fueled generating facilities by $237 million related to the cost of this closure activity. Closure activity on the six existing surface impoundments is estimated to extend through 2023. The following table reconciles the beginning and ending balances of MidAmerican Energy's ARO liabilities for the nine-month period ended September 30, 2019 (in millions):

Beginning balance
 
$
562

Change in estimated costs
 
237

Additions
 
5

Retirements
 
(2
)
Accretion
 
22

Ending balance
 
$
824



100


(9)
Fair Value Measurements

The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

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

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

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

The following table presents MidAmerican Energy's financial assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of September 30, 2019:
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
—

 
$
4

 
$
—

 
$
(1
)
 
$
3

Money market mutual funds(2)
 
3

 
—

 
—

 
—

 
3

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
189

 
—

 
—

 
—

 
189

International government obligations
 
—

 
5

 
—

 
—

 
5

Corporate obligations
 
—

 
57

 
—

 
—

 
57

Municipal obligations
 
—

 
1

 
—

 
—

 
1

Agency, asset and mortgage-backed obligations
 
—

 
1

 
—

 
—

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
309

 
—

 
—

 
—

 
309

International companies
 
8

 
—

 
—

 
—

 
8

Investment funds
 
19

 
—

 
—

 
—

 
19

 
 
$
528

 
$
68

 
$
—

 
$
(1
)
 
$
595

 
 
 
 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
 
$
—

 
$
(8
)
 
$
—

 
$
2

 
$
(6
)


101


 
 
Input Levels for Fair Value Measurements
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other(1)
 
Total
As of December 31, 2018:
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
Commodity derivatives
 
$
—

 
$
4

 
$
2

 
$
(3
)
 
$
3

Money market mutual funds(2)
 
2

 
—

 
—

 
—

 
2

Debt securities:
 
 
 
 
 
 
 
 
 
 
United States government obligations
 
187

 
—

 
—

 
—

 
187

International government obligations
 
—

 
4

 
—

 
—

 
4

Corporate obligations
 
—

 
46

 
—

 
—

 
46

Municipal obligations
 
—

 
2

 
—

 
—

 
2

Agency, asset and mortgage-backed obligations
 
—

 
1

 
—

 
—

 
1

Equity securities:
 
 
 
 
 
 
 
 
 
 
United States companies
 
256

 
—

 
—

 
—

 
256

International companies
 
6

 
—

 
—

 
—

 
6

Investment funds
 
10

 
—

 
—

 
—

 
10

 
 
$
461

 
$
57

 
$
2

 
$
(3
)
 
$
517

 
 
 
 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
 
$
—

 
$
(4
)
 
$
(2
)
 
$
3

 
$
(3
)

(1)
Represents netting under master netting arrangements and a net cash collateral receivable of $1 million and $- million as of September 30, 2019 and December 31, 2018, respectively.
(2)
Amounts are included in cash and cash equivalents and investments and restricted investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities primarily accounted for as available-for-sale securities. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
 
As of September 30, 2019
 
As of December 31, 2018
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
 
 
 
 
 
 
Long-term debt
$
6,342

 
$
7,519

 
$
5,379

 
$
5,644



102


(10)
Commitments and Contingencies

Construction Commitments

During the nine-month period ended September 30, 2019, MidAmerican Energy entered into firm construction commitments totaling $337 million for the remainder of 2019 through 2020 related to the construction of wind-powered generating facilities in Iowa.

Easements

During the nine-month period ended September 30, 2019, MidAmerican Energy entered into non-cancelable easements with minimum payments totaling $341 million through 2059 for land in Iowa on which some of its wind-powered generating facilities will be located.

Maintenance and Service Contracts

During the nine-month period ended September 30, 2019, MidAmerican Energy entered into non-cancelable maintenance and service contracts related to wind-powered generating facilities with minimum payment commitments totaling $377 million through 2029.

Legal Matters

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using FERC-approved formula rates subject to true-up for actual cost of service. Prior to September 2016, the rates in effect were based on a 12.38% return on equity ("ROE"). In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the 12.38% ROE no longer be found just and reasonable and sought to reduce the base ROE to 9.15% and 8.67%, respectively. MidAmerican Energy is authorized by the FERC to include a 0.50% adder beyond the base ROE effective January 2015. In September 2016, the FERC issued an order for the first complaint, which reduces the base ROE to 10.32% and required refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. It is uncertain when the FERC will rule on the second complaint, covering the period from February 2015 through May 2016. MidAmerican Energy believes it is probable that the FERC will order a base ROE lower than 12.38% in the second complaint and, as of September 30, 2019, has accrued a $10 million liability for refunds under the second complaint of amounts collected under the higher ROE from March 2015 through May 2016.


103


(11)
Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business and customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in Note 12, (in millions):
 
For the Three-Month Periods Ended September 30,
 
2019
 
2018
 
Electric
 
Natural Gas
 
Other
 
Total
 
Electric
 
Natural Gas
 
Other
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
228

 
$
41

 
$
—

 
$
269

 
$
233

 
$
54

 
$
—

 
$
287

Commercial
101

 
10

 
—

 
111

 
100

 
17

 
—

 
117

Industrial
274

 
3

 
—

 
277

 
268

 
3

 
—

 
271

Natural gas transportation services
—

 
7

 
—

 
7

 
—

 
8

 
—

 
8

Other retail(1)
48

 
—

 
—

 
48

 
46

 
1

 
—

 
47

Total retail
651

 
61

 
—

 
712

 
647

 
83

 
—

 
730

Wholesale
41

 
15

 
—

 
56

 
62

 
20

 
—

 
82

Multi-value transmission projects
17

 
—

 
—

 
17

 
14

 
—

 
—

 
14

Other Customer Revenue
—

 
—

 
8

 
8

 
—

 
—

 
2

 
2

Total Customer Revenue
709

 
76

 
8

 
793

 
723

 
103

 
2

 
828

Other revenue
3

 
—

 
—

 
3

 
4

 
—

 
—

 
4

Total operating revenue
$
712

 
$
76

 
$
8

 
$
796

 
$
727

 
$
103

 
$
2

 
$
832

 
For the Nine-Month Periods Ended September 30,
 
2019
 
2018
 
Electric
 
Natural Gas
 
Other
 
Total
 
Electric
 
Natural Gas
 
Other
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
547

 
$
282

 
$
—

 
$
829

 
$
567

 
$
287

 
$
—

 
$
854

Commercial
255

 
95

 
—

 
350

 
251

 
100

 
—

 
351

Industrial
641

 
12

 
—

 
653

 
608

 
13

 
—

 
621

Natural gas transportation services
—

 
27

 
—

 
27

 
—

 
27

 
—

 
27

Other retail(1)
118

 
—

 
—

 
118

 
113

 
1

 
—

 
114

Total retail
1,561

 
416

 
—

 
1,977

 
1,539

 
428

 
—

 
1,967

Wholesale
168

 
64

 
—

 
232

 
187

 
75

 
—

 
262

Multi-value transmission projects
47

 
—

 
—

 
47

 
43

 
—

 
—

 
43

Other Customer Revenue
—

 
—

 
23

 
23

 
—

 
—

 
5

 
5

Total Customer Revenue
1,776

 
480

 
23

 
2,279

 
1,769

 
503

 
5

 
2,277

Other revenue
16

 
2

 
—

 
18

 
16

 
2

 
—

 
18

Total operating revenue
$
1,792

 
$
482

 
$
23

 
$
2,297

 
$
1,785

 
$
505

 
$
5

 
$
2,295


(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.

104


(12)
Segment Information

MidAmerican Energy has identified two reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.

The following tables provide information on a reportable segment basis (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
712

 
$
727

 
$
1,792

 
$
1,785

Regulated natural gas
76

 
103

 
482

 
505

Other
8

 
2

 
23

 
5

Total operating revenue
$
796

 
$
832

 
$
2,297

 
$
2,295

 
 
 
 
 
 
 
 
Operating income:
 
 
 
 
 
 
 
Regulated electric
$
243

 
$
278

 
$
396

 
$
392

Regulated natural gas
(8
)
 
1

 
45

 
52

Other
(1
)
 
(1
)
 
2

 
—

Total operating income
234

 
278

 
443

 
444

Interest expense
(68
)
 
(56
)
 
(207
)
 
(170
)
Allowance for borrowed funds
7

 
6

 
20

 
14

Allowance for equity funds
27

 
16

 
59

 
39

Other, net
4

 
13

 
34

 
34

Income before income tax benefit
$
204

 
$
257

 
$
349

 
$
361


 
As of
 
September 30,
2019
 
December 31,
2018
Assets:
 
 
 
Regulated electric
$
18,341

 
$
16,511

Regulated natural gas
1,343

 
1,406

Other
10

 
3

Total assets
$
19,694

 
$
17,920




105




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Managers and Member of
MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of September 30, 2019, the related consolidated statements of operations and changes in member's equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2018, and the related consolidated statements of operations, comprehensive income, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Des Moines, Iowa
November 1, 2019


106


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
47

 
$
1

Trade receivables, net
352

 
365

Inventories
201

 
204

Other current assets
87

 
89

Total current assets
687

 
659

 
 
 
 
Property, plant and equipment, net
17,831

 
16,169

Goodwill
1,270

 
1,270

Regulatory assets
301

 
273

Investments and restricted investments
785

 
710

Other assets
105

 
121

 
 
 
 
Total assets
$
20,979

 
$
19,202


The accompanying notes are an integral part of these consolidated financial statements.

107


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
611

 
$
575

Accrued interest
74

 
58

Accrued property, income and other taxes
273

 
300

Note payable to affiliate
173

 
156

Short-term debt
—

 
240

Current portion of long-term debt
—

 
500

Other current liabilities
148

 
122

Total current liabilities
1,279

 
1,951

 
 
 
 
Long-term debt
6,582

 
5,119

Regulatory liabilities
1,514

 
1,620

Deferred income taxes
2,543

 
2,319

Asset retirement obligations
789

 
552

Other long-term liabilities
321

 
312

Total liabilities
13,028

 
11,873

 
 
 
 
Commitments and contingencies (Note 10)

 

 
 
 
 
Member's equity:
 
 
 
Paid-in capital
1,679

 
1,679

Retained earnings
6,272

 
5,650

Total member's equity
7,951

 
7,329

 
 
 
 
Total liabilities and member's equity
$
20,979

 
$
19,202


The accompanying notes are an integral part of these consolidated financial statements.


108


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
712

 
$
727

 
$
1,792

 
$
1,785

Regulated natural gas and other
85

 
105

 
507

 
512

Total operating revenue
797

 
832

 
2,299

 
2,297

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Cost of fuel and energy
113

 
140

 
318

 
366

Cost of natural gas purchased for resale and other
45

 
50

 
301

 
297

Operations and maintenance
190

 
201

 
602

 
599

Depreciation and amortization
184

 
133

 
540

 
499

Property and other taxes
31

 
30

 
94

 
92

Total operating expenses
563

 
554

 
1,855

 
1,853

 
 
 
 
 
 
 
 
Operating income
234

 
278

 
444

 
444

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(74
)
 
(61
)
 
(223
)
 
(185
)
Allowance for borrowed funds
7

 
6

 
20

 
14

Allowance for equity funds
27

 
16

 
59

 
39

Other, net
5

 
12

 
36

 
35

Total other income (expense)
(35
)
 
(27
)
 
(108
)
 
(97
)
 
 
 
 
 
 
 
 
Income before income tax benefit
199

 
251

 
336

 
347

Income tax benefit
(80
)
 
(228
)
 
(286
)
 
(338
)
 
 
 
 
 
 
 
 
Net income
$
279

 
$
479

 
$
622

 
$
685


The accompanying notes are an integral part of these consolidated financial statements.


109


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)
(Amounts in millions)

 
Paid-in
Capital
 
Retained
Earnings
 
Total Member's
Equity
 
 
 
 
 
 
Balance, June 30, 2018
$
1,679

 
$
5,187

 
$
6,866

Net income
—

 
479

 
479

Balance, September 30, 2018
$
1,679

 
$
5,666

 
$
7,345

 
 
 
 
 
 
Balance, December 31, 2017
$
1,679

 
$
4,981

 
$
6,660

Net income
—

 
685

 
685

Balance, September 30, 2018
$
1,679

 
$
5,666

 
$
7,345

 
 
 
 
 
 
Balance, June 30, 2019
$
1,679

 
$
5,993

 
$
7,672

Net income
—

 
279

 
279

Balance, September 30, 2019
$
1,679

 
$
6,272

 
$
7,951

 
 
 
 
 
 
Balance, December 31, 2018
$
1,679

 
$
5,650

 
$
7,329

Net income
—

 
622

 
622

Balance, September 30, 2019
$
1,679

 
$
6,272

 
$
7,951


The accompanying notes are an integral part of these consolidated financial statements.


110


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
622

 
$
685

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
540

 
499

Amortization of utility plant to other operating expenses
25

 
26

Allowance for equity funds
(59
)
 
(39
)
Deferred income taxes and amortization of investment tax credits
30

 
(35
)
Other, net
18

 
17

Changes in other operating assets and liabilities:
 
 
 
Trade receivables and other assets
(6
)
 
(42
)
Inventories
3

 
40

Contributions to pension and other postretirement benefit plans, net
(9
)
 
(10
)
Accrued property, income and other taxes, net
(28
)
 
(65
)
Accounts payable and other liabilities
58

 
(41
)
Net cash flows from operating activities
1,194

 
1,035

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(1,909
)
 
(1,466
)
Purchases of marketable securities
(139
)
 
(224
)
Proceeds from sales of marketable securities
126

 
198

Other, net
19

 
29

Net cash flows from investing activities
(1,903
)
 
(1,463
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from long-term debt
1,460

 
687

Repayments of long-term debt
(500
)
 
(350
)
Net change in note payable to affiliate
17

 
(6
)
Net repayments of short-term debt
(240
)
 
—

Other, net
—

 
(2
)
Net cash flows from financing activities
737

 
329

 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
28

 
(99
)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
57

 
282

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
85

 
$
183


The accompanying notes are an integral part of these consolidated financial statements.


111


MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)
General

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct, wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries and related corporate services. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations. Direct, wholly owned nonregulated subsidiaries of MHC are Midwest Capital Group, Inc. and MEC Construction Services Co.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2019, and for the three- and nine-month periods ended September 30, 2019 and 2018. The Consolidated Statements of Comprehensive Income have been omitted as net income materially equals comprehensive income for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2018, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the nine-month period ended September 30, 2019.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of
 
September 30
 
December 31
 
2019
 
2018
 
 
 
 
Cash and cash equivalents
$
47

 
$
1

Restricted cash and cash equivalents in other current assets
38

 
56

Total cash and cash equivalents and restricted cash and cash equivalents
$
85

 
$
57


112



(3)
Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements. In addition to MidAmerican Energy's property, plant and equipment, net, MidAmerican Funding had as of September 30, 2019 and December 31, 2018, nonregulated property gross of $24 million and related accumulated depreciation and amortization of $13 million and $12 million, respectively, which consisted primarily of a corporate aircraft owned by MHC.

(4)
Leases

Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.

(5)
Recent Financing Transactions

Refer to Note 5 of MidAmerican Energy's Notes to Financial Statements.

(6)
Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax benefit is as follows:
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
 %
 
21
 %
 
21
 %
 
21
 %
Income tax credits
(36
)
 
(97
)
 
(78
)
 
(101
)
State income tax, net of federal income tax benefit
(18
)
 
(10
)
 
(20
)
 
(10
)
Effects of ratemaking
(7
)
 
(5
)
 
(7
)
 
(7
)
Other, net
—

 
—

 
(1
)
 
—

Effective income tax rate
(40
)%
 
(91
)%
 
(85
)%
 
(97
)%

Income tax credits relate primarily to production tax credits from MidAmerican Energy's wind-powered generating facilities. Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service.

Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the three-month periods ended September 30, 2019 and 2018 were $69 million and $241 million, respectively, with $185 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019. Production tax credits recognized in income for the nine-month periods ended September 30, 2019 and 2018 were $259 million and $349 million, respectively, with $129 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019.

Berkshire Hathaway includes BHE and subsidiaries in its United States federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Funding received net cash payments for income tax from BHE totaling $313 million and $248 million for the nine-month period ended September 30, 2019 and 2018, respectively.


113


(7)
Employee Benefit Plans

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements.

(8)    Asset Retirement Obligations

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.

(9)
Fair Value Measurements

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
 
As of September 30, 2019
 
As of December 31, 2018
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
 
 
 
 
 
 
Long-term debt
$
6,582

 
$
7,840

 
$
5,619

 
$
5,941


(10)
Commitments and Contingencies

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Refer to Note 10 of MidAmerican Energy's Notes to Financial Statements.

(11)
Revenue from Contracts with Customers

Refer to Note 11 of MidAmerican Energy's Notes to Financial Statements. Additionally, MidAmerican Funding had other Accounting Standards Codification Topic 606 revenue of $1 million and $- million for the three-month periods ended September 30, 2019 and 2018, respectively, and $2 million for the nine-month periods ended September 30, 2019 and 2018, respectively.

(12)
Segment Information

MidAmerican Funding has identified two reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.


114


The following tables provide information on a reportable segment basis (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
712

 
$
727

 
$
1,792

 
$
1,785

Regulated natural gas
76

 
103

 
482

 
505

Other
9

 
2

 
25

 
7

Total operating revenue
$
797

 
$
832

 
$
2,299

 
$
2,297

 
 
 
 
 
 
 
 
Operating income:
 
 
 
 
 
 
 
Regulated electric
$
243

 
$
278

 
$
396

 
$
392

Regulated natural gas
(8
)
 
1

 
45

 
52

Other
(1
)
 
(1
)
 
3

 
—

Total operating income
234

 
278

 
444

 
444

Interest expense
(74
)
 
(61
)
 
(223
)
 
(185
)
Allowance for borrowed funds
7

 
6

 
20

 
14

Allowance for equity funds
27

 
16

 
59

 
39

Other, net
5

 
12

 
36

 
35

Income before income tax benefit
$
199

 
$
251

 
$
336

 
$
347


 
As of
 
September 30,
2019
 
December 31,
2018
Assets(1):
 
 
 
Regulated electric
$
19,532

 
$
17,702

Regulated natural gas
1,422

 
1,485

Other
25

 
15

Total assets
$
20,979

 
$
19,202

(1)
Assets by reportable segment reflect the assignment of goodwill to applicable reporting units.


115


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

MidAmerican Funding is an Iowa limited liability company whose sole member is BHE. MidAmerican Funding owns all of the outstanding common stock of MHC Inc., which owns all of the common stock of MidAmerican Energy, Midwest Capital Group, Inc. and MEC Construction Services Co. MidAmerican Energy is a public utility company headquartered in Des Moines, Iowa. MHC Inc., MidAmerican Funding and BHE are also headquartered in Des Moines, Iowa.

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 as presented in this joint filing. 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 and other usage factors. This discussion should be read in conjunction with the historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Energy's and MidAmerican Funding's actual results in the future could differ significantly from the historical results.

Results of Operations for the Third Quarter and First Nine Months of 2019 and 2018

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the third quarter of 2019 was $282 million, a decrease of $201 million, or 42%, compared to 2018 primarily due to lower income tax benefit of $148 million primarily due to a $172 million decrease in recognized production tax credits, partially offset by the effects of ratemaking, higher depreciation and amortization expense of $51 million due to $33 million of higher Iowa revenue sharing accruals and greater assets placed in-service and higher interest expense of $12 million, partially offset by higher electric utility margin of $12 million and higher allowances for equity and borrowed funds of $12 million. The decrease in production tax credits recognized was due to a change in the method of interim period recognition of $185 million, partially offset by higher actual generation. Electric utility margin increased due to higher retail customer volumes, higher recoveries through bill riders, net of energy costs, and higher wholesale margins due to lower energy costs, partially offset by lower average retail rates. Electric retail customer volumes increased 1.7% from higher industrial volumes of 2.9% and the favorable impact of weather, partially offset by a decrease from other usage factors.

MidAmerican Energy's net income for the first nine months of 2019 was $631 million, a decrease of $64 million, or 9%, compared to 2018 due to lower income tax benefit of $52 million primarily due to a $90 million decrease in recognized production tax credits, partially offset by the effects of ratemaking, higher depreciation and amortization expense of $41 million due to greater assets placed in-service, partially offset by $15 million of lower Iowa revenue sharing accruals, and higher interest expense of $37 million, partially offset by higher electric utility margin of $55 million and higher allowances for equity and borrowed funds of $26 million. The decrease in production tax credits recognized was due to a change in the method of interim period recognition of $129 million, partially offset by higher actual generation. Electric utility margin increased due to higher recoveries through bill riders, net of energy costs, higher wholesale margins due to lower energy costs and higher sales volumes and higher retail customer volumes, partially offset by lower average retail rates. Electric retail customer volumes increased 0.9% as an increase in industrial volumes of 4.0% was largely offset by lower residential and commercial volumes from the unfavorable impact of weather and other usage factors.

MidAmerican Funding -

MidAmerican Funding's net income for the third quarter of 2019 was $279 million, a decrease of $200 million, or 42%, compared to 2018. MidAmerican Funding's net income for the first nine months of 2019 was $622 million, a decrease of $63 million, or 9%, compared to 2018. The decreases were primarily due to the changes in MidAmerican Energy's earnings discussed above.


116


Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and regulated cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in those expenses result in comparable changes to revenue from the related recovery mechanisms. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Electric utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated electric operating revenue
 
$
712

 
$
727

 
$
(15
)
(2
)%
 
$
1,792

 
$
1,785

 
$
7

—
 %
Cost of fuel and energy
 
113

 
140

 
(27
)
(19
)
 
318

 
366

 
(48
)
(13
)
Electric utility margin
 
599

 
587

 
12

2

 
1,474

 
1,419

 
55

4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulated natural gas operating revenue
 
76

 
103

 
(27
)
(26
)%
 
482

 
505

 
(23
)
(5
)
Cost of natural gas purchased for resale
 
39

 
50

 
(11
)
(22
)
 
287

 
296

 
(9
)
(3
)
Natural gas utility margin
 
37

 
53

 
(16
)
(30
)
 
195

 
209

 
(14
)
(7
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility margin
 
636

 
640

 
(4
)
(1
)%
 
1,669

 
1,628

 
41

3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other operating revenue
 
8

 
2

 
6

*
 
23

 
5

 
18

*
Other cost of sales
 
6

 
—

 
6

*
 
15

 
—

 
15

*
Operations and maintenance
 
189

 
201

 
(12
)
(6
)%
 
600

 
598

 
2

—

Depreciation and amortization
 
184

 
133

 
51

38

 
540

 
499

 
41

8

Property and other taxes
 
31

 
30

 
1

3

 
94

 
92

 
2

2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating income
 
$
234

 
$
278

 
$
(44
)
(16
)%
 
$
443

 
$
444

 
$
(1
)
—
 %

*    Not meaningful.


117


Regulated Electric Utility Margin

A comparison of key operating results related to regulated electric utility margin is as follows:
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Electric utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
712

 
$
727

 
$
(15
)
 
(2
)%
 
$
1,792

 
$
1,785

 
$
7

 
—
 %
Cost of fuel and energy
113

 
140

 
(27
)
 
(19
)
 
318

 
366

 
(48
)
 
(13
)
Electric utility margin
$
599

 
$
587

 
$
12

 
2

 
$
1,474

 
$
1,419

 
$
55

 
4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electricity Sales (GWh):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
1,950

 
1,952

 
(2
)
 
—
 %
 
5,105

 
5,307

 
(202
)
 
(4
)%
Commercial
1,037

 
1,025

 
12

 
1

 
2,930

 
2,944

 
(14
)
 
—

Industrial
3,652

 
3,550

 
102

 
3

 
10,567

 
10,158

 
409

 
4

Other
420

 
415

 
5

 
1

 
1,200

 
1,218

 
(18
)
 
(1
)
Total retail
7,059

 
6,942

 
117

 
2

 
19,802

 
19,627

 
175

 
1

Wholesale
1,708

 
2,160

 
(452
)
 
(21
)
 
7,312

 
7,179

 
133

 
2

Total sales
8,767

 
9,102

 
(335
)
 
(4
)
 
27,114

 
26,806

 
308

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
786

 
780

 
6

 
1
 %
 
785

 
778

 
7

 
1
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average revenue per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Retail
$
92.13

 
$
93.39

 
$
(1.26
)
 
(1
)%
 
$
78.83

 
$
78.63

 
$
0.20

 
—
 %
Wholesale
$
23.00

 
$
27.19

 
$
(4.19
)
 
(15
)%
 
$
22.81

 
$
25.09

 
$
(2.28
)
 
(9
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
12

 
91

 
(79
)
 
(87
)%
 
4,218

 
4,126

 
92

 
2
 %
Cooling degree days
862

 
784

 
78

 
10
 %
 
1,142

 
1,295

 
(153
)
 
(12
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWh)(1):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coal
3,764

 
4,559

 
(795
)
 
(17
)%
 
10,101

 
11,293

 
(1,192
)
 
(11
)%
Nuclear
962

 
990

 
(28
)
 
(3
)
 
2,846

 
2,838

 
8

 
—

Natural gas
297

 
275

 
22

 
8

 
361

 
549

 
(188
)
 
(34
)
Wind and other(2)
2,954

 
2,428

 
526

 
22

 
11,252

 
9,693

 
1,559

 
16

Total energy generated
7,977

 
8,252

 
(275
)
 
(3
)
 
24,560

 
24,373

 
187

 
1

Energy purchased
1,026

 
1,054

 
(28
)
 
(3
)
 
3,072

 
3,010

 
62

 
2

Total
9,003

 
9,306

 
(303
)
 
(3
)
 
27,632

 
27,383

 
249

 
1



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

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

118


Regulated electric utility margin increased $12 million for the third quarter of 2019 compared to 2018 primarily due to:
(1)
Higher retail utility margin of $8 million due to -
•
an increase of $6 million from non-weather-related sales growth, due to higher industrial usage, partially offset by lower residential usage;
•
an increase of $6 million from the favorable impact of weather;
•
an increase of $3 million, net of energy costs, from higher recoveries through bill riders, primarily related to ratemaking treatment for the impact of 2017 Tax Reform and the production tax credit component of the energy adjustment clause, partially offset by a decrease of $20 million in electric demand-side management ("DSM") program revenue (offset in operations and maintenance expense);
•
a decrease of $5 million in average revenue rates due to sales mix; and
•
a decrease of $2 million from other revenue;
(2)
Higher wholesale utility margin of $2 million due to higher margin per unit, reflecting lower energy costs, partially offset by lower sales volumes; and
(3)
Higher Multi-Value Projects ("MVP") transmission revenue of $2 million due to continued capital additions.

Regulated electric utility margin increased $55 million for the first nine months of 2019 compared to 2018 primarily due to:
(1)
Higher retail utility margin of $28 million primarily due to -
•
an increase of $42 million from non-weather-related sales growth, primarily higher industrial usage;
•
an increase of $38 million, net of energy costs, from higher recoveries through bill riders, primarily related to the production tax credit component of the energy adjustment clause and ratemaking treatment for the impact of 2017 Tax Reform, partially offset by a decrease of $30 million in electric DSM program revenue (offset in operations and maintenance expense);
•
a decrease of $32 million in averages rates, predominantly from sales mix;
•
a decrease of $17 million from the favorable impact of weather in 2018; and
•
a decrease of $3 million from other revenue;
(2)
Higher wholesale utility margin of $24 million due to higher margin per unit from lower energy costs and higher wholesale volumes; and
(3)
Higher MVP transmission revenue of $3 million due to continued capital additions.




119


Regulated Natural Gas Utility Margin

A comparison of key operating results related to regulated natural gas utility margin is as follows:
 
Third Quarter
 
First Nine Months
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Natural gas utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
$
76

 
$
103

 
$
(27
)
 
(26)
 %
 
$
482

 
$
505

 
$
(23
)
 
(5)
 %
Cost of natural gas purchased for resale
39

 
50

 
(11
)
 
(22
)
 
287

 
296

 
(9
)
 
(3
)
Natural gas utility margin
$
37

 
$
53

 
$
(16
)
 
(30
)
 
$
195

 
$
209

 
$
(14
)
 
(7
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas throughput (000's Dth):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
2,633

 
2,773

 
(140
)
 
(5)
 %
 
38,130

 
36,493

 
1,637

 
4
 %
Commercial
1,522

 
1,651

 
(129
)
 
(8
)
 
18,103

 
17,661

 
442

 
3

Industrial
929

 
985

 
(56
)
 
(6
)
 
3,424

 
3,690

 
(266
)
 
(7
)
Other
10

 
3

 
7

 
*
 
58

 
33

 
25

 
76

Total retail sales
5,094

 
5,412

 
(318
)
 
(6
)
 
59,715

 
57,877

 
1,838

 
3

Wholesale sales
7,251

 
7,569

 
(318
)
 
(4
)
 
25,856

 
27,940

 
(2,084
)
 
(7
)
Total sales
12,345

 
12,981

 
(636
)
 
(5
)
 
85,571

 
85,817

 
(246
)
 
—

Natural gas transportation service
27,011

 
21,876

 
5,135

 
23

 
81,378

 
73,968

 
7,410

 
10

Total natural gas throughput
39,356

 
34,857

 
4,499

 
13

 
166,949

 
159,785

 
7,164

 
4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
760

 
754

 
6

 
1
 %
 
761

 
755

 
6

 
1
 %
Average revenue per retail Dth sold
$
10.65

 
$
13.90

 
$
(3.25
)
 
(23)
 %
 
$
6.55

 
$
6.95

 
$
(0.40
)
 
(6)
 %
Average cost of natural gas per retail Dth sold
$
4.83

 
$
5.48

 
$
(0.65
)
 
(12)
 %
 
$
3.74

 
$
3.81

 
$
(0.07
)
 
(2)
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Combined retail and wholesale average cost of natural gas per Dth sold
$
3.17

 
$
3.86

 
$
(0.69
)
 
(18)
 %
 
$
3.35

 
$
3.44

 
$
(0.09
)
 
(3)
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
19

 
92

 
(73
)
 
(79)
 %
 
4,408

 
4,269

 
139

 
3
 %

*    Not meaningful.

Regulated natural gas utility margin decreased $16 million for the third quarter of 2019 compared to 2018 due to:
(1)
A decrease of $10 million from lower natural gas DSM program revenue (offset in operations and maintenance expense); and
(2)
A decrease of $6 million from non-weather rate and usage variances, in part due to sales mix.
Regulated natural gas utility margin decreased $14 million for the first nine months of 2019 compared to 2018 due to:
(1)
A decrease of $16 million from lower natural gas DSM program revenue (offset in operations and maintenance expense); partially offset by
(2)
An increase of $2 million from the favorable impact of weather.

Operating Expenses

MidAmerican Energy -

Operations and maintenance decreased $12 million for the third quarter of 2019 compared to 2018 primarily due to lower DSM program expense of $30 million, which is recoverable through bill riders and offset in operating revenue, partially offset by higher wind-powered generation operations and maintenance of $9 million due to additional wind turbines and easements and higher electric and gas distribution operation and maintenance of $4 million.


120


Operations and maintenance increased $2 million for the first nine months of 2019 compared to 2018 primarily due to higher wind-powered generation operations and maintenance of $25 million due to additional wind turbines and easements, higher electric distribution operations and maintenance of $8 million from emergency outage and tree-trimming costs, higher nonregulated operations costs of $7 million primarily from nonregulated utility construction services, higher transmission costs from MISO of $5 million, which are recoverable through bill riders and offset in operating revenue, higher gas distribution operations and maintenance of $5 million and various other increases, partially offset by lower DSM program expense of $46 million, which is recoverable through bill riders and offset in operating revenue, and lower fossil-fueled generation maintenance of $8 million.

Depreciation and amortization for the third quarter of 2019 increased $51 million compared to 2018 due to higher Iowa revenue sharing accruals of $33 million and wind-powered generating facilities and other plant placed in-service.

Depreciation and amortization for the first nine months of 2019 increased $41 million compared to 2018 due to wind-powered generating facilities and other plant placed in-service, partially offset by lower Iowa revenue sharing accruals of $15 million.

Other Income (Expense)

MidAmerican Energy -

Interest expense increased $12 million and $37 million for the third quarter and first nine months of 2019 compared to 2018 primarily due to higher debt outstanding.

Allowance for borrowed and equity funds increased $12 million and $26 million for the third quarter and first nine months of 2019 compared to 2018 primarily due to higher construction work-in-progress balances related to wind-powered generation.

Other, net decreased $9 million for the third quarter of 2019 compared to 2018 primarily due to higher charitable contributions and lower returns on corporate-owned life insurance policies. For the first nine months of 2019 compared to 2018, higher returns on corporate-owned life insurance policies offset higher charitable contributions.

Income Tax Benefit

MidAmerican Energy -

MidAmerican Energy's income tax benefit decreased $148 million for the third quarter of 2019 compared to 2018, and the effective tax rate was (38)% for 2019 and (88)% for 2018. For the first nine months of 2019 compared to 2018, MidAmerican Energy's income tax benefit decreased $52 million, and the effective tax rate was (81)% for 2019 and (93)% for 2018. The change in the effective tax rates for 2019 compared to 2018 were substantially due to the recognition of production tax credits and the effects of ratemaking.

Federal renewable electricity production tax credits are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities, including those facilities where a significant portion of the equipment was replaced, commonly referred to as repowered facilities, are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. Due to a combination of declines in pre-tax income and increases in production tax credits in recent years and changes in estimates for these values throughout the year, the volatility of the effective tax rate used to determine the recognition of income tax expense each quarter has similarly increased. MidAmerican Energy concluded that, due to such increased volatility, it was no longer able to reasonably estimate an annual effective tax rate for this purpose. Accordingly, beginning January 1, 2019, production tax credits are recognized in the Statement of Operations as they are earned, and excluded in the determination of the effective tax rate used in the recognition of all other income tax expense. Production tax credits recognized in income for the three-month periods ended September 30, 2019 and 2018 were $69 million and $241 million, respectively, with $185 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019. Production tax credits recognized in income for the nine-month periods ended September 30, 2019 and 2018 were $259 million and $349 million, respectively, with $129 million lower production tax credits recognized attributable to the change in the method of interim period recognition in 2019. The impact of the change in the method of interim period recognition was partially offset by increases in production tax credits earned, largely due to greater production in 2019.


121


MidAmerican Funding -

MidAmerican Funding's income tax benefit decreased $148 million for the third quarter of 2019 compared to 2018, and the effective tax rate was (40)% for 2019 and (91)% for 2018. For the first nine months of 2019 compared to 2018, MidAmerican Energy's income tax benefit decreased $52 million, and the effective tax rate was (85)% for 2019 and (97)% for 2018. The changes in the effective tax rates were principally due to the factors discussed for MidAmerican Energy.

Liquidity and Capital Resources

As of September 30, 2019, MidAmerican Energy's and MidAmerican Funding's total net liquidity were as follows (in millions):
 
MidAmerican Energy:
 
 
Cash and cash equivalents
 
$
46

 
 
 
Credit facilities, maturing 2020 and 2022
 
1,305

Less:
 
 
Tax-exempt bond support
 
(370
)
Net credit facilities
 
935

 
 
 
MidAmerican Energy total net liquidity
 
$
981

 
 
 
MidAmerican Funding:
 
 
MidAmerican Energy total net liquidity
 
$
981

Cash and cash equivalents
 
1

MHC, Inc. credit facility, maturing 2020
 
4

MidAmerican Funding total net liquidity
 
$
986


Operating Activities

MidAmerican Energy's net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018, were $1,211 million and $1,028 million, respectively. MidAmerican Funding's net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018, were $1,194 million and $1,035 million, respectively. Cash flows from operating activities increased primarily due to lower payments to vendors, MidAmerican Energy's income tax cash flows with BHE and higher cash margins for MidAmerican Energy's regulated electric business, partially offset by higher interest paid due to long-term debt issued in January 2019. MidAmerican Energy's income tax cash flows with BHE totaled net cash receipts of $309 million and $232 million in 2019 and 2018, respectively. The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.

Investing Activities

MidAmerican Energy's and MidAmerican Funding's net cash flows from investing activities for the nine-month periods ended September 30, 2019 and 2018, were $(1,903) million and $(1,463) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures, which increased due to higher wind-powered generating facility construction and repowering expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.


122


Financing Activities

MidAmerican Energy's net cash flows from financing activities for the nine-month periods ended September 30, 2019 and 2018 were $720 million and $336 million, respectively. MidAmerican Funding's net cash flows from financing activities for the nine-month periods ended September 30, 2019 and 2018, were $737 million and $329 million, respectively. In January 2019, MidAmerican Energy issued $600 million of its 3.65% First Mortgage Bonds due 2029 and $900 million of its 4.25% First Mortgage Bonds due 2049. In February 2019, MidAmerican Energy redeemed $500 million of its 2.40% First Mortgage Bonds due in March 2019 at a redemption price of 100% of the principal amount plus accrued interest. In February 2018, MidAmerican Energy issued $700 million of its 3.65% First Mortgage Bonds due 2048, and in March 2018, MidAmerican Energy repaid $350 million of its 5.30% Senior Notes due March 2018. Through its commercial paper program, MidAmerican Energy made payments totaling $240 million in 2019. MidAmerican Funding received $17 million in 2019 and paid $6 million in 2018 through its note payable with BHE.

Debt Authorizations and Related Matters

MidAmerican Energy has authority from the FERC to issue, through July 31, 2020, commercial paper and bank notes aggregating $1.3 billion at interest rates not to exceed the applicable London Interbank Offered Rate plus a spread of 400 basis points.

MidAmerican Energy currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of long-term debt securities through June 26, 2021. Additionally, following the October 2019 issuance of $850 million of first mortgage bonds, 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 Illinois Commerce Commission, to issue long-term debt securities up to an aggregate of $850 million through August 20, 2022, and preferred stock up to an aggregate of $500 million through November 1, 2020.

Future Uses of Cash

MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including regulatory approvals, their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

MidAmerican Energy has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

MidAmerican Energy's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
 
Nine-Month Periods
 
Annual
 
Ended September 30,
 
Forecast
 
2018
 
2019
 
2019
 
 
 
 
 
 
Wind-powered generation
$
704

 
$
1,027

 
$
1,447

Wind-powered generation repowering
233

 
332

 
397

Other
529

 
550

 
1,036

Total
$
1,466

 
$
1,909

 
$
2,880



123


MidAmerican Energy's forecast capital expenditures for 2019 include the following:

•
The construction of wind-powered generating facilities in Iowa. MidAmerican Energy currently has three wind-powered generation construction projects in progress, two of which are subject to ratemaking principles approved by the IUB.
In August 2016, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 2,000 MW (nominal ratings) of additional wind-powered generating facilities ("Wind XI") expected to be placed in service in 2017 through 2019, including a total of 1,345 MW (nominal ratings) placed in-service through September 30, 2019. Wind XI ratemaking principles established a cost cap of $3.6 billion, including AFUDC, a fixed rate of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding and the revenue sharing mechanism that was effective in 2018. In December 2018, the IUB issued an order approving ratemaking principles related to MidAmerican Energy's construction of up to 591 MW (nominal ratings) of additional wind-powered generating facilities ("Wind XII") expected to be placed in-service by the end of 2020. Wind XII ratemaking principles establish a cost cap of $922 million, including AFUDC, establish a fixed rate of return on equity of 11.0% over the proposed 40-year useful lives of those facilities in any future Iowa rate proceeding and provide that all Iowa retail energy benefits from Wind XII will reduce rate base and be excluded from the Iowa energy adjustment clause. Additionally, the ratemaking principles modify the Wind XI revenue sharing mechanism, effective January 1, 2019, such that revenue sharing will be triggered each year by actual equity returns above a threshold calculated annually or 11%, whichever is less, and MidAmerican Energy will share with customers 90% of the revenue in excess of the trigger, instead of 100% sharing. The threshold will be calculated each year-end and will be the weighted average of equity returns authorized via ratemaking principles for certain rate base and, for remaining rate base, interest rates on 30-year single A-rated utility bond yields plus 400 basis points, with a minimum return of 9.5%.The cost caps established by ratemaking principles ensure that as long as total costs for each project are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. MidAmerican Energy expects all of these wind-powered generating facilities to qualify for 100% of production tax credits available. Production tax credits 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 is constructing 205 MW (nominal ratings) of wind-powered generating facilities expected to be placed in-service in 2020, with a current forecast of $300 million, including AFUDC. This project is not subject to pre-approved ratemaking principles. MidAmerican Energy expects these wind-powered generating facilities to qualify for 100% of production tax credits available. Production tax credits from this project are expected to be included in MidAmerican Energy's Iowa energy adjustment clause.
•
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 production tax credits for ten years following each facility's return to service at rates that depend upon the year in which construction begins. Of the 1,307 MW of current repowering projects not in-service as of September 30, 2019, 136 MW are currently expected to qualify for 100% of the federal production tax credits available for ten years following each facility's return to service, 764 MW are expected to qualify for 80% of such credits and 407 MW 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.

Contractual Obligations

As of September 30, 2019, there have been no material changes outside the normal course of business in MidAmerican Energy's and MidAmerican Funding's contractual obligations from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2018.

Regulatory Matters

MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.


124


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, as a result of Illinois not passing adequate legislation and Quad Cities Station not clearing the 2019-2020 PJM Interconnection, L.L.C. capacity auction. MidAmerican Energy expressed to Exelon Generation its desire for the continued operation of the facility through the end of its operating license in 2032 and worked with Exelon Generation on solutions to that end. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the zero emission credits will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. For the nuclear assets already in rate base, MidAmerican Energy's customers will not be charged for the subsidy, and MidAmerican Energy will not receive additional revenue from the subsidy.

On February 14, 2017, two lawsuits were filed with the United States District Court for the Northern District of Illinois ("Northern District of Illinois") against the Illinois Power Agency alleging that the state's zero emission credit program violates certain provisions of the United States Constitution. Both lawsuits were dismissed at the Northern District of Illinois, and the United States Court of Appeals for the Seventh Circuit affirmed the dismissals. On April 15, 2019, plaintiffs' petition seeking United States Supreme Court review of the case was denied.

On January 9, 2017, the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Offer Price Rule ("MOPR") provisions to apply to existing resources receiving zero emission credit compensation. If successful, an expanded MOPR could result in an increased risk of Quad Cities Station not clearing in future capacity auctions and Exelon Generation no longer receiving capacity revenues for the facility. As majority owner and operator of Quad Cities Station, Exelon Generation has filed protests at the FERC in response to each filing. The FERC has not yet issued a decision on the requests.

On April 10, 2019, PJM Interconnection, L.L.C. ("PJM") notified the FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked the FERC to clarify that it would not require the PJM to re-run the auction in the event the FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings 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 and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2018. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2018.

125




Nevada Power Company and its subsidiaries
Consolidated Financial Section


126


PART I
Item 1.
Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of September 30, 2019, the related consolidated statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2018, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2018, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
November 1, 2019


127


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
276

 
$
111

Trade receivables, net
343

 
233

Inventories
60

 
61

Regulatory assets
1

 
39

Other current assets
74

 
75

Total current assets
754

 
519

 
 
 
 
Property, plant and equipment, net
6,475

 
6,418

Finance lease right of use assets, net
442

 
450

Regulatory assets
832

 
878

Other assets
57

 
37

 
 
 
 
Total assets
$
8,560

 
$
8,302

 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
180

 
$
187

Accrued interest
39

 
38

Accrued property, income and other taxes
94

 
30

Current portion of long-term debt
575

 
500

Current portion of finance lease obligations
24

 
20

Regulatory liabilities
82

 
49

Customer deposits
71

 
67

Other current liabilities
63

 
29

Total current liabilities
1,128

 
920

 
 
 
 
Long-term debt
1,775

 
1,853

Finance lease obligations
430

 
443

Regulatory liabilities
1,176

 
1,137

Deferred income taxes
706

 
749

Other long-term liabilities
296

 
296

Total liabilities
5,511

 
5,398

 
 
 
 
Commitments and contingencies (Note 10)

 

 
 
 
 
Shareholder's equity:
 
 
 
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding
—

 
—

Additional paid-in capital
2,308

 
2,308

Retained earnings
745

 
600

Accumulated other comprehensive loss, net
(4
)
 
(4
)
Total shareholder's equity
3,049

 
2,904

 
 
 
 
Total liabilities and shareholder's equity
$
8,560

 
$
8,302

 
 
 
 
The accompanying notes are an integral part of the consolidated financial statements.

128


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Operating revenue
$
806

 
$
820

 
$
1,728

 
$
1,777

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Cost of fuel and energy
353

 
331

 
752

 
740

Operations and maintenance
109

 
146

 
263

 
344

Depreciation and amortization
89

 
85

 
267

 
253

Property and other taxes
11

 
11

 
34

 
31

Total operating expenses
562

 
573

 
1,316

 
1,368

 
 
 
 
 
 
 
 
Operating income
244

 
247

 
412

 
409

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(41
)
 
(38
)
 
(129
)
 
(128
)
Allowance for borrowed funds
1

 
—

 
2

 
1

Allowance for equity funds
2

 
1

 
4

 
2

Other, net
4

 
7

 
17

 
16

Total other income (expense)
(34
)
 
(30
)
 
(106
)
 
(109
)
 
 
 
 
 
 
 
 
Income before income tax expense
210

 
217

 
306

 
300

Income tax expense
45

 
53

 
66

 
72

Net income
$
165

 
$
164

 
$
240

 
$
228

 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.
 
 


129


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)

 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
Additional
 
 
 
Other
 
Total
 
 
Common Stock
 
Paid-in
 
Retained
 
Comprehensive
 
Shareholder's
 
 
Shares
 
Amount
 
Capital
 
Earnings
 
Loss, Net
 
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2018
 
1,000

 
$
—

 
$
2,308

 
$
438

 
$
(4
)
 
$
2,742

Net income
 
—

 
—

 
—

 
164

 
—

 
164

Other equity transactions
 
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Balance, September 30, 2018
 
1,000

 
$
—

 
$
2,308

 
$
601

 
$
(4
)
 
$
2,905

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
 
1,000

 
$
—

 
$
2,308

 
$
374

 
$
(4
)
 
$
2,678

Net income
 
—

 
—

 
—

 
228

 
—

 
228

Other equity transactions
 
—

 
—

 
—

 
(1
)
 
—

 
(1
)
Balance, September 30, 2018
 
1,000

 
$
—

 
$
2,308

 
$
601

 
$
(4
)
 
$
2,905

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2019
 
1,000

 
$
—

 
$
2,308

 
$
580

 
$
(4
)
 
$
2,884

Net income
 
—

 
—

 
—

 
165

 
—

 
165

Balance, September 30, 2019
 
1,000

 
$
—

 
$
2,308

 
$
745

 
$
(4
)
 
$
3,049

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
 
1,000

 
$
—

 
$
2,308

 
$
600

 
$
(4
)
 
$
2,904

Net income
 
—

 
—

 
—

 
240

 
—

 
240

Dividends declared
 
—

 
—

 
—

 
(95
)
 
—

 
(95
)
Balance, September 30, 2019
 
1,000

 
$
—

 
$
2,308

 
$
745

 
$
(4
)
 
$
3,049

 
 
 
 
 
 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.


130


NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
240

 
$
228

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
267

 
253

Allowance for equity funds
(4
)
 
(2
)
Changes in regulatory assets and liabilities
62

 
75

Deferred income taxes and amortization of investment tax credits
(42
)
 
(7
)
Deferred energy
39

 
12

Amortization of deferred energy
37

 
13

Other, net
(4
)
 
8

Changes in other operating assets and liabilities:
 
 
 
Trade receivables and other assets
(110
)
 
(138
)
Inventories
2

 
1

Accrued property, income and other taxes
53

 
54

Accounts payable and other liabilities
15

 
(11
)
Net cash flows from operating activities
555

 
486

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(283
)
 
(203
)
Proceeds from sale of assets
2

 
1

Net cash flows from investing activities
(281
)
 
(202
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from long-term debt
495

 
573

Repayments of long-term debt
(500
)
 
(824
)
Dividends paid
(95
)
 
—

Other, net
(11
)
 
(12
)
Net cash flows from financing activities
(111
)
 
(263
)
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
163

 
21

Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
121

 
66

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
284

 
$
87

 
 
 
 
The accompanying notes are an integral part of these consolidated financial statements.


131


NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

(1)
General

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of September 30, 2019 and for the three- and nine-month periods ended September 30, 2019 and 2018. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2018 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies, except as disclosed in Note 4, during the nine-month period ended September 30, 2019.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Cash and cash equivalents
$
276

 
$
111

Restricted cash and cash equivalents included in other current assets
8

 
10

Total cash and cash equivalents and restricted cash and cash equivalents
$
284

 
$
121


Subsequent Event

In October 2019, Nevada Power declared and paid a dividend to NV Energy, Inc. of $200 million.


132


(3)
Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
Depreciable Life
 
September 30,
 
December 31,
 
 
2019
 
2018
Utility plant:
 
 
 
 
 
Generation
30 - 55 years
 
$
3,730

 
$
3,720

Distribution
20 - 65 years
 
3,503

 
3,411

Transmission
45 - 70 years
 
1,453

 
1,439

General and intangible plant
5 - 65 years
 
718

 
716

Utility plant
 
 
9,404

 
9,286

Accumulated depreciation and amortization
 
 
(3,096
)
 
(2,966
)
Utility plant, net
 
 
6,308

 
6,320

Other non-regulated, net of accumulated depreciation and amortization
45 years
 
1

 
1

Plant, net
 
 
6,309

 
6,321

Construction work-in-progress
 
 
166

 
97

Property, plant and equipment, net
 
 
$
6,475

 
$
6,418


(4)
Leases

Adoption

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Nevada Power adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative-effect impact to the opening balance of retained earnings at the date of initial adoption.

Nevada Power has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.

133



Leases

Lessee

Nevada Power has non-cancelable operating leases primarily for land, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities, office space and vehicles. These leases generally require Nevada Power 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. Nevada Power does not include options in its lease calculations unless there is a triggering event indicating Nevada Power is reasonably certain to exercise the option. Nevada Power's accounting policy is to not recognize lease obligations and corresponding right-of-use assets 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 ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

Nevada Power's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

Nevada Power's operating right-of-use assets are recorded in other assets and the operating lease liabilities are recorded in current and long-term other liabilities accordingly. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation. The following table summarizes Nevada Power's leases recorded on the Consolidated Balance Sheet (in millions):
 
As of
 
September 30,
 
2019
Right-of-use assets:
 
Operating leases
$
14

Finance leases
442

Total right-of-use assets
$
456

 
 
Lease liabilities:
 
Operating leases
$
17

Finance leases
454

Total lease liabilities
$
471



134


The following table summarizes Nevada Power's lease costs (in millions):
 
Three-Month Period
 
Nine-Month Period
 
Ended September 30,
 
Ended September 30,
 
2019
 
2019
 
 
 
 
Variable
$
113

 
$
333

Operating
1

 
2

Finance:
 
 
 
Amortization
3

 
9

Interest
8

 
28

Total lease costs
$
125

 
$
372

 
 
 
 
Weighted-average remaining lease term (years):
 
 
 
Operating leases
 
 
7.7

Finance leases
 
 
30.9

 
 
 
 
Weighted-average discount rate:
 
 
 
Operating leases
 
 
4.5
%
Finance leases
 
 
8.7
%

The following table summarizes Nevada Power's supplemental cash flow information relating to leases (in millions):
 
Nine-Month Period
 
Ended September 30,
 
2019
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(2
)
Operating cash flows from finance leases
(29
)
Financing cash flows from finance leases
(11
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Finance leases
$
8


Nevada Power has the following remaining lease commitments as of (in millions):
 
September 30, 2019
 
December 31, 2018(1)
 
Operating
 
Finance
 
Total
 
Operating
 
Capital
 
Total
2019
$
1

 
$
13

 
$
14

 
$
3

 
$
59

 
$
62

2020
3

 
59

 
62

 
3

 
59

 
62

2021
3

 
63

 
66

 
3

 
61

 
64

2022
2

 
61

 
63

 
3

 
60

 
63

2023
2

 
51

 
53

 
2

 
50

 
52

Thereafter
9

 
715

 
724

 
10

 
709

 
719

Total undiscounted lease payments
20

 
962

 
982

 
$
24

 
$
998

 
$
1,022

Less - amounts representing interest
(3
)
 
(508
)
 
(511
)
 
 
 
 
 
 
Lease liabilities
$
17

 
$
454

 
$
471

 
 
 
 
 
 

(1)     Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".


135


(5)
Regulatory Matters

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.

2017 Tax Reform

In February 2018, Nevada Power made a filing with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by Nevada Power. The new rates were effective April 1, 2018. The order extended the procedural schedule to allow parties additional discovery relevant to 2017 Tax Reform and a hearing was held in July 2018. In September 2018, the PUCN issued an order directing Nevada Power to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, Nevada Power filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Nevada Power filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. Nevada Power has filed opening briefs and the intervening parties have filed answering briefs. Oral arguments on the petition have been scheduled for January 2020.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs. In June 2019, the Nevada Legislature passed Senate Bill 547 ("SB 547") which modifies the 704B process. The modifications outlined in SB 547, among others, require a utility to establish limits in their integrated resource plan on the amount of load that can take service under Chapter 704B, customers taking service under Chapter 704B continue to pay for public program costs and requires the alternative energy providers to be licensed by the PUCN. In addition, SB 547 requires customers to file a 704B application with the PUCN in January allowing for alignment with the capacity amount established in the integrated resource plan.

In June 2018, Station Casinos LLC ("Station"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from an alternative provider and become a distribution only service customer of Nevada Power. In October 2018, the PUCN approved an order allowing Station to purchase energy from another energy supplier subject to conditions, including paying an impact fee of $15 million. In November 2018, Station filed a petition for reconsideration with the PUCN to allow Station to pay its share of the Renewable Base Tariff Energy Rate in a single lump sum, receive a credit for a portion of impact fees previously paid by past 704B applicants and receive a credit for a portion of incremental transmission revenue associated with expected sales to others. In December 2018, the PUCN issued an order granting reconsideration and reaffirming the October 2018 order. In February 2019, the PUCN issued an order allowing Station to alter their expected transition date from December 1, 2018 to October 1, 2019. In June 2019, Station withdrew their application.

In November 2018, Boyd Gaming Corporation ("Boyd"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from an alternative provider and become a distribution only service customer of Nevada Power. In June 2019, the PUCN approved an order allowing Boyd to purchase energy from another energy supplier subject to conditions, including paying an impact fee of $11 million. In September 2019, Boyd withdrew their application.


136


(6)
Recent Financing Transactions

Long-Term Debt

In January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029. Nevada Power used the net proceeds to repay all of Nevada Power's $500 million 7.125% General and Refunding Mortgage Notes, Series V, maturing in March 2019.

Credit Facilities

In May 2019, Nevada Power extended, with lender consent, the expiration date for its $400 million secured credit facility to June 2022 by exercising the remaining one-year extension option.

(7)
Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
 
Three-Month Period
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
%
 
21
 %
 
21
%
 
21
%
Nondeductible expenses
—

 
3


—


3

Effects of ratemaking
—

 
1

 
—

 
—

Other
—

 
(1
)
 
1

 
—

Effective income tax rate
21
%

24
 %

22
%

24
%

(8)    Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts payable to NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Qualified Pension Plan:
 
 
 
Other long-term liabilities
$
26

 
$
26

 
 
 
 
Non-Qualified Pension Plans:
 
 
 
Other current liabilities
1

 
1

Other long-term liabilities
9

 
9

 
 
 
 
Other Postretirement Plans:
 
 
 
Other long-term liabilities
1

 
1



137


(9)
Fair Value Measurements

The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date.
•
Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•
Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data.

The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
 
Input Levels for Fair Value Measurements
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of September 30, 2019
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Money market mutual funds(1)
$
261

 
$
—

 
$
—

 
$
261

Investment funds
2

 
—

 
—

 
2

 
$
263

 
$
—

 
$
—

 
$
263

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$
—

 
$
—

 
$
(18
)
 
$
(18
)
 
 
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
—

 
$
7

 
$
7

Money market mutual funds(1)
104

 
—

 
—

 
104

Investment funds
1

 
—

 
—

 
1

 
$
105

 
$
—

 
$
7

 
$
112

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$
—

 
$
—

 
$
(4
)
 
$
(4
)

(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.


138


Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of September 30, 2019 and December 31, 2018, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

The following table reconciles the beginning and ending balances of Nevada Power's commodity derivative assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Beginning balance
$
(11
)
 
$
(9
)
 
$
3

 
$
(3
)
Changes in fair value recognized in regulatory assets
(13
)
 
2

 
(30
)
 
(6
)
Settlements
6

 
—

 
9

 
2

Ending balance
$
(18
)
 
$
(7
)
 
$
(18
)
 
$
(7
)

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
 
As of September 30, 2019
 
As of December 31, 2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
2,350

 
$
2,891

 
$
2,353

 
$
2,651


(10)
Commitments and Contingencies

Fuel, Capacity and Transmission Contract Commitments

In October 2019, Nevada Power terminated a power purchase agreement, due to the supplier's failure to satisfy its performance obligations as detailed in the agreement, that had minimum annual payments of approximately $60 million in 2019 through 2023 and $1,145 million in 2024 and thereafter, as of December 31, 2018.


139


Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. Nevada Power is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.

(11)
Revenue from Contracts with Customers

The following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by customer class (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Customer Revenue:
 
 
 
 

 
 
Retail:
 
 
 
 

 
 
Residential
$
468

 
$
484

 
$
934

 
$
989

Commercial
142

 
135

 
346

 
340

Industrial
169

 
164

 
351

 
351

Other
4

 
7

 
15

 
18

Total fully bundled
783

 
790

 
1,646

 
1,698

Distribution only service
9

 
9

 
24

 
24

Total retail
792

 
799

 
1,670

 
1,722

Wholesale, transmission and other
8

 
15

 
39

 
38

Total Customer Revenue
800

 
814

 
1,709

 
1,760

Other revenue
6

 
6

 
19

 
17

Total revenue
$
806

 
$
820

 
$
1,728

 
$
1,777




140


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

Nevada Power's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. Nevada Power is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Nevada Power. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Nevada Power.

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other usage factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.


141


Results of Operations for the Third Quarter and First Nine Months of 2019 and 2018

Overview

Net income for the third quarter of 2019 was $165 million, an increase of $1 million, or 1%, compared to 2018 primarily due to $37 million of lower operations and maintenance expense, mainly due to lower political activity expenses and a lower accrual for earnings sharing. This increase is largely offset by $36 million of lower utility margin, mainly due to lower customer volumes from the unfavorable impacts of weather.

Net income for the first nine months of 2019 was $240 million, an increase of $12 million, or 5%, compared to 2018 primarily due to $81 million of lower operations and maintenance expense, mainly due to lower political activity expenses, a lower accrual for earnings sharing and lower settlement costs associated with a personal injury claim in 2018. This increase is partially offset by $61 million of lower utility margin, mainly due to lower customer volumes from the unfavorable impacts of weather and lower average retail rates related to the tax rate reduction rider effective April 2018.

Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.
Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
 
$
806

 
$
820

 
$
(14
)
(2
)%
 
$
1,728

 
$
1,777

 
$
(49
)
(3
)%
Cost of fuel and energy
 
353

 
331

 
22

7

 
752

 
740

 
12

2

Utility margin
 
453

 
489

 
(36
)
(7
)
 
976

 
1,037

 
(61
)
(6
)
Operations and maintenance
 
109

 
146

 
(37
)
(25
)
 
263

 
344

 
(81
)
(24
)
Depreciation and amortization
 
89

 
85

 
4

5

 
267

 
253

 
14

6

Property and other taxes
 
11

 
11

 
—

—

 
34

 
31

 
3

10

Operating income
 
$
244

 
$
247

 
$
(3
)
(1
)
 
$
412

 
$
409

 
$
3

1



142


A comparison of Nevada Power's key operating results is as follows:
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating revenue
 
$
806

 
$
820

 
$
(14
)
(2
)%
 
$
1,728

 
$
1,777

 
$
(49
)
(3
)%
Cost of fuel and energy
 
353

 
331

 
22

7

 
752

 
740

 
12

2

Utility margin
 
$
453

 
$
489

 
$
(36
)
(7
)
 
$
976

 
$
1,037

 
$
(61
)
(6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
GWh sold:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
3,908

 
4,213

 
(305
)
(7
)%
 
7,692

 
8,299

 
(607
)
(7
)%
Commercial
 
1,569

 
1,568

 
1

—

 
3,698

 
3,759

 
(61
)
(2
)
Industrial
 
1,600

 
1,631

 
(31
)
(2
)
 
4,140

 
4,281

 
(141
)
(3
)
Other
 
49

 
61

 
(12
)
(20
)
 
143

 
157

 
(14
)
(9
)
Total fully bundled(1)
 
7,126

 
7,473

 
(347
)
(5
)
 
15,673

 
16,496

 
(823
)
(5
)
Distribution only service
 
786

 
775

 
11

1

 
2,006

 
1,938

 
68

4

Total retail
 
7,912

 
8,248

 
(336
)
(4
)
 
17,679

 
18,434

 
(755
)
(4
)
Wholesale
 
50

 
53

 
(3
)
(6
)
 
314

 
181

 
133

73

Total GWh sold
 
7,962

 
8,301

 
(339
)
(4
)
 
17,993

 
18,615

 
(622
)
(3
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
843

 
828

 
15

2
 %
 
839

 
823

 
16

2
 %
Commercial
 
109

 
108

 
1

1

 
109

 
107

 
2

2

Industrial
 
2

 
2

 
—

—

 
2

 
2

 
—

—

Total
 
954

 
938

 
16

2

 
950

 
932

 
18

2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue - fully bundled(1)
 
$
109.94

 
$
105.82

 
$
4.12

4
 %
 
$
105.04

 
$
102.93

 
$
2.11

2
 %
Wholesale
 
$
36.63

 
$
54.80

 
$
(18.17
)
(33
)%
 
$
35.64


$
37.97


$
(2.33
)
(6
)%
Total cost of energy(2)(3)
 
$
48.80

 
$
41.93

 
$
6.87

16
 %
 
$
48.33

 
$
44.14

 
$
4.19

9
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
 
—

 
—

 
—

—

 
1,108

 
839

 
269

32
 %
Cooling degree days
 
2,392

 
2,580

 
(188
)
(7
)%
 
3,511

 
4,072

 
(561
)
(14
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWh)(3)(4):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
5,042

 
5,282

 
(240
)
(5
)%
 
10,296

 
11,295

 
(999
)
(9
)%
Coal
 
377

 
403

 
(26
)
(6
)
 
968

 
891

 
77

9

Renewables
 
20

 
20

 
—

—

 
50

 
56

 
(6
)
(11
)
Total energy generated
 
5,439

 
5,705

 
(266
)
(5
)
 
11,314

 
12,242

 
(928
)
(8
)
Energy purchased
 
1,787

 
2,214

 
(427
)
(19
)
 
4,958

 
5,209

 
(251
)
(5
)
Total
 
7,226

 
7,919

 
(693
)
(9
)
 
16,272

 
17,451

 
(1,179
)
(7
)
*    Not meaningful
(1)
Fully bundled includes sales to customers for combined energy, transmission and distribution services.
(2)
The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs.
(3)
The average total cost of energy per MWh and sources of energy excludes 15 and - GWh of coal and 199 and - GWh of gas generated energy that is purchased at cost by related parties for the third quarter of 2019 and 2018, respectively. The average total cost of energy per MWh and sources of energy excludes 133 and 93 GWh of coal and 1,122 and 1,043 GWh of gas generated energy that is purchased at cost by related parties for the first nine months of 2019 and 2018, respectively.
(4)
GWh amounts are net of energy used by the related generating facilities.

143


Utility margin decreased $36 million, or 7%, for the third quarter of 2019 compared to 2018 primarily due to $31 million of lower customer volumes primarily from the unfavorable impacts of weather and lower transmission revenue of $7 million, partially offset by $4 million of residential customer growth.

Operations and maintenance decreased $37 million, or 25%, for the third quarter of 2019 compared to 2018 primarily due to a lower accrual for earnings sharing, lower political activity expenses and the impacts of adopting ASC 842, "Leases" ("ASC 842").

Depreciation and amortization increased $4 million, or 5%, for the third quarter of 2019 compared to 2018 primarily due to the impacts of adopting ASC 842 and higher plant placed in service.

Other income (expense) is unfavorable $(4) million, or (13)%, for the third quarter of 2019 compared to 2018 primarily due to the impacts of adopting ASC 842 and higher non-service pension expense, partially offset by lower interest expense on long-term debt and higher dividend and interest income.

Income tax expense decreased $8 million, or 15%, for the third quarter of 2019 compared to 2018. The effective tax rate was 21% in 2019 and 24% in 2018 and decreased due to lower nondeductible expenses.

Utility margin decreased $61 million, or 6%, for the first nine months of 2019 compared to 2018 primarily due to:
•
$49 million in lower customer volumes primarily from the unfavorable impacts of weather,
•
$11 million in lower retail rates due to the tax rate reduction rider effective April 2018,
•
$4 million from lower transmission revenue, and
•
$3 million due to lower retail rates as a result of the 2017 regulatory rate review with rates effective February 2018.
The decrease in utility margin was offset by:
•
$7 million due to residential and commercial customer growth.

Operations and maintenance decreased $81 million, or 24%, for the first nine months of 2019 compared to 2018 primarily due to the impacts of adopting ASC 842, lower political activity expenses, a lower accrual for earnings sharing and settlement costs associated with a personal injury claim in 2018.

Depreciation and amortization increased $14 million, or 6%, for the first nine months of 2019 compared to 2018 primarily due to the impacts of adopting ASC 842 and higher plant placed in service.

Property and other taxes increased $3 million, or 10%, for the first nine months of 2019 compared to 2018 due to a decrease in available abatements.

Other income (expense) is favorable $3 million, or 3%, for the first nine months of 2019 compared to 2018 primarily due to lower interest expense on long-term debt, higher dividend and interest income and higher other income due to a licensing agreement with a third party, partially offset by the impacts of adopting ASC 842 and higher non-service pension expense.

Income tax expense decreased $6 million, or 8%, for the first nine months of 2019 compared to 2018. The effective tax rate was 22% in 2019 and 24% in 2018 and decreased due to lower nondeductible expenses.

Liquidity and Capital Resources

As of September 30, 2019, Nevada Power's total net liquidity was as follows (in millions):

Cash and cash equivalents
 
$
276

Credit facility
 
400

Total net liquidity
 
$
676

Credit facility:
 
 
Maturity date
 
2022



144


Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018 were $555 million and $486 million, respectively. The change was due to lower interest payments for long-term debt, lower payments for operating costs, mainly due to lower political activity expenses, lower contributions to the pension plan, increased collections of customer advances, primarily relating to temporary deposits for solar power purchase agreements under construction and proceeds from a licensing agreement with a third party, partially offset by lower collections from customers due to the unfavorable impacts of weather, higher payments for income taxes and increased payment for fuel costs.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2019 and 2018 were $(281) million and $(202) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2019 and 2018 were $(111) million and $(263) million, respectively. The change was due to lower repayments of long-term debt, partially offset by lower proceeds from issuance of long-term debt and higher dividends paid to NV Energy, Inc. of $95 million in 2019.

In October 2019, Nevada Power declared and paid a dividend to NV Energy, Inc. of $200 million.

Long-Term Debt

In January 2019, Nevada Power issued $500 million of its 3.70% General and Refunding Mortgage Notes, Series CC, due May 2029. Nevada Power used the net proceeds to repay all of Nevada Power's $500 million 7.125% General and Refunding Mortgage Notes, Series V, maturing in March 2018.

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) issue new long-term debt securities of up to $1.3 billion; (2) refinance up to $156 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective automatic shelf registration statement with the SEC to issue an indeterminate amount of general and refunding mortgage securities through October 2022.

Future Uses of Cash

Nevada Power has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.


145


Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
 
Nine-Month Periods
 
Annual
 
Ended September 30,
 
Forecast
 
2018
 
2019
 
2019
 
 
 
 
 
 
Distribution
93

 
148

 
201

Transmission system investment
6

 
18

 
27

Other
104

 
117

 
197

Total
$
203

 
$
283

 
$
425


Nevada Power's forecast capital expenditures include investments related to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Integrated Resource Planning

In June 2019, the Nevada Utilities filed an amendment to their 2018 Joint Integrated Resource Plan requesting approval of three power purchase agreements for 1,190 MW of solar photovoltaic generating resources with an additional 590 MW of co-located battery storage.

Contractual Obligations

As of September 30, 2019, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2018 other than the power purchase agreement termination discussed below.

In October 2019, Nevada Power terminated a power purchase agreement, due to the supplier's failure to satisfy its performance obligations as detailed in the agreement, that had annual contractual cash obligations of approximately $60 million in 2019 through 2023 and $1,145 million in 2024 and thereafter, as of December 31, 2018.

Regulatory Matters

Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Nevada Power believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.


146


Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2018. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2018.

147


Sierra Pacific Power Company
Financial Section


148


PART I
Item 1.
Financial Statements


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors and Shareholder of
Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of Sierra Pacific Power Company ("Sierra Pacific") as of September 30, 2019, the related statements of operations and changes in shareholder's equity for the three-month and nine-month periods ended September 30, 2019 and 2018, and of cash flows for the nine-month periods ended September 30, 2019 and 2018, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of Sierra Pacific as of December 31, 2018, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 22, 2019, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2018, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.


/s/ Deloitte & Touche LLP


Las Vegas, Nevada
November 1, 2019


149


SIERRA PACIFIC POWER COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)

 
As of
 
September 30,
 
December 31,
 
2019
 
2018
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
64

 
$
71

Trade receivables, net
98

 
100

Inventories
59

 
52

Regulatory assets
9

 
7

Other current assets
30

 
33

Total current assets
260

 
263

 
 
 
 
Property, plant and equipment, net
3,026

 
2,947

Regulatory assets
307

 
314

Other assets
75

 
45

 
 
 
 
Total assets
$
3,668

 
$
3,569

 
 
 
 
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
 
 
 
Accounts payable
$
100

 
$
116

Accrued interest
11

 
13

Accrued property, income and other taxes
28

 
14

Regulatory liabilities
42

 
18

Customer deposits
21

 
18

Other current liabilities
33

 
18

Total current liabilities
235

 
197

 
 
 
 
Long-term debt
1,135

 
1,120

Regulatory liabilities
487

 
491

Deferred income taxes
334

 
331

Other long-term liabilities
179

 
166

Total liabilities
2,370

 
2,305

 
 
 
 
Commitments and contingencies (Note 10)

 

 
 
 
 
Shareholder's equity:
 
 
 
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding
—

 
—

Additional paid-in capital
1,111

 
1,111

Retained earnings
187

 
153

Total shareholder's equity
1,298

 
1,264

 
 
 
 
Total liabilities and shareholder's equity
$
3,668

 
$
3,569

 
 
 
 
The accompanying notes are an integral part of the financial statements.


150


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)

 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
232

 
$
225

 
$
586

 
$
575

Regulated natural gas
16

 
14

 
75

 
74

Total operating revenue
248

 
239

 
661

 
649

 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Cost of fuel and energy
93

 
90

 
254

 
245

Cost of natural gas purchased for resale
6

 
4

 
35

 
35

Operations and maintenance
46

 
53

 
130

 
140

Depreciation and amortization
31

 
30

 
94

 
89

Property and other taxes
5

 
6

 
17

 
18

Total operating expenses
181

 
183

 
530

 
527

 
 
 
 
 
 
 
 
Operating income
67

 
56

 
131

 
122

 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(12
)
 
(12
)
 
(36
)
 
(33
)
Allowance for borrowed funds
—

 
—

 
1

 
1

Allowance for equity funds
—

 
1

 
2

 
3

Other, net
1

 
3

 
4

 
8

Total other income (expense)
(11
)
 
(8
)
 
(29
)
 
(21
)
 
 
 
 
 
 
 
 
Income before income tax expense
56

 
48

 
102

 
101

Income tax expense
12

 
13

 
22

 
25

Net income
$
44

 
$
35

 
$
80

 
$
76

 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these financial statements.


151


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)

 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
Additional
 
 
 
Other
 
Total
 
 
Common Stock
 
Paid-in
 
Retained
 
Comprehensive
 
Shareholder's
 
 
Shares
 
Amount
 
Capital
 
Earnings
 
Loss, Net
 
Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2018
 
1,000

 
$
—

 
$
1,111

 
$
102

 
$
(1
)
 
$
1,212

Net income
 
—

 
—

 
—

 
35

 
—

 
35

Other equity transactions
 
—

 
—

 
—

 
1

 
—

 
1

Balance, September 30, 2018
 
1,000

 
$
—

 
$
1,111

 
$
138

 
$
(1
)
 
$
1,248

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2017
 
1,000

 
$
—

 
$
1,111

 
$
62

 
$
(1
)
 
$
1,172

Net income
 
—

 
—

 
—

 
76

 
—

 
76

Balance, September 30, 2018
 
1,000

 
$
—

 
$
1,111

 
$
138

 
$
(1
)
 
$
1,248

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, June 30, 2019
 
1,000

 
$
—

 
$
1,111

 
$
143

 
$
—

 
$
1,254

Net income
 
—

 
—

 
—

 
44

 
—

 
44

Balance, September 30, 2019
 
1,000

 
$
—

 
$
1,111

 
$
187

 
$
—

 
$
1,298

 
 
 
 
 
 
 
 
 
 
 
 
 
Balance, December 31, 2018
 
1,000

 
$
—

 
$
1,111

 
$
153

 
$
—

 
$
1,264

Net income
 
—

 
—

 
—

 
80

 
—

 
80

Dividends declared
 
—

 
—

 
—

 
(46
)
 
—

 
(46
)
Balance, September 30, 2019
 
1,000

 
$
—

 
$
1,111

 
$
187

 
$
—

 
$
1,298

 
 
 
 
 
 
 
 
 
 
 
 
 
The accompanying notes are an integral part of these financial statements.


152


SIERRA PACIFIC POWER COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)

 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
Cash flows from operating activities:
 
 
 
Net income
$
80

 
$
76

Adjustments to reconcile net income to net cash flows from operating activities:
 
 
 
Depreciation and amortization
94

 
89

Allowance for equity funds
(2
)
 
(3
)
Changes in regulatory assets and liabilities
30

 
32

Deferred income taxes and amortization of investment tax credits
(5
)
 
9

Deferred energy
7

 
26

Amortization of deferred energy
(5
)
 
(6
)
Other, net
(3
)
 
—

Changes in other operating assets and liabilities:
 
 
 
Trade receivables and other assets
(3
)
 
(3
)
Inventories
(7
)
 
(5
)
Accrued property, income and other taxes
10

 
(2
)
Accounts payable and other liabilities
(7
)
 
(5
)
Net cash flows from operating activities
189

 
208

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(165
)
 
(139
)
Proceeds from sale of asset
1

 
—

Net cash flows from investing activities
(164
)
 
(139
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Proceeds from long-term debt
125

 
—

Repayments of long-term debt
(109
)
 
—

Dividends paid
(46
)
 
—

Other, net
(3
)
 
(2
)
Net cash flows from financing activities
(33
)
 
(2
)
 
 
 
 
Net change in cash and cash equivalents and restricted cash and cash equivalents
(8
)
 
67

Cash and cash equivalents and restricted cash and cash equivalents at beginning of period
76

 
8

Cash and cash equivalents and restricted cash and cash equivalents at end of period
$
68

 
$
75

 
 
 
 
The accompanying notes are an integral part of these financial statements.


153


SIERRA PACIFIC POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
(Unaudited)

(1)
General

Sierra Pacific Power Company ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of September 30, 2019 and for the three- and nine-month periods ended September 30, 2019 and 2018. The Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three- and nine-month periods ended September 30, 2019 and 2018. The results of operations for the three- and nine-month periods ended September 30, 2019 are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Financial Statements. Note 2 of Notes to Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2018 describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies, except as disclosed in Note 4, during the nine-month period ended September 30, 2019.

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

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of September 30, 2019 and December 31, 2018, as presented in the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Cash and cash equivalents
$
64

 
$
71

Restricted cash and cash equivalents included in other current assets
4

 
5

Total cash and cash equivalents and restricted cash and cash equivalents
$
68

 
$
76



154


(3)
Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):
 
 
 
As of
 
Depreciable Life
 
September 30,
 
December 31,
 
 
2019
 
2018
Utility plant:
 
 
 
 
 
Electric generation
25 - 60 years
 
$
1,133

 
$
1,132

Electric distribution
20 - 100 years
 
1,657

 
1,568

Electric transmission
50 - 100 years
 
831

 
812

Electric general and intangible plant
5 - 70 years
 
175

 
185

Natural gas distribution
35 - 70 years
 
415

 
403

Natural gas general and intangible plant
5 - 70 years
 
14

 
14

Common general
5 - 70 years
 
322

 
321

Utility plant
 
 
4,547

 
4,435

Accumulated depreciation and amortization
 
 
(1,624
)
 
(1,583
)
Utility plant, net
 
 
2,923

 
2,852

Other non-regulated, net of accumulated depreciation and amortization
70 years
 
4

 
5

Plant, net
 
 
2,927

 
2,857

Construction work-in-progress
 
 
99

 
90

Property, plant and equipment, net
 
 
$
3,026

 
$
2,947


(4)
Leases

Adoption

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, which creates FASB Accounting Standards Codification ("ASC") Topic 842, "Leases" and supersedes Topic 840 "Leases." This guidance increases transparency and comparability among entities by recording lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. A lessee should recognize on the balance sheet a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous guidance. Following the issuance of ASU No. 2016-02, the FASB issued several ASUs that clarified the implementation guidance for ASU No. 2016-02 but did not change the core principle of the guidance. Sierra Pacific adopted this guidance for all applicable contracts in-effect as of January 1, 2019 under a modified retrospective method and the adoption did not have a cumulative-effect impact at the date of initial adoption.

Sierra Pacific has elected to utilize various practical expedients available to adopt ASU No. 2016-02, including (1) the package of three not requiring a reassessment of (i) whether any expired or existing contracts are or contain leases; (ii) the lease classification for any expired or existing leases; and (iii) initial direct costs for any existing leases; (2) using hindsight in determining the lease term; and (3) not requiring a reassessment of whether existing or expired land easements that were not previously accounted for as leases under ASC Topic 840 are or contain a lease under ASC Topic 842.


155


Leases

Lessee

Sierra Pacific has non-cancelable operating leases primarily for transmission and delivery assets, generating facilities, vehicles and office equipment and finance leases consisting primarily of transmission assets, generating facilities and vehicles. These leases generally require Sierra Pacific 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. Sierra Pacific does not include options in its lease calculations unless there is a triggering event indicating Sierra Pacific is reasonably certain to exercise the option. Sierra Pacific's accounting policy is to not recognize lease obligations and corresponding right-of-use assets 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 ASC Topic 360, "Property, Plant and Equipment" when a triggering event has occurred that might affect the value and use of the assets being leased.

Sierra Pacific's leases of generating facilities generally are for the long-term purchase of electric energy, also known as power purchase agreements ("PPA"). PPAs are generally signed before or during the early stages of project construction and can yield a lease that has not yet commenced. These agreements are primarily for renewable energy and the payments are considered variable lease payments as they are based on the amount of output.

Sierra Pacific's 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. The right-of-use assets and lease liabilities for finance leases as of December 31, 2018 have been reclassified from property, plant and equipment, net and current portion of long-term and long-term debt, respectively, to conform to the current period presentation. The following table summarizes Sierra Pacific's leases recorded on the Balance Sheet (in millions):
 
As of
 
September 30,
 
2019
Right-of-use assets:
 
Operating leases
$
18

Finance leases
41

Total right-of-use assets
$
59

 
 
Lease liabilities:
 
Operating leases
$
18

Finance leases
42

Total lease liabilities
$
60



156


The following table summarizes Sierra Pacific's lease costs (in millions):
 
Three-Month Period
 
Nine-Month Period
 
Ended September 30,
 
Ended September 30,
 
2019
 
2019
 
 
 
 
Variable
$
21

 
$
51

Operating
—

 
1

Finance:
 
 
 
Amortization
—

 
1

Interest
1

 
2

Total lease costs
$
22

 
$
55

 
 
 
 
Weighted-average remaining lease term (years):
 
 
 
Operating leases
 
 
26.0

Finance leases
 
 
22.1

 
 
 
 
Weighted-average discount rate:
 
 
 
Operating leases
 
 
5.0
%
Finance leases
 
 
7.2
%

The following table summarizes Sierra Pacific's supplemental cash flow information relating to leases (in millions):
 
Nine-Month Period
 
Ended September 30,
 
2019
Cash paid for amounts included in the measurement of lease liabilities:
 
Operating cash flows from operating leases
$
(2
)
Operating cash flows from finance leases
(2
)
Financing cash flows from finance leases
(2
)
Right-of-use assets obtained in exchange for lease liabilities:
 
Finance leases
$
5


Sierra Pacific has the following remaining lease commitments as of (in millions):
 
September 30, 2019
 
December 31, 2018(1)
 
Operating
 
Finance
 
Total
 
Operating
 
Capital
 
Total
2019
$
—

 
$
2

 
$
2

 
$
2

 
$
6

 
$
8

2020
2

 
6

 
8

 
2

 
4

 
6

2021
2

 
6

 
8

 
2

 
5

 
7

2022
1

 
5

 
6

 
1

 
4

 
5

2023
1

 
5

 
6

 
1

 
4

 
5

Thereafter
27

 
48

 
75

 
28

 
47

 
75

Total undiscounted lease payments
33

 
72

 
105

 
$
36

 
$
70

 
$
106

Less - amounts representing interest
(15
)
 
(30
)
 
(45
)
 
 
 
 
 
 
Lease liabilities
$
18

 
$
42

 
$
60

 
 
 
 
 
 

(1)     Amounts included for comparability and accounted for in accordance with ASC Topic 840, "Leases".


157


(5)
Regulatory Matters

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Statements of Operations but rather is deferred and recorded as a regulatory asset on the Balance Sheets. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel and energy in future time periods.

2017 Tax Reform

In February 2018, Sierra Pacific made a filing with the PUCN proposing a tax rate reduction rider for the lower annual income tax expense anticipated to result from 2017 Tax Reform for 2018 and beyond. In March 2018, the PUCN issued an order approving the rate reduction proposed by Sierra Pacific. The new rates were effective April 1, 2018. The 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 Sierra Pacific to record the amortization of any excess protected accumulated deferred income tax arising from the 2017 Tax Reform as a regulatory liability effective January 1, 2018. Subsequently, Sierra Pacific filed a petition for reconsideration relating to the amortization of protected excess accumulated deferred income tax balances resulting from the 2017 Tax Reform. In November 2018, the PUCN issued an order granting reconsideration and reaffirming the September 2018 order. In December 2018, Sierra Pacific filed a petition for judicial review. In January 2019, intervening parties filed statements of intent to participate in the petition for judicial review. Sierra Pacific has filed opening briefs and the intervening parties have filed answering briefs. Oral arguments on the petition have been scheduled for January 2020.

Chapter 704B Applications

Chapter 704B of the Nevada Revised Statutes allows retail electric customers with an average annual load of one megawatt ("MW") or more to file with the PUCN an application to purchase energy from alternative providers of a new electric resource and become distribution only service customers. On a case-by-case basis, the PUCN will assess the application and may deny or grant the application subject to conditions, including paying an impact fee, paying on-going charges and receiving approval for specific alternative energy providers and terms. The impact fee and on-going charges are assessed to alleviate the burden on other Nevada customers for the applicant's share of previously committed investments and long-term renewable contracts and are set at a level designed such that the remaining customers are not subjected to increased costs. In June 2019, the Nevada Legislature passed Senate Bill 547 ("SB 547") which modifies the 704B process. The modifications outlined in SB 547, among others, require a utility to establish limits in their integrated resource plan on the amount of load that can take service under Chapter 704B, customers taking service under Chapter 704B continue to pay for public program costs and requires the alternative energy providers to be licensed by the PUCN. In addition, SB 547 requires customers to file a 704B application with the PUCN in January allowing for alignment with the capacity amount established in the integrated resource plan.

(6)    Recent Financing Transactions

Long-Term Debt

In April 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; and $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036. Sierra Pacific purchased the Series 2016C, Series 2016D and Series 2016E bonds as required by the bond indentures.


158


In April 2019, Sierra Pacific entered into a re-offering of the following series of bonds: $30 million of its variable-rate tax-exempt Humboldt County Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; the Series 2016D bonds; the Series 2016E bonds; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; and $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Series 2016B and Series 2016G bonds were offered at a fixed rate of 1.85%. The Series 2016D, Series 2016E and Series 2016F bonds were offered at a fixed rate of 2.05%. Sierra Pacific previously purchased the Series 2016B, Series 2016F and Series 2016G bonds on their date of issuance. Sierra Pacific holds the Series 2016C bonds and the bonds could be issued at a future date if required by future regulatory proceedings. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.

In June 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $59 million of its fixed-rate tax-exempt Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031 and $20 million of its fixed-rate tax-exempt Humboldt County Pollution Control Refunding Revenue Bonds, Series 2016A, due 2029. Sierra Pacific holds these bonds and the bonds could be issued at a future date if required by future regulatory proceedings.

Credit Facilities

In May 2019, Sierra Pacific extended, with lender consent, the expiration date for its $250 million secured credit facility to June 2022 by exercising the remaining one-year extension option.

(7)    Income Taxes

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense is as follows:
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
 
 
 
 
 
 
 
 
Federal statutory income tax rate
21
%
 
21
%
 
21
%
 
21
%
Nondeductible expenses
—


5


—


4

Effects of ratemaking
—

 
1

 
—

 
—

Other
—

 
—

 
1

 
—

Effective income tax rate
21
%
 
27
%
 
22
%
 
25
%

(8)
Employee Benefit Plans

Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.


159


Amounts payable to NV Energy are included on the Balance Sheets and consist of the following (in millions):
 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Qualified Pension Plan:
 
 
 
Other long-term liabilities
$
18

 
$
19

 
 
 
 
Non-Qualified Pension Plans:
 
 
 
Other current liabilities
1

 
1

Other long-term liabilities
7

 
7

 
 
 
 
Other Postretirement Plans:
 
 
 
Other long-term liabilities
13

 
13


(9)
Fair Value Measurements

The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities that are measured at fair value on the Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date.
•
Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).
•
Level 3 — Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.

The following table presents Sierra Pacific's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
 
Input Levels for Fair Value Measurements
 
 
 
Level 1
 
Level 2
 
Level 3
 
Total
As of September 30, 2019
 
 
 
 
 
 
 
Assets - money market mutual funds(1)
$
56

 
$
—

 
$
—

 
$
56

 
 
 
 
 
 
 
 
Liabilities - commodity derivatives
$
—

 
$
—

 
$
(4
)
 
$
(4
)
 
 
 
 
 
 
 
 
As of December 31, 2018
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
—

 
$
2

 
$
2

Money market mutual funds(1)
45

 
—

 
—

 
45

 
$
45

 
$
—

 
$
2

 
$
47


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


160


Sierra Pacific's investments in money market mutual funds and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.

Sierra Pacific's long-term debt is carried at cost on the Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Sierra Pacific's long-term debt (in millions):
 
As of September 30, 2019
 
As of December 31, 2018
 
Carrying
 
Fair
 
Carrying
 
Fair
 
Value
 
Value
 
Value
 
Value
 
 
 
 
 
 
 
 
Long-term debt
$
1,135

 
$
1,270

 
$
1,120

 
$
1,167


(10)
Commitments and Contingencies

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Legal Matters

Sierra Pacific is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its financial results. Sierra Pacific is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts.

(11)
Revenue from Contracts with Customers

The following table summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 12 (in millions):
 
Three-Month Periods
 
Ended September 30,
 
2019
 
2018
 
Electric

Gas

Total
 
Electric
 
Gas
 
Total
Customer Revenue:





 

 

 
 
Retail:





 

 

 
 
Residential
$
75


$
11


$
86

 
$
76

 
$
9

 
$
85

Commercial
80


3


83

 
75

 
3

 
78

Industrial
58


1


59

 
59

 
1

 
60

Other
2


—


2

 
2

 
—

 
2

Total fully bundled
215


15


230

 
212

 
13

 
225

Distribution only service
1


—


1

 
1

 
—

 
1

Total retail
216


15


231

 
213

 
13

 
226

Wholesale, transmission and other
16


—


16

 
12

 
1

 
13

Total Customer Revenue
232


15


247

 
225

 
14

 
239

Other revenue
—


1


1

 
—

 
—

 
—

Total revenue
$
232


$
16


$
248

 
$
225

 
$
14

 
$
239


161


 
Nine-Month Periods
 
Ended September 30,
 
2019
 
2018
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Customer Revenue:
 
 
 
 
 
 
 
 
 
 
 
Retail:
 
 
 
 
 
 
 
 
 
 
 
Residential
$
201

 
$
49

 
$
250

 
$
203

 
$
48

 
$
251

Commercial
188

 
18

 
206

 
190

 
18

 
208

Industrial
143

 
6

 
149

 
136

 
6

 
142

Other
5

 
—

 
5

 
5

 
—

 
5

Total fully bundled
537

 
73

 
610

 
534

 
72

 
606

Distribution only service
3

 
—

 
3

 
3

 
—

 
3

Total retail
540

 
73

 
613

 
537

 
72

 
609

Wholesale, transmission and other
44

 
—

 
44

 
35

 
1

 
36

Total Customer Revenue
584

 
73

 
657

 
572

 
73

 
645

Other revenue
2

 
2

 
4

 
3

 
1

 
4

Total revenue
$
586

 
$
75

 
$
661

 
$
575

 
$
74

 
$
649


(12)
Segment Information

Sierra Pacific has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

The following tables provide information on a reportable segment basis (in millions):
 
Three-Month Periods
 
Nine-Month Periods
 
Ended September 30,
 
Ended September 30,
 
2019
 
2018
 
2019
 
2018
Operating revenue:
 
 
 
 
 
 
 
Regulated electric
$
232

 
$
225

 
$
586

 
$
575

Regulated natural gas
16

 
14

 
75

 
74

Total operating revenue
$
248

 
$
239

 
$
661

 
$
649

 
 
 
 
 
 
 
 
Operating income:
 
 
 
 
 
 
 
Regulated electric
$
67

 
$
56

 
$
119

 
$
111

Regulated natural gas
—

 
—

 
12

 
11

Total operating income
67

 
56

 
131

 
122

Interest expense
(12
)
 
(12
)
 
(36
)
 
(33
)
Allowance for borrowed funds
—

 
—

 
1

 
1

Allowance for equity funds
—

 
1

 
2

 
3

Other, net
1

 
3

 
4

 
8

Income before income tax expense
$
56

 
$
48

 
$
102

 
$
101


162


 
As of
 
September 30,
 
December 31,
 
2019
 
2018
Assets:
 
 
 
Regulated electric
$
3,282

 
$
3,177

Regulated natural gas
304

 
314

Regulated common assets(1)
82

 
78

Total assets
$
3,668

 
$
3,569


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

163


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

Sierra Pacific's revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy, natural gas and resources. Sierra Pacific's electric segment is summer peaking experiencing its highest retail energy sales in response to the demand for air conditioning and its natural gas segment is winter peaking due to sales in response to the demand for heating. The variations in energy usage due to varying weather, customer growth and other energy usage patterns, including energy efficiency and conservation measures, necessitates a continual balancing of loads and resources and purchases and sales of energy under short- and long-term energy supply contracts. As a result, the prudent management and optimization of available resources has a direct effect on the operating and financial performance of Sierra Pacific. Additionally, the timely recovery of purchased power, fuel costs and other costs and the ability to earn a fair return on investments through rates are essential to the operating and financial performance of Sierra Pacific.

The following is management's discussion and analysis of certain significant factors that have affected the financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other usage factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.


164


Results of Operations for the Third Quarter and First Nine Months of 2019 and 2018

Overview

Net income for the third quarter of 2019 was $44 million, an increase of $9 million, or 26%, compared to 2018 primarily due to $7 million of lower operations and maintenance expense, mainly due to lower political activity expenses, and $4 million of higher electric utility margin, mainly due to higher transmission revenue.

Net income for the first nine months of 2019 was $80 million, an increase of $4 million, or 5%, compared to 2018 primarily due to $10 million of lower operations and maintenance expense, mainly due to lower political activity expenses, and $2 million of higher electric utility margin, mainly due to $5 million of higher transmission revenue and $3 million of customer growth, partially offset by lower average retail rates related to the tax rate reduction rider effective April 2018. These increases are partially offset by $4 million of unfavorable other, net, mainly due to higher non-service pension expense.

Non-GAAP Financial Measure
Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Statements of Operations.
Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.
Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Electric utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric operating revenue
 
$
232

 
$
225

 
$
7

3
 %
 
$
586

 
$
575

 
$
11

2
 %
Cost of fuel and energy
 
93

 
90

 
3

3

 
254

 
245

 
9

4

Electric utility margin
 
139

 
135

 
4

3

 
332

 
330

 
2

1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas utility margin:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas operating revenue
 
16

 
14

 
2

14
 %
 
75

 
74

 
1

1
 %
Cost of natural gas purchased for resale
 
6

 
4

 
2

50

 
35

 
35

 
—

—

Natural gas utility margin
 
10

 
10

 
—

—

 
40

 
39

 
1

3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility margin
 
149

 
145

 
4

3
 %
 
372

 
369

 
3

1
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operations and maintenance
 
46

 
53

 
(7
)
(13
)%
 
130

 
140

 
(10
)
(7
)%
Depreciation and amortization
 
31

 
30

 
1

3

 
94

 
89

 
5

6

Property and other taxes
 
5

 
6

 
(1
)
(17
)
 
17

 
18

 
(1
)
(6
)
Operating income
 
$
67

 
$
56

 
$
11

20
 %
 
$
131

 
$
122

 
$
9

7
 %


165


A comparison of Sierra Pacific's key operating results is as follows:

Electric Utility Margin
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Electric utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric operating revenue
 
$
232

 
$
225

 
$
7

3
 %
 
$
586

 
$
575

 
$
11

2
 %
Cost of fuel and energy
 
93

 
90

 
3

3

 
254

 
245

 
9

4

Electric utility margin
 
$
139

 
$
135

 
$
4

3

 
$
332

 
$
330

 
$
2

1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
GWh sold:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
696

 
737

 
(41
)
(6
)%
 
1,881

 
1,877

 
4

—
 %
Commercial
 
903

 
874

 
29

3

 
2,281

 
2,282

 
(1
)
—

Industrial
 
886

 
867

 
19

2

 
2,815

 
2,497

 
318

13

Other
 
4

 
4

 
—

—

 
12

 
12

 
—

—

Total fully bundled(1)
 
2,489

 
2,482

 
7

—

 
6,989


6,668


321

5

Distribution only service
 
416

 
375

 
41

11

 
1,212


1,124


88

8

Total retail
 
2,905

 
2,857

 
48

2

 
8,201

 
7,792

 
409

5

Wholesale
 
100

 
109

 
(9
)
(8
)
 
458

 
391

 
67

17

Total GWh sold
 
3,005

 
2,966

 
39

1

 
8,659

 
8,183

 
476

6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
305

 
300

 
5

2
 %
 
304

 
299

 
5

2
 %
Commercial
 
48

 
48

 
—

—

 
48

 
48

 
—

—

Total
 
353

 
348

 
5

1

 
352

 
347

 
5

1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average per MWh:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenue - fully bundled(1)
 
$
85.85

 
$
84.84

 
$
1.01

1
 %
 
$
76.73

 
$
80.02

 
$
(3.29
)
(4
)%
Revenue - wholesale
 
$
46.68

 
$
58.09

 
$
(11.41
)
(20
)%
 
$
50.03


$
49.92


$
0.11

—
 %
Total cost of energy(2)
 
$
33.33

 
$
36.76

 
$
(3.43
)
(9
)%
 
$
32.05

 
$
34.57

 
$
(2.52
)
(7
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Heating degree days
 
119

 
14

 
105

*
 
2,882

 
2,639

 
243

9
 %
Cooling degree days
 
891

 
1,043

 
(152
)
(15
)%
 
1,107

 
1,283

 
(176
)
(14
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sources of energy (GWh)(2)(3):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 
1,468

 
1,480

 
(12
)
(1
)%
 
3,714


3,615


99

3
 %
Coal
 
376

 
361

 
15

4

 
928

 
558

 
370

66

Renewables(4)
 
13

 
12

 
1

8

 
30


30


—

—

Total energy generated
 
1,857

 
1,853

 
4

—

 
4,672

 
4,203

 
469

11

Energy purchased
 
937

 
785

 
152

19

 
3,243

 
3,090

 
153

5

Total
 
2,794

 
2,638

 
156

6

 
7,915

 
7,293

 
622

9


*     Not meaningful
(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 - and 35 GWh of coal and - and 136 GWh of gas generated energy that is purchased at cost by related parties for the third quarter of 2019 and 2018, respectively. The average total cost of energy per MWh and sources of energy excludes - and 54 GWh of coal and - and 185 GWh of gas generated energy that is purchased at cost by related parties for the first nine months of 2019 and 2018, respectively.
(3)
GWh amounts are net of energy used by the related generating facilities.
(4)
Includes the Fort Churchill Solar Array which is under lease by Sierra Pacific.

166


Natural Gas Utility Margin
 
 
Third Quarter
 
First Nine Months
 
 
2019
 
2018
 
Change
 
2019
 
2018
 
Change
Natural gas utility margin (in millions):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas operating revenue
 
$
16

 
$
14

 
$
2

14
%
 
$
75

 
$
74

 
$
1

1
 %
Cost of natural gas purchased for resale
 
6

 
4

 
2

50

 
35

 
35

 
—

—

Natural gas utility margin
 
$
10

 
$
10

 
$
—

—

 
$
40

 
$
39

 
$
1

3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dths sold (in thousands):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
 
814

 
740

 
74

10
%
 
7,454

 
6,520

 
934

14
 %
Commercial
 
491

 
464

 
27

6

 
3,878

 
3,364

 
514

15

Industrial
 
278

 
267

 
11

4

 
1,357

 
1,364

 
(7
)
(1
)
Total retail
 
1,583

 
1,471

 
112

8

 
12,689

 
11,248

 
1,441

13

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average number of retail customers (in thousands)
 
171

 
167

 
4

2
%
 
170

 
167

 
3

2
 %
Average revenue per retail Dth sold
 
$
10.11

 
$
8.98

 
$
1.13

13
%
 
$
5.91

 
$
6.44

 
$
(0.53
)
(8
)%
Average cost of natural gas per retail Dth sold
 
$
3.79

 
$
2.69

 
$
1.10

41
%
 
$
2.76

 
$
3.11

 
$
(0.35
)
(11
)%
Heating degree days
 
119

 
14

 
105

*
 
2,882

 
2,639

 
243

9
 %

*     Not meaningful

Electric utility margin increased $4 million, or 3%, for the third quarter of 2019 compared to 2018 primarily due to higher transmission revenue of $5 million, partially offset by $2 million of lower residential volumes primarily from the impacts of weather.

Operations and maintenance decreased $7 million, or 13%, for the third quarter of 2019 compared to 2018 primarily due to lower political activity expenses and the impacts of adopting ASC 842, "Leases" ("ASC 842").

Depreciation and amortization increased $1 million, or 3%, for the third quarter of 2019 compared to 2018 primarily due to higher plant placed in service and the impacts of adopting ASC 842.

Other income (expense) is unfavorable $3 million, or 38%, for the third quarter of 2019 compared to 2018 primarily due to higher non-service pension expense and the impacts of adopting ASC 842.

Income tax expense decreased $1 million, or 8%, for the third quarter of 2019 compared to 2018. The effective tax rate was 21% in 2019 and 27% in 2018 and decreased due to lower nondeductible expenses.

Electric utility margin increased $2 million, or 1%, for the first nine months of 2019 compared to 2018 primarily due to:
•
$5 million of higher transmission revenue, and
•
$3 million of customer growth.
The increase in electric utility margin was offset by:
•
$6 million in lower retail rates due to the tax rate reduction rider effective April 2018.

Operations and maintenance decreased $10 million, or 7%, for the first nine months of 2019 compared to 2018 primarily due to lower political activity expenses and the impacts of adopting ASC 842, partially offset by higher generation plant costs.


167


Depreciation and amortization increased $5 million, or 6%, for the first nine months of 2019 compared to 2018 primarily due to higher plant placed in service and the impacts of adopting ASC 842.

Other income (expense) is unfavorable $8 million, or 38%, for the first nine months of 2019 compared to 2018 primarily due to higher non-service pension expense and the impacts of adopting ASC 842.

Income tax expense decreased $3 million, or 12%, for the first nine months of 2019 compared to 2018. The effective tax rate was 22% in 2019 and 25% in 2018 and decreased due to lower nondeductible expenses.

Liquidity and Capital Resources

As of September 30, 2019, Sierra Pacific's total net liquidity was as follows (in millions):

Cash and cash equivalents
 
$
64

Credit facility
 
250

Total net liquidity
 
$
314

Credit facility:
 
 
Maturity date
 
2022


Operating Activities

Net cash flows from operating activities for the nine-month periods ended September 30, 2019 and 2018 were $189 million and $208 million, respectively. The change was primarily due to an increase in fuel costs, higher inventory purchases, decreased collections of customer advances, lower collections from customers due to the unfavorable impacts of weather and the refunding of a credit deposit to a customer, partially offset by lower payments for operating costs, mainly due to lower political activity expenses, and lower contributions to the pension plan.

Investing Activities

Net cash flows from investing activities for the nine-month periods ended September 30, 2019 and 2018 were $(164) million and $(139) million, respectively. The change was due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the nine-month periods ended September 30, 2019 and 2018 were $(33) million and $(2) million, respectively. The change was due to higher payments to repurchase long-term debt and dividends paid to NV Energy, Inc. of $46 million, partially offset by higher proceeds from the re-offering of previously repurchased long-term debt.

Long-Term Debt

In April 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $30 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016C, due 2036; $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016D, due 2036; and $25 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016E, due 2036. Sierra Pacific purchased the Series 2016C, Series 2016D and Series 2016E bonds as required by the bond indentures.

In April 2019, Sierra Pacific entered into a re-offering of the following series of bonds: $30 million of its variable-rate tax-exempt Pollution Control Refunding Revenue Bonds, Series 2016B, due 2029; the Series 2016D bonds; the Series 2016E bonds; $75 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016F, due 2036; and $20 million of its variable-rate tax-exempt Water Facilities Refunding Revenue Bonds, Series 2016G, due 2036. The Series 2016B and Series 2016G bonds were offered at a fixed rate of 1.85%. The Series 2016D, Series 2016E and Series 2016F bonds were offered at a fixed rate of 2.05%. Sierra Pacific previously purchased the Series 2016B, Series 2016F and Series 2016G bonds on their date of issuance. Sierra Pacific holds the Series 2016C bonds and the bonds could be issued at a future date if required by future regulatory proceedings. Sierra Pacific used the net proceeds of the re-offering for general corporate purposes.

168



In June 2019, Sierra Pacific purchased the following series of bonds that were held by the public: $59 million of its fixed-rate tax-exempt Gas Facilities Refunding Revenue Bonds, Series 2016A, due 2031 and $20 million of its fixed-rate tax-exempt Humboldt County Pollution Control Refunding Revenue Bonds, Series 2016A, due 2029. Sierra Pacific holds these bonds and the bonds could be issued at a future date if required by future regulatory proceedings.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $1.6 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

Future Uses of Cash

Sierra Pacific has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customers' rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates. Expenditures for certain assets may ultimately include acquisition of existing assets.

Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
 
Nine-Month Periods
 
Annual
 
Ended September 30,
 
Forecast
 
2018
 
2019
 
2019
 
 
 
 
 
 
Distribution
$
101

 
$
117

 
$
169

Transmission system investment
3

 
10

 
16

Other
35

 
38

 
66

Total
$
139

 
$
165

 
$
251


Sierra Pacific's forecast capital expenditures include investments related to operating projects that consist of routine expenditures for transmission, distribution, generation and other infrastructure needed to serve existing and expected demand.

Contractual Obligations

As of September 30, 2019, there have been no material changes outside the normal course of business in contractual obligations from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2018.

Regulatory Matters

Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.


169


Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2018. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2018.


170


Item 3.
Quantitative and Qualitative Disclosures About Market Risk

For quantitative and qualitative disclosures about market risk affecting the Registrants, see Item 7A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2018. Refer to Note 8 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of September 30, 2019.

Item 4.
Controls and Procedures

At the end of the period covered by this Quarterly Report on Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended September 30, 2019 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.


171


PART II

Item 1.
Legal Proceedings

Not applicable.

Item 1A.
Risk Factors

There has been no material change to each Registrant's risk factors from those disclosed in Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, 2018.

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

Not applicable.

Item 3.
Defaults Upon Senior Securities

Not applicable.

Item 4.
Mine Safety Disclosures

Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.

Item 5.
Other Information

Not applicable.

Item 6.
Exhibits

The following is a list of exhibits filed as part of this Quarterly Report.


172


Exhibit No.
Description

BERKSHIRE HATHAWAY ENERGY
4.1
4.2
4.3
10.1
10.2
15.1
31.1
31.2
32.1
32.2

PACIFICORP
15.2
31.3
31.4
32.3
32.4

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
4.4
10.3
10.4
95

173



MIDAMERICAN ENERGY
15.3
31.5
31.6
32.5
32.6

Exhibit No.
Description

BERKSHIRE HATHAWAY ENERGY AND MIDAMERICAN ENERGY
4.5
4.6
10.5
10.6

MIDAMERICAN FUNDING
31.7
31.8
32.7
32.8

NEVADA POWER
15.4
31.9
31.10
32.9
32.10

BERKSHIRE HATHAWAY ENERGY AND NEVADA POWER
10.7


174


SIERRA PACIFIC
31.11
31.12
32.11
32.12

BERKSHIRE HATHAWAY ENERGY AND SIERRA PACIFIC
10.8

ALL REGISTRANTS
101
The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, 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.

175


SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
BERKSHIRE HATHAWAY ENERGY COMPANY
 
 
Date: November 1, 2019
/s/ Patrick J. Goodman
 
Patrick J. Goodman
 
Executive Vice President and Chief Financial Officer
 
(principal financial and accounting officer)
 
 
 
PACIFICORP
 
 
Date: November 1, 2019
/s/ Nikki L. Kobliha
 
Nikki L. Kobliha
 
Vice President, Chief Financial Officer and Treasurer
 
(principal financial and accounting officer)
 
 
 
MIDAMERICAN FUNDING, LLC
 
MIDAMERICAN ENERGY COMPANY
 
 
Date: November 1, 2019
/s/ Thomas B. Specketer
 
Thomas B. Specketer
 
Vice President and Controller
 
of MidAmerican Funding, LLC and
 
Vice President and Chief Financial Officer
 
of MidAmerican Energy Company
 
(principal financial and accounting officer)
 
 
 
NEVADA POWER COMPANY
 
 
Date: November 1, 2019
/s/ Michael E. Cole
 
Michael E. Cole
 
Vice President and Chief Financial Officer
 
(principal financial and accounting officer)
 
 
 
SIERRA PACIFIC POWER COMPANY
 
 
Date: November 1, 2019
/s/ Michael E. Cole
 
Michael E. Cole
 
Vice President and Chief Financial Officer
 
(principal financial and accounting officer)

176