Attached files
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 March 31, 2017
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) | ||||
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 and posted on their corporate Web sites, if any, every Interactive Data File required to be submitted and posted 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 and post 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 April 30, 2017, 77,356,144 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 April 30, 2017, 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 April 30, 2017.
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 April 30, 2017, 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 April 30, 2017, 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 April 30, 2017, 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 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 and its subsidiaries | |
Nevada Utilities | Nevada Power Company and Sierra Pacific Power Company | |
Registrants | Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy, Nevada Power and Sierra Pacific | |
Subsidiary Registrants | PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy, Nevada Power and Sierra Pacific | |
Northern Powergrid | Northern Powergrid Holdings Company | |
Northern Natural Gas | Northern Natural Gas Company | |
Kern River | Kern River Gas Transmission Company | |
AltaLink | BHE Canada Holdings Corporation | |
ALP | AltaLink, L.P. | |
BHE U.S. Transmission | BHE U.S. Transmission, LLC | |
HomeServices | HomeServices of America, Inc. and its subsidiaries | |
BHE Pipeline Group or Pipeline Companies | Consists of Northern Natural Gas and Kern River | |
BHE Transmission | Consists of AltaLink and BHE U.S. Transmission | |
BHE Renewables | Consists of BHE Renewables, LLC and CalEnergy Philippines | |
Utilities | PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company | |
Berkshire Hathaway | Berkshire Hathaway Inc. | |
Pinyon Pines Projects | 168-megawatt and 132-megawatt wind-powered generating facilities in California | |
Certain Industry Terms | ||
AESO | Alberta Electric System Operator | |
AFUDC | Allowance for Funds Used During Construction | |
AUC | Alberta Utilities Commission | |
CPUC | California Public Utilities Commission | |
Dth | Decatherms | |
EPA | United States Environmental Protection Agency | |
FERC | Federal Energy Regulatory Commission | |
GHG | Greenhouse Gases | |
GWh | Gigawatt Hours | |
GTA | General Tariff Application | |
IPUC | Idaho Public Utilities Commission | |
IUB | Iowa Utilities Board | |
kV | Kilovolt | |
ii
MW | Megawatts | |
MWh | Megawatt Hours | |
OPUC | Oregon Public Utility Commission | |
PUCN | Public Utilities Commission of Nevada | |
REC | Renewable Energy Credit | |
RPS | Renewable Portfolio Standards | |
SEC | United States Securities and Exchange Commission | |
SIP | State Implementation Plan | |
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; |
• | 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 storms, floods, fires, earthquakes, explosions, landslides, mining accidents, 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 and creditworthiness 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 the London Interbank Offered Rate, the base interest rate for the Registrants' credit facilities; |
iii
• | 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 and mortgage industries and regulations that could affect brokerage and mortgage transactions; |
• | 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 consolidated financial results of the respective Registrants; |
• | the ability to successfully integrate future acquired operations into a Registrant's business; 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 and its subsidiaries | ||
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
Des Moines, Iowa
We have reviewed the accompanying consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries (the "Company") as of March 31, 2017, and the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of the Company's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of Berkshire Hathaway Energy Company and subsidiaries as of December 31, 2016, 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
May 5, 2017
4
BERKSHIRE HATHAWAY ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,018 | $ | 721 | |||
Trade receivables, net | 1,618 | 1,751 | |||||
Inventories | 895 | 925 | |||||
Mortgage loans held for sale | 218 | 359 | |||||
Other current assets | 1,027 | 917 | |||||
Total current assets | 4,776 | 4,673 | |||||
Property, plant and equipment, net | 62,888 | 62,509 | |||||
Goodwill | 9,133 | 9,010 | |||||
Regulatory assets | 4,513 | 4,307 | |||||
Investments and restricted cash and investments | 4,119 | 3,945 | |||||
Other assets | 1,096 | 996 | |||||
Total assets | $ | 86,525 | $ | 85,440 | |||
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 | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 1,161 | $ | 1,317 | |||
Accrued interest | 479 | 454 | |||||
Accrued property, income and other taxes | 377 | 389 | |||||
Accrued employee expenses | 259 | 261 | |||||
Short-term debt | 2,011 | 1,869 | |||||
Current portion of long-term debt | 1,301 | 1,006 | |||||
Other current liabilities | 1,031 | 1,017 | |||||
Total current liabilities | 6,619 | 6,313 | |||||
Regulatory liabilities | 2,956 | 2,933 | |||||
BHE senior debt | 7,419 | 7,418 | |||||
BHE junior subordinated debentures | 744 | 944 | |||||
Subsidiary debt | 26,953 | 26,748 | |||||
Deferred income taxes | 13,986 | 13,879 | |||||
Other long-term liabilities | 2,736 | 2,742 | |||||
Total liabilities | 61,413 | 60,977 | |||||
Commitments and contingencies (Note 11) | |||||||
Equity: | |||||||
BHE shareholders' equity: | |||||||
Common stock - 115 shares authorized, no par value, 77 shares issued and outstanding | — | — | |||||
Additional paid-in capital | 6,381 | 6,390 | |||||
Retained earnings | 19,986 | 19,448 | |||||
Accumulated other comprehensive loss, net | (1,385 | ) | (1,511 | ) | |||
Total BHE shareholders' equity | 24,982 | 24,327 | |||||
Noncontrolling interests | 130 | 136 | |||||
Total equity | 25,112 | 24,463 | |||||
Total liabilities and equity | $ | 86,525 | $ | 85,440 | |||
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 | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
Energy | $ | 3,581 | $ | 3,550 | |||
Real estate | 585 | 491 | |||||
Total operating revenue | 4,166 | 4,041 | |||||
Operating costs and expenses: | |||||||
Energy: | |||||||
Cost of sales | 1,119 | 1,095 | |||||
Operating expense | 883 | 882 | |||||
Depreciation and amortization | 610 | 619 | |||||
Real estate | 583 | 492 | |||||
Total operating costs and expenses | 3,195 | 3,088 | |||||
Operating income | 971 | 953 | |||||
Other income (expense): | |||||||
Interest expense | (458 | ) | (473 | ) | |||
Capitalized interest | 10 | 11 | |||||
Allowance for equity funds | 17 | 15 | |||||
Interest and dividend income | 26 | 27 | |||||
Other, net | 25 | 10 | |||||
Total other income (expense) | (380 | ) | (410 | ) | |||
Income before income tax expense and equity income | 591 | 543 | |||||
Income tax expense | 52 | 74 | |||||
Equity income | 24 | 26 | |||||
Net income | 563 | 495 | |||||
Net income attributable to noncontrolling interests | 7 | 5 | |||||
Net income attributable to BHE shareholders | $ | 556 | $ | 490 | |||
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 | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Net income | $ | 563 | $ | 495 | |||
Other comprehensive income, net of tax: | |||||||
Unrecognized amounts on retirement benefits, net of tax of $(1) and $6 | 5 | 22 | |||||
Foreign currency translation adjustment | 87 | 67 | |||||
Unrealized gains on available-for-sale securities, net of tax of $18 and $22 | 38 | 33 | |||||
Unrealized losses on cash flow hedges, net of tax of $(2) and $(14) | (4 | ) | (23 | ) | |||
Total other comprehensive income, net of tax | 126 | 99 | |||||
Comprehensive income | 689 | 594 | |||||
Comprehensive income attributable to noncontrolling interests | 7 | 5 | |||||
Comprehensive income attributable to BHE shareholders | $ | 682 | $ | 589 | |||
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 | ||||||||||||||||||||||||||
Accumulated | ||||||||||||||||||||||||||
Additional | Other | |||||||||||||||||||||||||
Common | Paid-in | Retained | Comprehensive | Noncontrolling | Total | |||||||||||||||||||||
Shares | Stock | Capital | Earnings | Loss, Net | Interests | Equity | ||||||||||||||||||||
Balance, December 31, 2015 | 77 | $ | — | $ | 6,403 | $ | 16,906 | $ | (908 | ) | $ | 134 | $ | 22,535 | ||||||||||||
Net income | — | — | — | 490 | — | 4 | 494 | |||||||||||||||||||
Other comprehensive income | — | — | — | — | 99 | — | 99 | |||||||||||||||||||
Distributions | — | — | — | — | — | (4 | ) | (4 | ) | |||||||||||||||||
Balance, March 31, 2016 | 77 | $ | — | $ | 6,403 | $ | 17,396 | $ | (809 | ) | $ | 134 | $ | 23,124 | ||||||||||||
Balance, December 31, 2016 | 77 | $ | — | $ | 6,390 | $ | 19,448 | $ | (1,511 | ) | $ | 136 | $ | 24,463 | ||||||||||||
Net income | — | — | — | 556 | — | 4 | 560 | |||||||||||||||||||
Other comprehensive income | — | — | — | — | 126 | — | 126 | |||||||||||||||||||
Distributions | — | — | — | — | — | (7 | ) | (7 | ) | |||||||||||||||||
Common stock purchases | — | — | (1 | ) | (18 | ) | — | — | (19 | ) | ||||||||||||||||
Other equity transactions | — | — | (8 | ) | — | — | (3 | ) | (11 | ) | ||||||||||||||||
Balance, March 31, 2017 | 77 | $ | — | $ | 6,381 | $ | 19,986 | $ | (1,385 | ) | $ | 130 | $ | 25,112 | ||||||||||||
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)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 563 | $ | 495 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 622 | 626 | |||||
Allowance for equity funds | (17 | ) | (15 | ) | |||
Equity income, net of distributions | (13 | ) | (16 | ) | |||
Changes in regulatory assets and liabilities | 20 | 60 | |||||
Deferred income taxes and amortization of investment tax credits | 224 | 72 | |||||
Other, net | (5 | ) | 3 | ||||
Changes in other operating assets and liabilities, net of effects from acquisitions: | |||||||
Trade receivables and other assets | 288 | 219 | |||||
Derivative collateral, net | (23 | ) | (3 | ) | |||
Pension and other postretirement benefit plans | (17 | ) | (6 | ) | |||
Accrued property, income and other taxes | (187 | ) | (2 | ) | |||
Accounts payable and other liabilities | (37 | ) | (73 | ) | |||
Net cash flows from operating activities | 1,418 | 1,360 | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | (865 | ) | (1,027 | ) | |||
Acquisitions, net of cash acquired | (579 | ) | (13 | ) | |||
Increase in restricted cash and investments | 66 | 41 | |||||
Purchases of available-for-sale securities | (81 | ) | (34 | ) | |||
Proceeds from sales of available-for-sale securities | 83 | 61 | |||||
Equity method investments | (65 | ) | (273 | ) | |||
Other, net | (9 | ) | (39 | ) | |||
Net cash flows from investing activities | (1,450 | ) | (1,284 | ) | |||
Cash flows from financing activities: | |||||||
Repayments of BHE junior subordinated debentures | (200 | ) | (500 | ) | |||
Common stock purchases | (19 | ) | — | ||||
Proceeds from subsidiary debt | 844 | — | |||||
Repayments of subsidiary debt | (425 | ) | (310 | ) | |||
Net proceeds from short-term debt | 140 | 722 | |||||
Other, net | (12 | ) | (11 | ) | |||
Net cash flows from financing activities | 328 | (99 | ) | ||||
Effect of exchange rate changes | 1 | 1 | |||||
Net change in cash and cash equivalents | 297 | (22 | ) | ||||
Cash and cash equivalents at beginning of period | 721 | 1,108 | |||||
Cash and cash equivalents at end of period | $ | 1,018 | $ | 1,086 | |||
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 subsidiaries principally engaged in energy businesses (collectively with its subsidiaries, the "Company"). BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The Company's operations are organized and managed 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 ("AltaLink") (which primarily consists of AltaLink, L.P. ("ALP")) 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 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 selling power generated from solar, wind, geothermal and hydroelectric sources under long-term contracts, the second 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 March 31, 2017 and for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month period ended March 31, 2017 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, 2016 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 during the three-month period ended March 31, 2017.
(2) New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
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In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB 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 in 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The material impacts currently identified include recording the unrealized gains and losses on available-for-sale securities in the Consolidated Statements of Operations as opposed to other comprehensive income ("OCI"). For the three-month periods ended March 31, 2017 and 2016, these amounts, net of tax, were $38 million and $33 million, respectively.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. The Company is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. The Company currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when the Company has the right to invoice as it corresponds directly with the value to the customer of the Company’s performance to date. The Company's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by regulated energy, nonregulated energy and real estate, with further disaggregation of regulated energy by jurisdiction and real estate by line of business.
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(3) | Business Acquisitions |
The Company completed various acquisitions totaling $579 million, net of cash acquired, for the three-month period ended March 31, 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related primarily to development and construction costs for the 110-megawatt Alamo 6 solar-powered generation project, the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power and a residential real estate brokerage business. There were no other material assets acquired or liabilities assumed.
(4) | Property, Plant and Equipment, Net |
Property, plant and equipment, net consists of the following (in millions):
As of | |||||||||
Depreciable | March 31, | December 31, | |||||||
Life | 2017 | 2016 | |||||||
Regulated assets: | |||||||||
Utility generation, transmission and distribution systems | 5-80 years | $ | 71,308 | $ | 71,536 | ||||
Interstate natural gas pipeline assets | 3-80 years | 6,944 | 6,942 | ||||||
78,252 | 78,478 | ||||||||
Accumulated depreciation and amortization | (23,515 | ) | (23,603 | ) | |||||
Regulated assets, net | 54,737 | 54,875 | |||||||
Nonregulated assets: | |||||||||
Independent power plants | 5-30 years | 5,856 | 5,594 | ||||||
Other assets | 3-30 years | 1,081 | 1,002 | ||||||
6,937 | 6,596 | ||||||||
Accumulated depreciation and amortization | (1,136 | ) | (1,060 | ) | |||||
Nonregulated assets, net | 5,801 | 5,536 | |||||||
Net operating assets | 60,538 | 60,411 | |||||||
Construction work-in-progress | 2,350 | 2,098 | |||||||
Property, plant and equipment, net | $ | 62,888 | $ | 62,509 | |||||
Construction work-in-progress includes $2.1 billion as of March 31, 2017 and $1.8 billion as of December 31, 2016, related to the construction of regulated assets.
During the fourth quarter of 2016, MidAmerican Energy revised its electric and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce depreciation and amortization expense by $34 million annually, or $9 million for the three-month period ended March 31, 2017, based on depreciable plant balances at the time of the change.
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(5) | Investments and Restricted Cash and Investments |
Investments and restricted cash and investments consists of the following (in millions):
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
Investments: | |||||||
BYD Company Limited common stock | $ | 1,248 | $ | 1,185 | |||
Rabbi trusts | 420 | 403 | |||||
Other | 128 | 106 | |||||
Total investments | 1,796 | 1,694 | |||||
Equity method investments: | |||||||
BHE Renewables tax equity investments | 821 | 741 | |||||
Electric Transmission Texas, LLC | 698 | 672 | |||||
Bridger Coal Company | 146 | 165 | |||||
Other | 133 | 142 | |||||
Total equity method investments | 1,798 | 1,720 | |||||
Restricted cash and investments: | |||||||
Quad Cities Station nuclear decommissioning trust funds | 476 | 460 | |||||
Other | 214 | 282 | |||||
Total restricted cash and investments | 690 | 742 | |||||
Total investments and restricted cash and investments | $ | 4,284 | $ | 4,156 | |||
Reflected as: | |||||||
Other current assets | $ | 165 | $ | 211 | |||
Noncurrent assets | 4,119 | 3,945 | |||||
Total investments and restricted cash and investments | $ | 4,284 | $ | 4,156 | |||
Investments
BHE's investment in BYD Company Limited common stock is accounted for as an available-for-sale security with changes in fair value recognized in accumulated other comprehensive income (loss) ("AOCI"). The fair value of BHE's investment in BYD Company Limited common stock reflects a pre-tax unrealized gain of $1,016 million and $953 million as of March 31, 2017 and December 31, 2016, respectively.
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(6) | Recent Financing Transactions |
In April 2017, Kern River redeemed the remaining $175 million of its 4.893% Senior Notes due 2018 at a redemption price determined in accordance with the terms of the indenture.
In March 2017, BHE repaid at par value $200 million, plus accrued interest, of its junior subordinated debentures due December 2044.
In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.
In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.
(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 | |||||
Ended March 31, | |||||
2017 | 2016 | ||||
Federal statutory income tax rate | 35 | % | 35 | % | |
Income tax credits | (16 | ) | (14 | ) | |
State income tax, net of federal income tax benefit | (5 | ) | (4 | ) | |
Income tax effect of foreign income | (5 | ) | (5 | ) | |
Equity income | 1 | 2 | |||
Other, net | (1 | ) | — | ||
Effective income tax rate | 9 | % | 14 | % | |
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.
Berkshire Hathaway includes the Company in its United States federal income tax return. For the three-month periods ended March 31, 2017 and 2016, the Company did not receive or make any cash payments for income taxes from or to Berkshire Hathaway.
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(8) | Employee Benefit Plans |
Domestic Operations
Net periodic benefit cost for the domestic pension and other postretirement benefit plans included the following components (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Pension: | |||||||
Service cost | $ | 6 | $ | 8 | |||
Interest cost | 29 | 31 | |||||
Expected return on plan assets | (40 | ) | (40 | ) | |||
Net amortization | 7 | 11 | |||||
Net periodic benefit cost | $ | 2 | $ | 10 | |||
Other postretirement: | |||||||
Service cost | $ | 2 | $ | 3 | |||
Interest cost | 6 | 8 | |||||
Expected return on plan assets | (10 | ) | (11 | ) | |||
Net amortization | (3 | ) | (3 | ) | |||
Net periodic benefit credit | $ | (5 | ) | $ | (3 | ) | |
Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $15 million and $4 million, respectively, during 2017. As of March 31, 2017, $3 million and $4 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.
Foreign Operations
Net periodic benefit cost for the United Kingdom pension plan included the following components (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Service cost | $ | 6 | $ | 5 | |||
Interest cost | 14 | 19 | |||||
Expected return on plan assets | (24 | ) | (29 | ) | |||
Net amortization | 17 | 12 | |||||
Net periodic benefit cost | $ | 13 | $ | 7 | |||
Employer contributions to the United Kingdom pension plan are expected to be £39 million during 2017. As of March 31, 2017, £10 million, or $12 million, of contributions had been made to the United Kingdom pension plan.
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(9) | Risk Management and Hedging Activities |
The Company is exposed to the impact of market fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company is principally exposed to electricity, natural gas, coal and fuel oil commodity price risk primarily through BHE's ownership of PacifiCorp, MidAmerican Energy Company, Nevada Power Company and Sierra Pacific Power Company (the "Utilities") as they have an obligation to serve retail customer load in their regulated service territories. The Company also provides nonregulated retail electricity and natural gas services in competitive markets. The Utilities' 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, wholesale electricity that is purchased and sold, and natural gas supply for retail customers. 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, future debt issuances and mortgage commitments. Additionally, the Company is exposed to foreign currency exchange rate risk from its business operations and investments in Great Britain and Canada. The Company does not engage in a material amount of proprietary trading activities.
Each of the Company's business platforms 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, the Company uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. The Company 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, the Company may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, forward sale commitments, or mortgage interest rate lock commitments, to mitigate the Company's exposure to interest rate risk. The Company does not hedge all of its commodity price, interest rate and foreign currency exchange rate risks, thereby exposing the unhedged portion to changes in market prices.
There have been no significant changes in the Company's accounting policies related to derivatives. Refer to Note 10 for additional information on derivative contracts.
The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
Other | Other | Other | |||||||||||||||||
Current | Other | Current | Long-term | ||||||||||||||||
Assets | Assets | Liabilities | Liabilities | Total | |||||||||||||||
As of March 31, 2017 | |||||||||||||||||||
Not designated as hedging contracts: | |||||||||||||||||||
Commodity assets(1) | $ | 19 | $ | 90 | $ | 6 | $ | 1 | $ | 116 | |||||||||
Commodity liabilities(1) | (4 | ) | — | (55 | ) | (157 | ) | (216 | ) | ||||||||||
Interest rate assets | 13 | — | — | — | 13 | ||||||||||||||
Interest rate liabilities | — | — | (5 | ) | (6 | ) | (11 | ) | |||||||||||
Total | 28 | 90 | (54 | ) | (162 | ) | (98 | ) | |||||||||||
Designated as hedging contracts: | |||||||||||||||||||
Commodity assets | 1 | — | 3 | 2 | 6 | ||||||||||||||
Commodity liabilities | — | — | (11 | ) | (18 | ) | (29 | ) | |||||||||||
Interest rate assets | — | 8 | — | — | 8 | ||||||||||||||
Interest rate liabilities | — | — | (4 | ) | — | (4 | ) | ||||||||||||
Total | 1 | 8 | (12 | ) | (16 | ) | (19 | ) | |||||||||||
Total derivatives | 29 | 98 | (66 | ) | (178 | ) | (117 | ) | |||||||||||
Cash collateral receivable | — | — | 16 | 72 | 88 | ||||||||||||||
Total derivatives - net basis | $ | 29 | $ | 98 | $ | (50 | ) | $ | (106 | ) | $ | (29 | ) | ||||||
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Other | Other | Other | |||||||||||||||||
Current | Other | Current | Long-term | ||||||||||||||||
Assets | Assets | Liabilities | Liabilities | Total | |||||||||||||||
As of December 31, 2016 | |||||||||||||||||||
Not designated as hedging contracts: | |||||||||||||||||||
Commodity assets(1) | $ | 42 | $ | 86 | $ | 5 | $ | 2 | $ | 135 | |||||||||
Commodity liabilities(1) | (10 | ) | — | (46 | ) | (150 | ) | (206 | ) | ||||||||||
Interest rate assets | 15 | — | — | — | 15 | ||||||||||||||
Interest rate liabilities | — | — | (4 | ) | (6 | ) | (10 | ) | |||||||||||
Total | 47 | 86 | (45 | ) | (154 | ) | (66 | ) | |||||||||||
Designated as hedging contracts: | |||||||||||||||||||
Commodity assets | 1 | — | 2 | 3 | 6 | ||||||||||||||
Commodity liabilities | — | — | (14 | ) | (8 | ) | (22 | ) | |||||||||||
Interest rate assets | — | 8 | — | — | 8 | ||||||||||||||
Interest rate liabilities | — | — | (3 | ) | — | (3 | ) | ||||||||||||
Total | 1 | 8 | (15 | ) | (5 | ) | (11 | ) | |||||||||||
Total derivatives | 48 | 94 | (60 | ) | (159 | ) | (77 | ) | |||||||||||
Cash collateral receivable | — | — | 13 | 61 | 74 | ||||||||||||||
Total derivatives - net basis | $ | 48 | $ | 94 | $ | (47 | ) | $ | (98 | ) | $ | (3 | ) | ||||||
(1) | The Company's commodity derivatives not designated as hedging contracts are generally included in regulated rates, and as of March 31, 2017 and December 31, 2016, a net regulatory asset of $180 million and $148 million, respectively, was recorded related to the net derivative liability of $100 million and $71 million, respectively. The difference between the net regulatory asset and the net derivative liability relates primarily to a power purchase agreement derivative at BHE Renewables. |
Not Designated as Hedging Contracts
The following table reconciles the beginning and ending balances of the Company's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Beginning balance | $ | 148 | $ | 250 | |||
Changes in fair value recognized in net regulatory assets | 33 | 36 | |||||
Net gains reclassified to operating revenue | 13 | — | |||||
Net losses reclassified to cost of sales | (14 | ) | (33 | ) | |||
Ending balance | $ | 180 | $ | 253 | |||
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Designated as Hedging Contracts
The Company uses commodity derivative contracts accounted for as cash flow hedges to hedge electricity and natural gas commodity prices for delivery to nonregulated customers, spring operational sales, natural gas storage and other transactions. Certain commodity derivative contracts have settled and the fair value at the date of settlement remains in AOCI and is recognized in earnings when the forecasted transactions impact earnings. The following table reconciles the beginning and ending balances of the Company's accumulated other comprehensive (income) loss (pre-tax) and summarizes pre-tax gains and losses on commodity derivative contracts designated and qualifying as cash flow hedges recognized in OCI, as well as amounts reclassified to earnings (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Beginning balance | $ | 16 | $ | 46 | |||
Changes in fair value recognized in OCI | 16 | 48 | |||||
Net losses reclassified to cost of sales | (9 | ) | (22 | ) | |||
Ending balance | $ | 23 | $ | 72 | |||
Realized gains and losses on hedges and hedge ineffectiveness are recognized in income as operating revenue, cost of sales, operating expense or interest expense depending upon the nature of the item being hedged. For the three-month periods ended March 31, 2017 and 2016, hedge ineffectiveness was insignificant. As of March 31, 2017, the Company had cash flow hedges with expiration dates extending through June 2026 and $11 million of pre-tax unrealized losses are forecasted to be reclassified from AOCI into earnings over the next twelve months as contracts settle.
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
Unit of | March 31, | December 31, | |||||
Measure | 2017 | 2016 | |||||
Electricity purchases | Megawatt hours | 10 | 5 | ||||
Natural gas purchases | Decatherms | 305 | 271 | ||||
Fuel purchases | Gallons | 8 | 11 | ||||
Interest rate swaps | US$ | 814 | 714 | ||||
Mortgage sale commitments, net | US$ | (143 | ) | (309 | ) | ||
Credit Risk
The Utilities are 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 the Utilities' counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. Before entering into a transaction, the Utilities analyze the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, the Utilities enter into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, the Utilities exercise rights under these arrangements, including calling on the counterparty's credit support arrangement.
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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 creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2017, the applicable credit ratings from the three recognized credit rating agencies were investment grade.
The aggregate fair value of the Company's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $204 million and $190 million as of March 31, 2017 and December 31, 2016, respectively, for which the Company had posted collateral of $76 million and $69 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of March 31, 2017 and December 31, 2016, the Company would have been required to post $118 million and $110 million, respectively, of additional collateral. The Company's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation, or other factors.
(10) | 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. |
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The following table presents the Company's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements | ||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(1) | Total | ||||||||||||||||
As of March 31, 2017 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | 1 | $ | 26 | $ | 95 | $ | (16 | ) | $ | 106 | |||||||||
Interest rate derivatives | — | 9 | 12 | — | 21 | |||||||||||||||
Mortgage loans held for sale | — | 218 | — | — | 218 | |||||||||||||||
Money market mutual funds(2) | 828 | — | — | — | 828 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 163 | — | — | — | 163 | |||||||||||||||
International government obligations | — | 4 | — | — | 4 | |||||||||||||||
Corporate obligations | — | 35 | — | — | 35 | |||||||||||||||
Municipal obligations | — | 2 | — | — | 2 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 1 | — | — | 1 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 263 | — | — | — | 263 | |||||||||||||||
International companies | 1,255 | — | — | — | 1,255 | |||||||||||||||
Investment funds | 171 | — | — | — | 171 | |||||||||||||||
$ | 2,681 | $ | 295 | $ | 107 | $ | (16 | ) | $ | 3,067 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity derivatives | $ | (2 | ) | $ | (220 | ) | $ | (23 | ) | $ | 104 | $ | (141 | ) | ||||||
Interest rate derivatives | (1 | ) | (11 | ) | (3 | ) | — | (15 | ) | |||||||||||
$ | (3 | ) | $ | (231 | ) | $ | (26 | ) | $ | 104 | $ | (156 | ) | |||||||
As of December 31, 2016 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | 5 | $ | 49 | $ | 87 | $ | (22 | ) | $ | 119 | |||||||||
Interest rate derivatives | — | 16 | 7 | — | 23 | |||||||||||||||
Mortgage loans held for sale | — | 359 | — | — | 359 | |||||||||||||||
Money market mutual funds(2) | 586 | — | — | — | 586 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 161 | — | — | — | 161 | |||||||||||||||
International government obligations | — | 3 | — | — | 3 | |||||||||||||||
Corporate obligations | — | 36 | — | — | 36 | |||||||||||||||
Municipal obligations | — | 2 | — | — | 2 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 2 | — | — | 2 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 250 | — | — | — | 250 | |||||||||||||||
International companies | 1,190 | — | — | — | 1,190 | |||||||||||||||
Investment funds | 147 | — | — | — | 147 | |||||||||||||||
$ | 2,339 | $ | 467 | $ | 94 | $ | (22 | ) | $ | 2,878 | ||||||||||
Liabilities: | ||||||||||||||||||||
Commodity derivatives | $ | (2 | ) | $ | (199 | ) | $ | (27 | ) | $ | 96 | $ | (132 | ) | ||||||
Interest rate derivatives | (1 | ) | (11 | ) | (1 | ) | — | (13 | ) | |||||||||||
$ | (3 | ) | $ | (210 | ) | $ | (28 | ) | $ | 96 | $ | (145 | ) | |||||||
21
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $88 million and $74 million as of March 31, 2017 and December 31, 2016, 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. Refer to Note 9 for further discussion regarding the Company's risk management and hedging activities.
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 and are 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.
The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Periods | |||||||||||
Ended March 31, | |||||||||||
Interest | Auction | ||||||||||
Commodity | Rate | Rate | |||||||||
Derivatives | Derivatives | Securities | |||||||||
2017: | |||||||||||
Beginning balance | $ | 60 | $ | 6 | $ | — | |||||
Changes included in earnings | 12 | 27 | — | ||||||||
Changes in fair value recognized in OCI | (2 | ) | — | — | |||||||
Changes in fair value recognized in net regulatory assets | 1 | — | — | ||||||||
Purchases | — | (2 | ) | — | |||||||
Settlements | 1 | (22 | ) | — | |||||||
Ending balance | $ | 72 | $ | 9 | $ | — | |||||
22
Three-Month Periods | |||||||||||
Ended March 31, | |||||||||||
Interest | Auction | ||||||||||
Commodity | Rate | Rate | |||||||||
Derivatives | Derivatives | Securities | |||||||||
2016: | |||||||||||
Beginning balance | $ | 47 | $ | 4 | $ | 44 | |||||
Changes included in earnings | 19 | 25 | — | ||||||||
Changes in fair value recognized in OCI | (6 | ) | — | 4 | |||||||
Changes in fair value recognized in net regulatory assets | (6 | ) | — | — | |||||||
Redemptions | — | — | (22 | ) | |||||||
Settlements | 4 | (18 | ) | — | |||||||
Ending balance | $ | 58 | $ | 11 | $ | 26 | |||||
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 March 31, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying | Fair | Carrying | Fair | ||||||||||||
Value | Value | Value | Value | ||||||||||||
Long-term debt | $ | 36,417 | $ | 41,112 | $ | 36,116 | $ | 40,718 | |||||||
(11) | Commitments and Contingencies |
Construction Commitments
During the three-month period ended March 31, 2017, MidAmerican Energy entered into contracts totaling $138 million for the construction of wind-powered generating facilities in 2017.
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.
Environmental Laws and Regulations
The Company is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the Federal Energy Regulatory Commission ("FERC"). In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed the Klamath Hydroelectric Settlement Agreement ("KHSA").
23
Congress failed to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC") jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the license to the KRRC is effective.
Under the amended KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution towards facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would need to be provided by the KRRC or an entity other than PacifiCorp for removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.
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.
(12) | 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 taxes (in millions):
Unrealized | ||||||||||||||||||||
Unrecognized | Foreign | Gains on | Unrealized | AOCI | ||||||||||||||||
Amounts on | Currency | Available- | Gains (Losses) | Attributable | ||||||||||||||||
Retirement | Translation | For-Sale | on Cash | To BHE | ||||||||||||||||
Benefits | Adjustment | Securities | Flow Hedges | Shareholders, Net | ||||||||||||||||
Balance, December 31, 2015 | $ | (438 | ) | $ | (1,092 | ) | $ | 615 | $ | 7 | $ | (908 | ) | |||||||
Other comprehensive income (loss) | 22 | 67 | 33 | (23 | ) | 99 | ||||||||||||||
Balance, March 31, 2016 | $ | (416 | ) | $ | (1,025 | ) | $ | 648 | $ | (16 | ) | $ | (809 | ) | ||||||
Balance, December 31, 2016 | $ | (447 | ) | $ | (1,675 | ) | $ | 585 | $ | 26 | $ | (1,511 | ) | |||||||
Other comprehensive income (loss) | 5 | 87 | 38 | (4 | ) | 126 | ||||||||||||||
Balance, March 31, 2017 | $ | (442 | ) | $ | (1,588 | ) | $ | 623 | $ | 22 | $ | (1,385 | ) | |||||||
Reclassifications from AOCI to net income for the periods ended March 31, 2017 and 2016 were insignificant. For information regarding cash flow hedge reclassifications from AOCI to net income in their entirety, refer to Note 9. Additionally, refer to the "Foreign Operations" discussion in Note 8 for information about unrecognized amounts on retirement benefits reclassifications from AOCI that do not impact net income in their entirety.
24
(13) | Segment Information |
The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
PacifiCorp | $ | 1,281 | $ | 1,252 | |||
MidAmerican Funding | 696 | 626 | |||||
NV Energy | 584 | 615 | |||||
Northern Powergrid | 245 | 279 | |||||
BHE Pipeline Group | 315 | 315 | |||||
BHE Transmission | 166 | 158 | |||||
BHE Renewables | 144 | 139 | |||||
HomeServices | 585 | 491 | |||||
BHE and Other(1) | 150 | 166 | |||||
Total operating revenue | $ | 4,166 | $ | 4,041 | |||
Depreciation and amortization: | |||||||
PacifiCorp | $ | 196 | $ | 197 | |||
MidAmerican Funding | 117 | 110 | |||||
NV Energy | 104 | 104 | |||||
Northern Powergrid | 49 | 50 | |||||
BHE Pipeline Group | 30 | 53 | |||||
BHE Transmission | 54 | 50 | |||||
BHE Renewables | 61 | 56 | |||||
HomeServices | 12 | 6 | |||||
BHE and Other(1) | (1 | ) | — | ||||
Total depreciation and amortization | $ | 622 | $ | 626 | |||
25
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating income: | |||||||
PacifiCorp | $ | 345 | $ | 324 | |||
MidAmerican Funding | 107 | 100 | |||||
NV Energy | 98 | 89 | |||||
Northern Powergrid | 133 | 158 | |||||
BHE Pipeline Group | 208 | 192 | |||||
BHE Transmission | 77 | 76 | |||||
BHE Renewables | 15 | 24 | |||||
HomeServices | 2 | (1 | ) | ||||
BHE and Other(1) | (14 | ) | (9 | ) | |||
Total operating income | 971 | 953 | |||||
Interest expense | (458 | ) | (473 | ) | |||
Capitalized interest | 10 | 11 | |||||
Allowance for equity funds | 17 | 15 | |||||
Interest and dividend income | 26 | 27 | |||||
Other, net | 25 | 10 | |||||
Total income before income tax expense and equity income | $ | 591 | $ | 543 | |||
Interest expense: | |||||||
PacifiCorp | $ | 95 | $ | 95 | |||
MidAmerican Funding | 59 | 54 | |||||
NV Energy | 58 | 67 | |||||
Northern Powergrid | 31 | 36 | |||||
BHE Pipeline Group | 12 | 13 | |||||
BHE Transmission | 41 | 36 | |||||
BHE Renewables | 50 | 49 | |||||
HomeServices | 1 | 1 | |||||
BHE and Other(1) | 111 | 122 | |||||
Total interest expense | $ | 458 | $ | 473 | |||
Operating revenue by country: | |||||||
United States | $ | 3,747 | $ | 3,599 | |||
United Kingdom | 245 | 279 | |||||
Canada | 166 | 160 | |||||
Philippines and other | 8 | 3 | |||||
Total operating revenue by country | $ | 4,166 | $ | 4,041 | |||
Income before income tax expense and equity income by country: | |||||||
United States | $ | 423 | $ | 358 | |||
United Kingdom | 102 | 119 | |||||
Canada | 42 | 43 | |||||
Philippines and other | 24 | 23 | |||||
Total income before income tax expense and equity income by country | $ | 591 | $ | 543 | |||
26
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
Total assets: | |||||||
PacifiCorp | $ | 23,402 | $ | 23,563 | |||
MidAmerican Funding | 18,090 | 17,571 | |||||
NV Energy | 14,163 | 14,320 | |||||
Northern Powergrid | 6,637 | 6,433 | |||||
BHE Pipeline Group | 5,271 | 5,144 | |||||
BHE Transmission | 8,500 | 8,378 | |||||
BHE Renewables | 7,533 | 7,010 | |||||
HomeServices | 1,815 | 1,776 | |||||
BHE and Other(1) | 1,114 | 1,245 | |||||
Total assets | $ | 86,525 | $ | 85,440 | |||
(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 three-month period ended March 31, 2017 (in millions):
BHE | |||||||||||||||||||||||||||||||||||
MidAmerican | NV | Northern | Pipeline | BHE | BHE | Home- | |||||||||||||||||||||||||||||
PacifiCorp | Funding | Energy | Powergrid | Group | Transmission | Renewables | Services | Total | |||||||||||||||||||||||||||
December 31, 2016 | $ | 1,129 | $ | 2,102 | $ | 2,369 | $ | 930 | $ | 75 | $ | 1,470 | $ | 95 | $ | 840 | $ | 9,010 | |||||||||||||||||
Acquisitions | — | — | — | — | — | — | — | 100 | 100 | ||||||||||||||||||||||||||
Foreign currency translation | — | — | — | 12 | — | 13 | — | — | 25 | ||||||||||||||||||||||||||
Other | — | — | — | — | (2 | ) | — | — | — | (2 | ) | ||||||||||||||||||||||||
March 31, 2017 | $ | 1,129 | $ | 2,102 | $ | 2,369 | $ | 942 | $ | 73 | $ | 1,483 | $ | 95 | $ | 940 | $ | 9,133 | |||||||||||||||||
27
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 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 and managed 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 AltaLink and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these 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 selling power generated from solar, wind, geothermal and hydroelectric sources under long-term contracts, the second largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.
Results of Operations for the First Quarter of 2017 and 2016
Overview
Net income for the Company's reportable segments is summarized as follows (in millions):
First Quarter | ||||||||||||||
2017 | 2016 | Change | ||||||||||||
Net income attributable to BHE shareholders: | ||||||||||||||
PacifiCorp | $ | 179 | $ | 165 | $ | 14 | 8 | % | ||||||
MidAmerican Funding | 102 | 73 | 29 | 40 | ||||||||||
NV Energy | 33 | 21 | 12 | 57 | ||||||||||
Northern Powergrid | 82 | 98 | (16 | ) | (16 | ) | ||||||||
BHE Pipeline Group | 121 | 109 | 12 | 11 | ||||||||||
BHE Transmission | 60 | 48 | 12 | 25 | ||||||||||
BHE Renewables | 34 | 12 | 22 | * | ||||||||||
HomeServices | — | 1 | (1 | ) | (100 | ) | ||||||||
BHE and Other | (55 | ) | (37 | ) | (18 | ) | (49 | ) | ||||||
Total net income attributable to BHE shareholders | $ | 556 | $ | 490 | $ | 66 | 13 | |||||||
* Not meaningful
28
Net income attributable to BHE shareholders increased $66 million for the first quarter of 2017 compared to 2016 due to the following:
• | PacifiCorp's net income increased $14 million primarily due to higher margins of $15 million and lower operations and maintenance expenses of $15 million, partially offset by higher depreciation and amortization of $6 million and higher property taxes of $3 million. Margins increased due to higher retail customer volumes, lower average purchased electricity prices and higher wholesale electricity revenue from higher short-term prices, partially offset by higher purchased electricity volumes and lower average retail rates. Retail customer volumes increased by 2.8% mainly due to the impacts of weather on residential and commercial customers, primarily in Oregon and Washington, an increase in the average number of residential and commercial customers, primarily in Utah, and higher industrial usage, partially offset by lower residential usage in Utah and Oregon. |
• | MidAmerican Funding's net income increased $29 million due to higher electric margins of $24 million and higher recognized production tax credits of $21 million, partially offset by higher operations and maintenance expenses of $7 million, higher depreciation and amortization of $7 million and higher property and other taxes of $2 million. Electric margins reflect higher wholesale revenue from higher sales prices and volumes and higher retail customer volumes from industrial growth, partially offset by higher purchased electricity and coal costs. |
• | NV Energy's net income increased $12 million due to lower operating expenses of $11 million and lower interest expense of $9 million, primarily due to financing transactions and other maturities in 2016, partially offset by lower electric margins of $2 million. Operating expenses decreased due to lower planned maintenance and other generating costs and lower energy efficiency program costs, which are offset in electric margins. Excluding the impact of the lower energy efficiency program costs, electric margins increased primarily due to higher customer usage at Sierra Pacific from the impacts of weather. |
• | Northern Powergrid's net income decreased $16 million largely due to the stronger United States dollar of $13 million, higher depreciation of $7 million from additional assets placed in-service and lower distribution revenues of $2 million, partially offset by higher smart metering revenues of $6 million. Higher distribution tariff rates were more than offset by the recovery in 2016 of the December 2013 customer rebate, unfavorable movements in regulatory provisions and lower units distributed. |
• | BHE Pipeline Group's net income increased $12 million due to higher transportation revenues at Northern Natural Gas and a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River, partially offset by lower transportation revenues at Kern River. |
• | BHE Transmission's net income increased $12 million from higher earnings at AltaLink of $10 million and at BHE U.S. Transmission of $2 million. Earnings at AltaLink increased primarily due to additional assets placed in-service and the stronger Canadian dollar of $2 million. BHE U.S. Transmission's earnings improved primarily from higher equity earnings at Electric Transmission Texas, LLC from continued investment and additional assets placed in-service. |
• | BHE Renewables' net income increased $22 million primarily due to favorable earnings from tax equity investments reaching commercial operation, additional wind and solar capacity placed in-service, favorable changes in the valuations of interest rate swap derivatives and higher production at the Casecnan project due to higher rainfall, partially offset by an unfavorable change in the valuation of a power purchase agreement derivative. |
• | HomeServices' net income decreased $1 million primarily due to brokerage acquisition-related costs and a $2 million gain in 2016 from the acquisition of interests in equity method investments in the insurance business, partially offset by higher earnings at existing brokerage, mortgage, settlement services and franchise businesses. |
• | BHE and Other net loss increased $18 million primarily due to lower federal income tax credits recognized on a consolidated basis and higher United States income taxes on foreign earnings, partially offset by lower consolidated deferred state income tax expense due to changes in the tax status of certain subsidiaries and lower interest expense due to redemptions of junior subordinated debentures. |
29
Reportable Segment Results
Operating revenue and operating income for the Company's reportable segments are summarized as follows (in millions):
First Quarter | ||||||||||||||
2017 | 2016 | Change | ||||||||||||
Operating revenue: | ||||||||||||||
PacifiCorp | $ | 1,281 | $ | 1,252 | $ | 29 | 2 | % | ||||||
MidAmerican Funding | 696 | 626 | 70 | 11 | ||||||||||
NV Energy | 584 | 615 | (31 | ) | (5 | ) | ||||||||
Northern Powergrid | 245 | 279 | (34 | ) | (12 | ) | ||||||||
BHE Pipeline Group | 315 | 315 | — | — | ||||||||||
BHE Transmission | 166 | 158 | 8 | 5 | ||||||||||
BHE Renewables | 144 | 139 | 5 | 4 | ||||||||||
HomeServices | 585 | 491 | 94 | 19 | ||||||||||
BHE and Other | 150 | 166 | (16 | ) | (10 | ) | ||||||||
Total operating revenue | $ | 4,166 | $ | 4,041 | $ | 125 | 3 | |||||||
Operating income: | ||||||||||||||
PacifiCorp | $ | 345 | $ | 324 | $ | 21 | 6 | % | ||||||
MidAmerican Funding | 107 | 100 | 7 | 7 | ||||||||||
NV Energy | 98 | 89 | 9 | 10 | ||||||||||
Northern Powergrid | 133 | 158 | (25 | ) | (16 | ) | ||||||||
BHE Pipeline Group | 208 | 192 | 16 | 8 | ||||||||||
BHE Transmission | 77 | 76 | 1 | 1 | ||||||||||
BHE Renewables | 15 | 24 | (9 | ) | (38 | ) | ||||||||
HomeServices | 2 | (1 | ) | 3 | * | |||||||||
BHE and Other | (14 | ) | (9 | ) | (5 | ) | (56 | ) | ||||||
Total operating income | $ | 971 | $ | 953 | $ | 18 | 2 | |||||||
* Not meaningful
PacifiCorp
Operating revenue increased $29 million for 2017 compared to 2016 due to higher retail revenue of $17 million and higher wholesale and other revenue of $12 million. Retail revenue increased due to higher customer volumes, partially offset by lower demand side management revenue (offset in operations and maintenance expenses), primarily driven by the establishment of the Utah Sustainable Transportation and Energy Plan program, and lower average retail rates from unfavorable price mix. Wholesale and other revenue increased due to higher short-term wholesale electricity prices. Retail customer volumes increased 2.8% mainly due to the impacts of weather on residential and commercial customers, primarily in Oregon and Washington, an increase in the average number of residential and commercial customers, primarily in Utah, and higher industrial usage, partially offset by lower residential usage in Utah and Oregon.
Operating income increased $21 million for 2017 compared to 2016 due to higher margins of $15 million and lower operations and maintenance expenses of $15 million, partially offset by higher depreciation and amortization of $6 million and higher property taxes of $3 million. Margins increased due to higher retail customers volumes, lower average purchased electricity prices and higher wholesale electricity revenue, partially offset by higher purchased electricity volumes and unfavorable retail price mix. Operations and maintenance expenses decreased primarily due to a decrease in demand side management amortization expense (offset in retail revenue), a decrease in pension expense and lower plant maintenance, partially offset by an increase in injury and damage expenses, primarily as a result of a first quarter 2016 accrual for insurance proceeds.
30
MidAmerican Funding
Operating revenue increased $70 million for 2017 compared to 2016 due to higher natural gas operating revenue of $36 million and higher electric operating revenue of $34 million. Natural gas operating revenue increased due to a higher average per-unit cost of gas sold of $40 million (offset in cost of sales) and 6.9% higher wholesale volumes, partially offset by 5.4% lower retail sales volumes. Electric operating revenue increased due to higher wholesale and other revenue of $21 million and higher retail revenue of $13 million. Electric wholesale and other revenue increased due to higher wholesale volumes of $15 million and higher wholesale prices of $7 million. Electric retail revenue increased $7 million from higher recoveries through bill riders (substantially offset in cost of sales, operating expense and income tax expense) and $9 million from non-weather usage and rate factors, including higher industrial customer sales volumes, partially offset by $3 million from the impact of warmer winter temperatures in 2017. Electric retail customer volumes increased 1.6% from industrial growth, partially offset by the unfavorable impact of temperatures.
Operating income increased $7 million for 2017 compared to 2016 due to higher electric operating income of $10 million, partially offset by lower natural gas operating income of $3 million from the lower retail sales volumes. Electric operating income increased primarily due to the higher operating revenue, partially offset by higher energy costs of $10 million from higher purchased power costs and higher coal-fueled generation, higher operations and maintenance expenses of $7 million, higher depreciation and amortization of $7 million and higher property and other taxes of $2 million. Operations and maintenance expenses increased primarily due to higher operations costs recovered through bill riders and higher maintenance costs related to additional wind turbines. The increase in depreciation and amortization reflects wind generation and other plant placed in-service and an accrual for an Iowa regulatory revenue sharing arrangement, partially offset by a reduction of $9 million from lower depreciation rates implemented in December 2016.
NV Energy
Operating revenue decreased $31 million for 2017 compared to 2016 due to lower electric operating revenue of $19 million and lower natural gas operating revenue of $12 million. Electric operating revenue decreased due to lower retail revenue of $23 million, partially offset by higher wholesale and other revenue of $4 million. Retail revenue decreased primarily due to $10 million from lower retail rates primarily from energy costs that are passed on to customers through deferred energy adjustment mechanisms, $8 million of lower commercial and industrial revenue mainly from customers purchasing energy from alternative providers and becoming distribution only service customers and $6 million of lower energy efficiency rate revenue (offset in operating expenses). Electric retail customer volumes, including distribution only service customers, increased 0.5% compared to 2016. Natural gas operating revenue decreased primarily due to lower energy rates, partially offset by higher customer usage.
Operating income increased $9 million for 2017 compared to 2016 due to lower operating expenses of $11 million, partially offset by lower electric margins of $2 million. Electric margins were lower due to lower electric operating revenue, partially offset by lower energy costs of $16 million and higher customer usage at Sierra Pacific from the impacts of weather. Energy costs decreased due to lower net deferred power costs of $53 million, partially offset by a higher average cost of fuel for generation of $34 million and higher purchased power costs of $3 million. Operating expenses decreased due to lower planned maintenance and other generating costs and lower energy efficiency program costs (offset in electric operating revenue).
Northern Powergrid
Operating revenue decreased $34 million for 2017 compared to 2016 due to the stronger United States dollar of $38 million and lower distribution revenue of $2 million, partially offset by higher smart metering revenue of $6 million. Distribution revenue decreased due to the recovery in 2016 of the December 2013 customer rebate of $11 million, unfavorable movements in regulatory provisions of $6 million and lower units distributed of $5 million, partially offset by higher tariff rates of $20 million. Operating income decreased $25 million for 2017 compared to 2016 due to the stronger United States dollar of $21 million and higher depreciation of $7 million from additional assets placed in-service.
BHE Pipeline Group
Operating revenue was unchanged from 2016 as higher transportation revenues and higher gas sales of $4 million related to system balancing activities (largely offset in cost of sales) at Northern Natural Gas were offset by lower transportation revenues at Kern River. Operating income increased $16 million for 2017 compared to 2016 primarily due to a reduction in expenses and regulatory liabilities related to the impact of an alternative rate structure approved by the FERC at Kern River and the higher transportation revenues.
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BHE Transmission
Operating revenue increased $8 million for 2017 compared to 2016 primarily due to $13 million from additional assets placed in-service and recovery of higher costs and the stronger Canadian dollar of $6 million, partially offset by $14 million due to AltaLink's change to the flow through method of recognizing income tax expense, which also reduced income tax expense, that was approved by the AUC in May 2016. Operating income increased $1 million for 2017 compared to 2016 mainly due to the stronger Canadian dollar of $3 million.
BHE Renewables
Operating revenue increased $5 million for 2017 compared to 2016 due to additional wind and solar capacity placed in service of $13 million and higher production at the Casecnan project of $5 million due to higher rainfall, partially offset by an unfavorable change in the valuation of a power purchase agreement derivative of $9 million and lower wind generation of $2 million at the Pinyon Pines projects. Operating income decreased $9 million for 2017 compared to 2016 due to higher operating expense of $9 million and higher depreciation and amortization of $5 million, each primarily due to the additional wind and solar capacity placed in-service, partially offset by the increase in operating revenue. Operating expense also increased from the scope and timing of maintenance at certain geothermal plants. The change in depreciation and amortization reflects a reduction of $2 million from the extension of the useful life of certain wind-generating facilities from 25 years to 30 years effective January 2017.
HomeServices
Operating revenue increased $94 million for 2017 compared to 2016 due to a 12.0% increase in closed brokerage units and a 3.4% increase in average home sales prices. The increase in operating revenue was due to an increase from existing businesses totaling $42 million and an increase in acquired businesses totaling $52 million. The increase in existing businesses reflects a 4.4% increase in close brokerage units. Operating income increased $3 million for 2017 compared to 2016 due to higher earnings at existing franchise, settlement services and insurance businesses, partially offset by net losses from acquired brokerage businesses. Operating income at existing brokerage businesses was relatively unchanged as the increase in closed units was largely offset by a higher commission expenses and higher operating expenses.
BHE and Other
Operating revenue decreased $16 million for 2017 compared to 2016 due to lower electricity and natural gas volumes and electricity prices, partially offset by higher natural gas prices, at MidAmerican Energy Services, LLC. Operating loss increased $5 million for 2017 compared to 2016 due to higher other operating costs, partially offset by higher margins of $3 million at MidAmerican Energy Services, LLC.
Consolidated Other Income and Expense Items
Interest Expense
Interest expense is summarized as follows (in millions):
First Quarter | ||||||||||||||
2017 | 2016 | Change | ||||||||||||
Subsidiary debt | $ | 346 | $ | 349 | $ | (3 | ) | (1 | )% | |||||
BHE senior debt and other | 105 | 102 | 3 | 3 | ||||||||||
BHE junior subordinated debentures | 7 | 22 | (15 | ) | (68 | ) | ||||||||
Total interest expense | $ | 458 | $ | 473 | $ | (15 | ) | (3 | ) | |||||
Interest expense decreased $15 million for 2017 compared to 2016 due to $2.0 billion of BHE junior subordinated debenture repayments in 2016, scheduled maturities and principal payments, early redemptions and the impact of foreign currency exchange rate movements of $4 million, partially offset by debt issuances at MidAmerican Funding, AltaLink and BHE Renewables.
Other, net
Other, net increased $15 million for 2017 compared to 2016 primarily due to higher investment returns and favorable changes in the valuations of interest rate swap derivatives of $6 million.
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Income Tax Expense
Income tax expense decreased $22 million for 2017 compared to 2016 and the effective tax rate was 9% for 2017 and 14% for 2016. The effective tax rate decreased due to higher production tax credits recognized of $19 million, favorable impacts of rate making of $15 million and lower consolidated deferred state income tax expense due to changes in the tax status of certain subsidiaries, partially offset by higher income tax expense on higher pre-tax income and higher United States income taxes on 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 2017 were $87 million, or $19 million higher than 2016, while production tax credits earned in 2017 were $141 million, or $41 million higher than 2016. The difference between production tax credits recognized and earned of $54 million as of March 31, 2017, primarily at MidAmerican Energy, will be reflected in earnings over the remainder of 2017.
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 17 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, 2016 for further discussion regarding the limitation of distributions from BHE's subsidiaries.
As of March 31, 2017, the Company's total net liquidity was as follows (in millions):
MidAmerican | NV | Northern | |||||||||||||||||||||||||||||
BHE | PacifiCorp | Funding | Energy | Powergrid | AltaLink | Other | Total | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 79 | $ | 15 | $ | 490 | $ | 86 | $ | 61 | $ | 7 | $ | 280 | $ | 1,018 | |||||||||||||||
Credit facilities | 2,000 | 1,000 | 609 | 650 | 188 | 995 | 915 | 6,357 | |||||||||||||||||||||||
Less: | |||||||||||||||||||||||||||||||
Short-term debt | (1,351 | ) | (8 | ) | — | (6 | ) | — | (262 | ) | (384 | ) | (2,011 | ) | |||||||||||||||||
Tax-exempt bond support and letters of credit | (7 | ) | (92 | ) | (220 | ) | (80 | ) | — | (8 | ) | — | (407 | ) | |||||||||||||||||
Net credit facilities | 642 | 900 | 389 | 564 | 188 | 725 | 531 | 3,939 | |||||||||||||||||||||||
Total net liquidity | $ | 721 | $ | 915 | $ | 879 | $ | 650 | $ | 249 | $ | 732 | $ | 811 | $ | 4,957 | |||||||||||||||
Credit facilities: | |||||||||||||||||||||||||||||||
Maturity dates | 2019 | 2018, 2019 | 2017, 2018 | 2018 | 2020 | 2017, 2018, 2021 | 2017, 2018 | ||||||||||||||||||||||||
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016 were $1.418 billion and $1.360 billion, respectively. The change was primarily due to lower cash payments for interest, improved operating results and other changes in working capital.
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In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% in 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at full value through 2016, at 80% of value in 2017, at 60% of value in 2018, and 40% of value in 2019. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, the Company's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019, production tax credits through 2029 and investment tax credits earned on qualifying wind and solar projects through 2021, respectively.
The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016 were $(1.5) billion and $(1.3) billion, respectively. The change was primarily due to higher cash paid for acquisitions, partially offset by lower funding of tax equity investments and lower capital expenditures of $162 million.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2017 was $328 million. Sources of cash totaled $984 million and consisted of $844 million of proceeds from subsidiary debt issuances and $140 million of net proceeds from short-term debt. Uses of cash totaled $656 million and consisted mainly of repayments of subsidiary debt totaling $425 million and repayments of BHE junior subordinated debentures of $200 million.
For a discussion of recent financing transactions, refer to Note 6 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
Net cash flows from financing activities for the three-month period ended March 31, 2016 was $(99) million. Uses of cash totaled $821 million and consisted mainly of repayments of BHE junior subordinated debentures of $500 million and repayments of subsidiary debt totaling $310 million. Sources of cash totaled $722 million related to net proceeds from short-term debt.
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 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, 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. Expenditures for certain assets may ultimately include acquisitions of existing assets.
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The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Three-Month Periods | Annual | ||||||||||
Ended March 31, | Forecast | ||||||||||
2016 | 2017 | 2017 | |||||||||
Capital expenditures by business: | |||||||||||
PacifiCorp | $ | 201 | $ | 178 | $ | 837 | |||||
MidAmerican Funding | 332 | 238 | 1,783 | ||||||||
NV Energy | 146 | 99 | 427 | ||||||||
Northern Powergrid | 155 | 151 | 629 | ||||||||
BHE Pipeline Group | 30 | 38 | 366 | ||||||||
BHE Transmission | 112 | 85 | 329 | ||||||||
BHE Renewables | 45 | 71 | 230 | ||||||||
HomeServices | 4 | 5 | 32 | ||||||||
BHE and Other | 2 | — | 23 | ||||||||
Total | $ | 1,027 | $ | 865 | $ | 4,656 | |||||
Capital expenditures by type: | |||||||||||
Wind generation | $ | 105 | $ | 49 | $ | 1,063 | |||||
Solar generation | 5 | 51 | 148 | ||||||||
Electric transmission | 115 | 92 | 352 | ||||||||
Environmental | 16 | — | 130 | ||||||||
Other growth | 92 | 136 | 552 | ||||||||
Operating | 694 | 537 | 2,411 | ||||||||
Total | $ | 1,027 | $ | 865 | $ | 4,656 | |||||
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 $29 million and $69 million for the three-month periods ended March 31, 2017 and 2016, respectively. MidAmerican Energy anticipates costs for wind-powered generating facilities will total an additional $702 million for 2017. 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 wind-powered generating facilities expected to be placed in-service in 2017 through 2019. The ratemaking principles establish a cost cap of $3.6 billion, including AFUDC, and 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. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns if they are above the weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. Each of these projects is expected to qualify for 100% of production tax credits currently available. |
◦ | Repowering certain existing wind-powered generating facilities at PacifiCorp and MidAmerican Energy and the construction of new wind-powered generating facilities at PacifiCorp totaling $31 million for the three-month period ended March 31, 2017. PacifiCorp and MidAmerican Energy anticipate costs for these activities will total an additional $299 million for 2017. The repowering projects entail the replacement of significant components of older turbines. The energy production from the repowered and the new facilities is expected to qualify for 100% of the federal renewable electricity production tax credits available for ten years once the equipment is placed in-service. |
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• | Solar generation includes the construction of the community solar gardens project in Minnesota at BHE Renewables totaling $36 million for the three-month period ended March 31, 2017. BHE Renewables anticipates costs for the community solar gardens project will total an additional $153 million for 2017. |
• | Electric transmission includes PacifiCorp's costs associated with main grid reinforcement and the Energy Gateway Transmission Expansion Program, MidAmerican Energy's MVPs approved by the Midcontinent Independent System Operator, Inc. for the construction of approximately 250 miles of 345 kV transmission line located in Iowa and Illinois and AltaLink's directly assigned projects from the AESO. |
• | Environmental includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities at the Utilities, including installation or upgrade of selective catalytic reduction control systems and low nitrogen oxide burners to reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systems and mercury emissions control systems, as well as expenditures for the management of coal combustion residuals. |
• | Other growth includes projects to deliver power and services to new markets, new customer connections and enhancements to existing customer connections. |
• | Operating includes ongoing distribution systems infrastructure needed at the Utilities and Northern Powergrid and investments in routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand. |
Acquisitions
The Company completed various acquisitions totaling $579 million for the three-month period ended March 31, 2017. The purchase price for each acquisition was allocated to the assets acquired and liabilities assumed, which related primarily to development and construction costs for the 110-megawatt Alamo 6 solar-powered generation project, the remaining 25% interest in the Silverhawk natural gas-fueled generation facility at Nevada Power and a residential real estate brokerage business. There were no other material assets acquired or liabilities assumed.
Integrated Resource Plan
In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission, and new wind renewable resources will require an estimated $3.5 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in BHE's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.
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 $170 million in 2015, $584 million in 2016 and $85 million through March 31, 2017, and expects to contribute $120 million for the remainder of 2017 and $201 million in 2018 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project.
Contractual Obligations
As of March 31, 2017, 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, 2016 other than the recent financing transactions and the renewable tax equity investments previously discussed.
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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 will go into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits 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 in the Northern District of Illinois against the Illinois Power Agency alleging that the state’s zero emission credit program violates certain provisions of the U.S. Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC’s energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon has intervened in both suits and has filed motions to dismiss in both matters. These motions are currently pending.
On January 9, 2017 the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Price Offer 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 timing of the FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
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, 2016, and new regulatory matters occurring in 2017.
PacifiCorp
Utah
In March 2017, PacifiCorp filed its annual Energy Balancing Account ("EBA") with the UPSC seeking approval to refund to customers $7 million in deferred net power costs for the period January 1, 2016 through December 31, 2016, reflecting the difference between base and actual net power costs in the 2016 deferral period. In April 2017, PacifiCorp revised its recommendation and requested approval to refund an additional $7 million to customers resulting in an interim rate reduction of $14 million. The rate change is effective on an interim basis May 1, 2017.
In March 2017, PacifiCorp filed its annual REC balancing account application with the UPSC seeking to refund to customers $1 million for the period January 1, 2016 through December 31, 2016 for the difference in base and actual renewable energy credits. The rate change will be effective on an interim basis June 1, 2017.
As a result of the Utah Sustainable Transportation and Energy Plan legislation that was signed into law in March 2016, PacifiCorp filed an application in September 2016 seeking approval of phase 1 of a proposed five-year pilot program with an annual budget of $10 million authorized under the legislation. The UPSC issued an order approving phase one of the five-year pilot program in December 2016. Phases two and three of PacifiCorp's application for approval of programs authorized by the legislation are ongoing at the UPSC. A hearing was held April 18, 2017 in Phase two of the application which includes projects under the Clean Coal Technology Program and an incentive for commercial line extensions. Phase three addresses the electric vehicle incentive program, including a residential time of use rate pilot.
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In November 2016, PacifiCorp filed cost of service analyses, as ordered by the UPSC, to quantify the cost shifting due to net metering. The UPSC ordered the analyses to comply with a 2014 law requiring the examination of whether the costs of net metering exceed the benefits to PacifiCorp and other customers. The filing includes a proposal for a new rate schedule for residential customer generators with a three-part rate based on the cost of serving this class of customer, which will mitigate future cost shifting. PacifiCorp proposed that the new rate schedule only apply to new net metering customers that submit applications after December 9, 2016. On December 9, 2016, PacifiCorp requested that the effective date for the start of a transitional tariff be suspended while it works with stakeholders on a collaborative process to resolve net metering rate design issues. The filing also requests an increase in the application fees for net metering. In February 2017, the UPSC ruled on motions to dismiss and requests for a show cause order for a general rate case filed by various parties to the docket and denied the motions. The UPSC has set a procedural schedule with hearings to occur in August 2017.
Oregon
In March 2017, PacifiCorp submitted its filing for the annual Transitional Adjustment Mechanism ("TAM") filing in Oregon requesting an annual increase of $18 million, or an average price increase of 1.5%, based on forecasted net power costs and loads for calendar year 2018. Consistent with Oregon Senate Bill 1547, the filing includes an update of the impact of expiring production tax credits, which accounts for $6 million of the total rate adjustment. The filing will be updated for changes in contracts and market conditions in July and November 2017, before final rates become effective in January 2018.
Wyoming
In April 2017, PacifiCorp filed its annual Energy Cost Adjustment Mechanism ("ECAM") and REC and Sulfur Dioxide Revenue Adjustment Mechanism ("RRA") applications with the WPSC. The ECAM filing requests approval to refund to customers $5 million in deferred net power costs for the period January 1, 2016 through December 31, 2016, and the RRA application requests approval to refund to customers $1 million. If approved by the WPSC, the ECAM and RRA rates will be effective June 15, 2017 on an interim basis until a final order is issued by the WPSC.
Idaho
In January 2017, a $1 million, or 0.4%, decrease in base rates became effective as a result of a filing made with the IPUC to update net power costs in base rates in compliance with a prior rate plan stipulation.
In March 2017, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $8 million for deferred costs in 2016. 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. If approved by the IPUC, the ECAM rates would be effective June 1, 2017.
California
In April 2017, PacifiCorp filed an application with the CPUC for an overall rate increase of 1.3% to recover $3 million of costs recorded in the catastrophic events memorandum account over a two-year period effective April 1, 2018, The catastrophic events memorandum account includes costs for implementing drought-related fire hazard mitigation measures and storm damage and recovery efforts associated with the December 2016 and January 2017 winter storms.
NV Energy (Nevada Power and Sierra Pacific)
Regulatory Rate Reviews
In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving most, but not all, issues in the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six MWs of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes.
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In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.
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 applicants' 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 May 2015, Wynn Las Vegas, LLC ("Wynn"), filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In December 2015, the PUCN granted the application subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms. In December 2015, Wynn filed a petition for reconsideration. In January 2016, the PUCN granted reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. In September 2016, Wynn paid impact fees totaling $15 million. In October 2016, Wynn became a distribution only service customer and started procuring energy from another energy supplier. In April 2017, Wynn filed a motion with the PUCN seeking relief from the January 2016 order and requested the PUCN adopt an alternative impact fee and revise on-going charges associated with retirement of assets and high cost renewable contracts.
In September 2016, Switch, Ltd. ("Switch"), a customer of the Nevada Utilities, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power and Sierra Pacific. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In March 2017, Switch provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.
In November 2016, Caesars Enterprise Service ("Caesars"), a customer of the Nevada Utilities, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power and Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.
Net Metering
Nevada enacted Senate Bill 374 ("SB 374") on June 5, 2015. The legislation required the Nevada Utilities to prepare cost-of-service studies and propose new rules and rates for customers who install distributed, renewable generating resources. In July 2015, the Nevada Utilities made filings in compliance with SB 374 and the PUCN issued final orders December 23, 2015.
The final orders issued by the PUCN establish separate rate classes for customers who install distributed, renewable generating facilities. The establishment of separate rate classes recognizes the unique characteristics, costs and services received by these partial requirements customers. The PUCN also established new, cost-based rates or prices for these new customer classes, including increases in the basic service charge and related reductions in energy charges. Finally, the PUCN established a separate value for compensating customers who produce and deliver excess energy to the Nevada Utilities. The valuation will consider eleven factors, including alternatives available to the Nevada Utilities. The PUCN established a gradual, five-step process for transition over four years to the new, cost-based rates.
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In January 2016, the PUCN denied requests to stay the order issued December 23, 2015. The PUCN also voted to reopen the evidentiary proceeding to address the application of new net metering rules for customers who applied for net metering service before the issuance of the final order. In February 2016, the PUCN affirmed most of the provisions of the December 23, 2015 order and adopted a twelve-year transition plan for changing rates for net metering customers to cost-based rates for utility services and value-based pricing for excess energy. Subsequently, two solar industry interest groups filed petitions for judicial review of the PUCN order issued in February 2016. The petitions request that the court either modify the PUCN order or direct the PUCN to modify its decision in a manner that would maintain rates and rules of service applicable to net metering as existed prior to the December 23, 2015 order of the PUCN. Two of the three petitions filed by the solar industry interest groups have been dismissed. In September 2016, the state district court issued an order in the third petition. The court concluded that the PUCN failed to provide existing net metering customers adequate legal notice of the proceeding. The court affirmed the PUCN's decision to establish new net energy metering rates and apply those to new net metering customers. The Nevada state district court decision was appealed to the Nevada Supreme Court.
In July 2016, the Nevada Utilities filed applications with the PUCN to revert back to the original net metering rates for a period of twenty years for customers who installed or had an active application for distributed, renewable generating facilities as of December 31, 2015. In September 2016, the PUCN issued an order accepting the stipulation and approved the applications as modified by the stipulation. In December 2016, as a part of Sierra Pacific's regulatory rate review, the PUCN issued an order establishing an additional six MWs of net metering under the grandfathered rates in the Sierra Pacific service territory; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. As mentioned above, Sierra Pacific has filed a petition for reconsideration relating to the additional six MWs of net metering.
In March 2017, the Nevada Utilities filed a joint application with several solar companies to extend the period for eligible customers to opt into the grandfathered net metering rates. The PUCN voted to approve the application and give qualifying customers until July 2017 to make this election.
Energy Choice Initiative
In November 2016, a majority of Nevada voters supported a ballot measure to amend Article 1 of the Nevada Constitution. If approved again in the general election of 2018, the proposed constitutional amendment would require the Nevada Legislature to create, on or before July 2023, an open and competitive retail electric market that includes provisions to reduce costs to customers, protect against service disconnections and unfair practices, and prohibit the granting of monopolies and exclusive franchises for the generation of electricity. The outcome of any customer choice initiative could have broad implications to the Nevada Utilities. The Governor issued an executive order establishing the Governor’s Committee on Energy Choice in which the Nevada Utilities have representation. The Nevada Utilities are engaged in the initiative process and with the Governor's Committee on Energy Choice but cannot assess or predict the outcome of the potential constitutional amendment or the financial impact, if any, at this time. The uncertainty created by the ballot initiative complicates both the short-term allocation of resources and long-term resource planning for the Nevada Utilities, including the ability to forecast load growth and the timing of resource additions. This uncertainty in planning is evidenced by a recent decision the PUCN issued denying Nevada Power’s proposed purchase of the South Point Energy Center, citing the unknown outcomes of the energy choice initiative as one of the factors considered in their decision.
ALP
General Tariff Applications
In November 2014, ALP filed a GTA requesting the AUC approve revenue requirements of C$811 million for 2015 and C$1.0 billion for 2016, primarily due to continued investment in capital projects as directed by the AESO. ALP amended the GTA in June 2015 and in October 2015. In May 2016, the AUC issued its decision pertaining to the 2015-2016 GTA. ALP filed its 2015-2016 GTA compliance filing in July 2016 to comply with the AUC's decision and to provide customers with tariff relief through: (i) the discontinuance of construction work-in-progress ("CWIP") in rate base and the return to AFUDC accounting effective January 1, 2015, and (ii) the refund of previously collected CWIP in rate base as part of ALP's transmission tariffs during 2011-2014 less related returns. In October 2016, ALP amended its 2015-2016 GTA compliance filing made in July 2016 to reflect the impacts of the generic cost of capital decision issued in October 2016.
In December 2016, the AUC issued its decision with respect to ALP’s 2015-2016 GTA compliance filing made in July 2016, as amended. The AUC found that ALP has either complied with or the AUC has otherwise relieved ALP from its compliance with all its directions in its decision except for Directive 47, which dealt with the determination of the refund for previously collected CWIP-in-rate base and all related amounts. In January 2017, ALP filed its second compliance filing as directed by the AUC and requested a technical conference to explain the technical aspects of the filing.
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In March 2017, the technical conference was held, and all key aspects of ALP’s approach and methodologies used in its second compliance filing to comply with AUC directives were reviewed and discussed. In April 2017, ALP filed with the AUC an amendment to its second compliance filing asking to remove C$7 million of recapitalized AFUDC associated with canceled projects that were not capitalized to rate base, and to increase the amount of income tax refund related to previously collected CWIP-in-rate base by C$4 million. As a result of this amendment, ALP’s forecast transmission tariffs were reduced from C$679 million to C$675 million for 2016, and remained unchanged at C$599 million for 2015, compared to the January 2017 second compliance filing, as amended.
Once the AUC approves ALP’s second compliance filing, as amended, final transmission tariff rates for the 2015 and 2016 test years will be set, subject to further adjustment through the deferral account reconciliation process.
ALP updated and refiled its 2017-2018 GTA in August 2016 to reflect the findings and conclusions of the AUC in its 2015-2016 GTA decision issued in May 2016. In October 2016, ALP amended its 2017-2018 GTA to reflect the impacts of the generic cost of capital decision issued in October 2016 and other updates and revisions. The amendment requests the AUC to approve ALP's revenue requirement of C$891 million for 2017 and C$919 million for 2018. In November 2016, the AUC approved the 2017 interim refundable transmission tariff at C$70 million per month effective January 2017. In December 2016, the AUC approved ALP's request to enter into a negotiated settlement process. In January 2017, the parties successfully reached a negotiated settlement on all aspects of ALP’s 2017-2018 GTA and in February 2017, ALP filed with the AUC the 2017-2018 negotiated settlement application for approval. The application consists of negotiated reductions of C$16 million of operating expenses and C$40 million of transmission maintenance and information technology capital expenditures over the two years, as well as an increase to miscellaneous revenue of C$3 million. These reductions resulted in a C$24 million, or 1.3%, net decrease to the two-year total revenue requirement applied for in ALP’s 2017-2018 GTA amendment filed in October 2016. In addition, ALP proposed to provide significant tariff relief through the refund of previously collected accumulated depreciation surplus of C$130 million (C$125 million net of other related impacts). The negotiated settlement agreement also provides for additional potential reductions over the two years through a 50/50 cost savings sharing mechanism.
Deferral Account Reconciliation Application
In April 2017, ALP filed its application with the AUC with respect to ALP’s 2014 projects and deferral accounts and specific 2015 projects. The application includes approximately C$2.0 billion in net capital additions.
Environmental Laws and Regulations
Each Registrant is subject to federal, state, local and foreign laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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 the EPA and various 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. Refer to "Liquidity and Capital Resources" of each respective Registrant in Part I, Item 2 of this Form 10-Q for discussion of each Registrant's forecast environmental-related capital expenditures. 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, 2016, and new environmental matters occurring in 2017.
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.
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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.
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 relating to PacifiCorp and Arizona Public Service Company as they work with state and federal agencies on an alternate compliance approach for Cholla Unit 4. In January 2015, permit applications and studies were submitted to amend the Cholla Title V permit, and subsequently the Arizona SIP to convert Cholla Unit 4 to a natural gas-fueled unit in 2025. The Arizona Department of Environmental Quality prepared a draft permit and a revision to the Arizona regional haze SIP, held two public hearings in July 2015 and, after considering the comments received during the public comment period that closed on July 14, 2015, submitted the final proposals to the EPA for review, public comment and final action. The EPA issued its proposed action to approve amendments to the Arizona regional haze SIP, which were published in the Federal Register in July 2016. The EPA's final action to approve the amendments to the Arizona regional haze SIP was issued January 13, 2017, and published in the Federal Register March 27, 2017, with an effective date of April 26, 2017.
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. Nevada Power, along with the other owners of the facility, have been reviewing the EPA's proposal to determine its impact on the viability of the facility's future operations. The land lease for the Navajo Generating Station is subject to renewal in 2019. Renewal of the lease will require completion of an Environmental Impact Statement as well as a renewal of the fuel supply agreement. In September 2013, the EPA issued a supplemental proposal that included another BART alternative called the Technical Work Group Alternative, which is based on a proposal submitted to the EPA by a group of Navajo Generating Station stakeholders. The EPA accepted comments on the various alternatives through January 6, 2014 and, in August 2014, the EPA announced it had approved the final plan for the Navajo Generating Station, including the reduction of emissions of nitrogen oxides by approximately 80% through the retirement of one unit, or the curtailment of generation equivalent to one unit, in 2019 and installation of SCR controls at the other two units by 2030. In October 2014, several groups filed an appeal of the EPA's decision in the Ninth Circuit; oral arguments were heard by the Ninth Circuit on November 18, 2016. The Hopi Tribe was initially part of the larger group appeal but their challenge was subsequently severed from that appeal and is proceeding separately. On March 20, 2017, the Ninth Circuit denied the petitions for review in the larger group appeal and the petition filed by the Hopi Tribe, upholding the EPA’s ability to issue a FIP on tribal land. 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.
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. The Clean Power Plan, which was finalized by the EPA in 2015 and is currently under review, was the primary basis for the United States' commitment under the Paris Agreement.
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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-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards have been appealed to the D.C. Circuit and oral argument was scheduled to be heard April 17, 2017. In March 2017, President Trump signed an Executive Order on Promoting Energy Independence and Economic Growth which includes a requirement to review and revise or rescind the new source performance standards. In response to the Executive Order, the Department of Justice requested that the court postpone the oral argument scheduled for April 17, 2017, and filed a motion to hold the case in abeyance for 30 days after the conclusion of the required regulatory review and any new rulemaking. On March 30, 2017, the court canceled the oral arguments pending disposition of the motion to hold the case in abeyance. Despite the pendency of the appeal and activities associated with implementing the Executive Order, 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 EPA also changed the compliance period to begin in 2022, with three interim periods of compliance and with the final goal to be achieved by 2030. Based on changes to the state emission reduction targets, which are now all between 771 pounds per MWh and 1,305 pounds per MWh, the Clean Power Plan, when fully implemented, is expected to reduce carbon dioxide emissions in the power sector to 32% below 2005 levels by 2030. The EPA also released in August 2015, a draft federal plan as an option or backstop for states to utilize in the event they do not submit approvable state plans. The public comment period on the draft federal plan and proposed model trading rules closed January 21, 2016. States were required to submit their initial implementation plans by September 2016 but could request an extension to September 2018. However, 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 U.S. Supreme Court. Oral argument was heard before the full D.C. Circuit (with the exception of Chief Judge Merrick Garland) on September 27, 2016, and the court has not yet issued its decision. As with the new source performance standards, the existing source standards are subject to review and revision or rescission under the Executive Order, and the Department of Justice filed a motion seeking to have the case held in abeyance pending the review and associated action. The full impacts of the final rule or the federal plan on the Registrants cannot be determined until the outcome of the pending litigation and subsequent appeals, the outcome of any issues should the case be remanded for further action by the EPA and the review of the rule and any subsequent action taken by the EPA in response to the Executive Order. 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 advancement of customer energy efficiency programs.
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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. 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 guidelines, permitting authorities were required to include the new limits in each impacted facility's discharge permit upon renewal; the new limits must be met as soon as possible, beginning November 1, 2018 and must be 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 that the court stay the pending litigation over the rule until September 12, 2017. While most of the issues raised by this rule 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 action is complete and any judicial review is concluded.
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 U.S. Supreme Court granted a petition to address jurisdictional challenges to the rule. Depending on the outcome of the appeal(s), a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits would have been required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. On February 28, 2017, President Trump signed an Executive Order directing the EPA to review and rescind or revise the rule. Until the rule is reviewed and rescinded or 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.
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New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting the Company, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
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, 2016. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2016.
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PacifiCorp and its subsidiaries
Consolidated Financial Section
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PART I
Item 1. | Financial Statements |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PacifiCorp
Portland, Oregon
We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of March 31, 2017, and the related consolidated statements of operations, changes in shareholders' equity, and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of PacifiCorp's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of PacifiCorp and subsidiaries as of December 31, 2016, 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Portland, Oregon
May 5, 2017
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | ||||||||
March 31, | December 31, | |||||||
2017 | 2016 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 15 | $ | 17 | ||||
Accounts receivable, net | 633 | 728 | ||||||
Income taxes receivable | — | 17 | ||||||
Inventories: | ||||||||
Materials and supplies | 229 | 228 | ||||||
Fuel | 212 | 215 | ||||||
Regulatory assets | 35 | 53 | ||||||
Other current assets | 78 | 96 | ||||||
Total current assets | 1,202 | 1,354 | ||||||
Property, plant and equipment, net | 19,130 | 19,162 | ||||||
Regulatory assets | 1,535 | 1,490 | ||||||
Other assets | 370 | 388 | ||||||
Total assets | $ | 22,237 | $ | 22,394 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of | ||||||||
March 31, | December 31, | |||||||
2017 | 2016 | |||||||
LIABILITIES AND SHAREHOLDERS' EQUITY | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 371 | $ | 408 | ||||
Income taxes payable | 80 | — | ||||||
Accrued employee expenses | 76 | 67 | ||||||
Accrued interest | 106 | 115 | ||||||
Accrued property and other taxes | 92 | 63 | ||||||
Short-term debt | 8 | 270 | ||||||
Current portion of long-term debt and capital lease obligations | 93 | 58 | ||||||
Regulatory liabilities | 39 | 54 | ||||||
Other current liabilities | 173 | 164 | ||||||
Total current liabilities | 1,038 | 1,199 | ||||||
Regulatory liabilities | 1,017 | 978 | ||||||
Long-term debt and capital lease obligations | 6,934 | 7,021 | ||||||
Deferred income taxes | 4,870 | 4,880 | ||||||
Other long-term liabilities | 909 | 926 | ||||||
Total liabilities | 14,768 | 15,004 | ||||||
Commitments and contingencies (Note 7) | ||||||||
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 | 3,000 | 2,921 | ||||||
Accumulated other comprehensive loss, net | (12 | ) | (12 | ) | ||||
Total shareholders' equity | 7,469 | 7,390 | ||||||
Total liabilities and shareholders' equity | $ | 22,237 | $ | 22,394 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||||
Ended March 31, | |||||||||
2017 | 2016 | ||||||||
Operating revenue | $ | 1,281 | $ | 1,252 | |||||
Operating costs and expenses: | |||||||||
Energy costs | 441 | 427 | |||||||
Operations and maintenance | 248 | 263 | |||||||
Depreciation and amortization | 196 | 190 | |||||||
Taxes, other than income taxes | 51 | 48 | |||||||
Total operating costs and expenses | 936 | 928 | |||||||
Operating income | 345 | 324 | |||||||
Other income (expense): | |||||||||
Interest expense | (95 | ) | (95 | ) | |||||
Allowance for borrowed funds | 4 | 4 | |||||||
Allowance for equity funds | 7 | 7 | |||||||
Other, net | 3 | 3 | |||||||
Total other income (expense) | (81 | ) | (81 | ) | |||||
Income before income tax expense | 264 | 243 | |||||||
Income tax expense | 85 | 78 | |||||||
Net income | $ | 179 | $ | 165 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY (Unaudited)
(Amounts in millions)
Accumulated | ||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||
Preferred | Common | Paid-in | Retained | Comprehensive | Shareholders' | |||||||||||||||||||
Stock | Stock | Capital | Earnings | Loss, Net | Equity | |||||||||||||||||||
Balance, December 31, 2015 | $ | 2 | $ | — | $ | 4,479 | $ | 3,033 | $ | (11 | ) | $ | 7,503 | |||||||||||
Net income | — | — | — | 165 | — | 165 | ||||||||||||||||||
Common stock dividends declared | — | — | — | (100 | ) | — | (100 | ) | ||||||||||||||||
Balance, March 31, 2016 | $ | 2 | $ | — | $ | 4,479 | $ | 3,098 | $ | (11 | ) | $ | 7,568 | |||||||||||
Balance, December 31, 2016 | $ | 2 | $ | — | $ | 4,479 | $ | 2,921 | $ | (12 | ) | $ | 7,390 | |||||||||||
Net income | — | — | — | 179 | — | 179 | ||||||||||||||||||
Common stock dividends declared | — | — | — | (100 | ) | — | (100 | ) | ||||||||||||||||
Balance, March 31, 2017 | $ | 2 | $ | — | $ | 4,479 | $ | 3,000 | $ | (12 | ) | $ | 7,469 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Three-Month Periods | ||||||||
Ended March 31, | ||||||||
2017 | 2016 | |||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 179 | $ | 165 | ||||
Adjustments to reconcile net income to net cash flows from operating activities: | ||||||||
Depreciation and amortization | 196 | 190 | ||||||
Allowance for equity funds | (7 | ) | (7 | ) | ||||
Deferred income taxes and amortization of investment tax credits | (5 | ) | (6 | ) | ||||
Changes in regulatory assets and liabilities | 19 | 29 | ||||||
Changes in other operating assets and liabilities: | ||||||||
Accounts receivable and other assets | 102 | 104 | ||||||
Derivative collateral, net | (7 | ) | (3 | ) | ||||
Inventories | 2 | (24 | ) | |||||
Income taxes | 97 | 84 | ||||||
Accounts payable and other liabilities | (7 | ) | — | |||||
Net cash flows from operating activities | 569 | 532 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (178 | ) | (200 | ) | ||||
Other, net | 20 | (2 | ) | |||||
Net cash flows from investing activities | (158 | ) | (202 | ) | ||||
Cash flows from financing activities: | ||||||||
Repayments of long-term debt and capital lease obligations | (51 | ) | (55 | ) | ||||
Net repayments of short-term debt | (262 | ) | (20 | ) | ||||
Common stock dividends | (100 | ) | (100 | ) | ||||
Net cash flows from financing activities | (413 | ) | (175 | ) | ||||
Net change in cash and cash equivalents | (2 | ) | 155 | |||||
Cash and cash equivalents at beginning of period | 17 | 12 | ||||||
Cash and cash equivalents at end of period | $ | 15 | $ | 167 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
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PACIFICORP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) General
PacifiCorp, which includes PacifiCorp and its subsidiaries, is a United States regulated electric utility company serving retail customers, including residential, commercial, industrial, irrigation and other customers in portions of Utah, Oregon, Wyoming, Washington, Idaho and California. PacifiCorp owns, or has interests in, a number of thermal, hydroelectric, wind-powered and geothermal generating facilities, as well as electric transmission and distribution assets. PacifiCorp also buys and sells electricity on the wholesale market with other utilities, energy marketing companies, financial institutions and other market participants. PacifiCorp is subject to comprehensive state and federal regulation. PacifiCorp's subsidiaries support its electric utility operations by providing coal mining services. PacifiCorp is an indirect subsidiary of Berkshire Hathaway Energy Company ("BHE"), a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2017 and for the three-month periods ended March 31, 2017 and 2016. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month periods ended March 31, 2017 and 2016 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, 2016 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in PacifiCorp's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2017.
(2) New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
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In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB 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 in 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The impact of this update is immaterial to PacifiCorp's Consolidated Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. PacifiCorp is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. PacifiCorp currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when PacifiCorp has the right to invoice as it corresponds directly with the value to the customer of PacifiCorp’s performance to date. PacifiCorp’s current plan is to quantitatively disaggregate revenue in the required financial statement footnote by customer class and jurisdiction.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of | |||||||||
March 31, | December 31, | ||||||||
Depreciable Life | 2017 | 2016 | |||||||
Property, plant and equipment in-service | 5-75 years | $ | 27,341 | $ | 27,298 | ||||
Accumulated depreciation and amortization | (8,927 | ) | (8,793 | ) | |||||
Net property, plant and equipment in-service | 18,414 | 18,505 | |||||||
Construction work-in-progress | 716 | 657 | |||||||
Total property, plant and equipment, net | $ | 19,130 | $ | 19,162 | |||||
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(4) Employee Benefit Plans
Net periodic benefit cost for the pension and other postretirement benefit plans included the following components (in millions):
Three-Month Periods | |||||||||
Ended March 31, | |||||||||
2017 | 2016 | ||||||||
Pension: | |||||||||
Service cost | $ | — | $ | 1 | |||||
Interest cost | 12 | 14 | |||||||
Expected return on plan assets | (18 | ) | (19 | ) | |||||
Net amortization | 4 | 8 | |||||||
Net periodic benefit cost | $ | (2 | ) | $ | 4 | ||||
Other postretirement: | |||||||||
Service cost | $ | 1 | $ | 1 | |||||
Interest cost | 3 | 4 | |||||||
Expected return on plan assets | (6 | ) | (6 | ) | |||||
Net amortization | (1 | ) | (1 | ) | |||||
Net periodic benefit credit | $ | (3 | ) | $ | (2 | ) | |||
Employer contributions to the pension and other postretirement benefit plans are expected to be $5 million and $- million, respectively, during 2017. As of March 31, 2017, $1 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(5) 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 6 for additional information on derivative contracts.
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The following table, which reflects master netting arrangements and excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of PacifiCorp's derivative contracts, on a gross basis, and reconciles those amounts to the amounts presented on a net basis on the Consolidated Balance Sheets (in millions):
Other | Other | Other | |||||||||||||||||
Current | Other | Current | Long-term | ||||||||||||||||
Assets | Assets | Liabilities | Liabilities | Total | |||||||||||||||
As of March 31, 2017 | |||||||||||||||||||
Not designated as hedging contracts(1): | |||||||||||||||||||
Commodity assets | $ | 7 | $ | — | $ | 5 | $ | — | $ | 12 | |||||||||
Commodity liabilities | (1 | ) | — | (27 | ) | (91 | ) | (119 | ) | ||||||||||
Total | 6 | — | (22 | ) | (91 | ) | (107 | ) | |||||||||||
Total derivatives | 6 | — | (22 | ) | (91 | ) | (107 | ) | |||||||||||
Cash collateral receivable | — | — | 13 | 63 | 76 | ||||||||||||||
Total derivatives - net basis | $ | 6 | $ | — | $ | (9 | ) | $ | (28 | ) | $ | (31 | ) | ||||||
As of December 31, 2016 | |||||||||||||||||||
Not designated as hedging contracts(1): | |||||||||||||||||||
Commodity assets | $ | 24 | $ | 2 | $ | 1 | $ | — | $ | 27 | |||||||||
Commodity liabilities | (6 | ) | — | (14 | ) | (84 | ) | (104 | ) | ||||||||||
Total | 18 | 2 | (13 | ) | (84 | ) | (77 | ) | |||||||||||
Total derivatives | 18 | 2 | (13 | ) | (84 | ) | (77 | ) | |||||||||||
Cash collateral receivable | — | — | 10 | 59 | 69 | ||||||||||||||
Total derivatives - net basis | $ | 18 | $ | 2 | $ | (3 | ) | $ | (25 | ) | $ | (8 | ) | ||||||
(1) | PacifiCorp's commodity derivatives are generally included in rates and as of March 31, 2017 and December 31, 2016, a regulatory asset of $103 million and $73 million, respectively, was recorded related to the net derivative liability of $107 million and $77 million, respectively. |
Not Designated as Hedging Contracts
The following table reconciles the beginning and ending balances of PacifiCorp's net regulatory assets and summarizes the pre-tax gains and losses on commodity derivative contracts recognized in net regulatory assets, as well as amounts reclassified to earnings (in millions):
Three-Month Periods | |||||||||
Ended March 31, | |||||||||
2017 | 2016 | ||||||||
Beginning balance | $ | 73 | $ | 133 | |||||
Changes in fair value recognized in net regulatory assets | 24 | 26 | |||||||
Net gains reclassified to operating revenue | 12 | 8 | |||||||
Net losses reclassified to energy costs | (6 | ) | (23 | ) | |||||
Ending balance | $ | 103 | $ | 144 | |||||
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Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):
Unit of | March 31, | December 31, | |||||
Measure | 2017 | 2016 | |||||
Electricity (sales) purchases | Megawatt hours | — | (3 | ) | |||
Natural gas purchases | Decatherms | 82 | 84 | ||||
Fuel oil purchases | Gallons | 8 | 11 | ||||
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 March 31, 2017, PacifiCorp's credit ratings from the three recognized credit rating agencies were investment grade.
The aggregate fair value of PacifiCorp's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $112 million and $97 million as of March 31, 2017 and December 31, 2016, respectively, for which PacifiCorp had posted collateral of $76 million and $69 million, respectively, in the form of cash deposits. If all credit-risk-related contingent features for derivative contracts in liability positions had been triggered as of March 31, 2017 and December 31, 2016, PacifiCorp would have been required to post $28 million and $22 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.
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(6) Fair Value Measurements
The carrying value of PacifiCorp's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. PacifiCorp has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
• | Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that PacifiCorp has the ability to access at the measurement date. |
• | Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs). |
• | Level 3 - Unobservable inputs reflect PacifiCorp's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. PacifiCorp develops these inputs based on the best information available, including its own data. |
The following table presents PacifiCorp's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements | ||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(1) | Total | ||||||||||||||||
As of March 31, 2017 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | — | $ | 12 | $ | — | $ | (6 | ) | $ | 6 | |||||||||
Money market mutual funds(2) | 12 | — | — | — | 12 | |||||||||||||||
Investment funds | 18 | — | — | — | 18 | |||||||||||||||
$ | 30 | $ | 12 | $ | — | $ | (6 | ) | $ | 36 | ||||||||||
Liabilities - Commodity derivatives | $ | — | $ | (119 | ) | $ | — | $ | 82 | $ | (37 | ) | ||||||||
As of December 31, 2016 | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | — | $ | 27 | $ | — | $ | (7 | ) | $ | 20 | |||||||||
Money market mutual funds(2) | 13 | — | — | — | 13 | |||||||||||||||
Investment funds | 17 | — | — | — | 17 | |||||||||||||||
$ | 30 | $ | 27 | $ | — | $ | (7 | ) | $ | 50 | ||||||||||
Liabilities - Commodity derivatives | $ | — | $ | (104 | ) | $ | — | $ | 76 | $ | (28 | ) | ||||||||
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $76 million and $69 million as of March 31, 2017 and December 31, 2016, respectively. |
(2) | Amounts are included in cash and cash equivalents, other current assets and other assets on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
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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 six 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 six 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 5 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 and are primarily accounted for as available-for-sale securities. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.
PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of PacifiCorp's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of PacifiCorp's long-term debt (in millions):
As of March 31, 2017 | As of December 31, 2016 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Value | Value | Value | Value | |||||||||||||
Long-term debt | $ | 7,003 | $ | 8,149 | $ | 7,052 | $ | 8,204 | ||||||||
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(7) Commitments and Contingencies
Legal Matters
PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Environmental Laws and Regulations
PacifiCorp is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.
Hydroelectric Relicensing
PacifiCorp's Klamath hydroelectric system is currently operating under annual licenses with the Federal Energy Regulatory Commission ("FERC"). In February 2010, PacifiCorp, the United States Department of the Interior, the United States Department of Commerce, the state of California, the state of Oregon and various other governmental and non-governmental settlement parties signed the Klamath Hydroelectric Settlement Agreement ("KHSA").
Congress failed to pass legislation needed to implement the original KHSA. On April 6, 2016, PacifiCorp, the states of California and Oregon, and the United States Departments of the Interior and Commerce and other stakeholders executed an amendment to the KHSA. Consistent with the terms of the amended KHSA, on September 23, 2016, PacifiCorp and the Klamath River Renewal Corporation ("KRRC") jointly filed an application with the FERC to transfer the license for the four mainstem Klamath River hydroelectric generating facilities from PacifiCorp to the KRRC. Also on September 23, 2016, the KRRC filed an application with the FERC to surrender the license and decommission the facilities. The KRRC's license surrender application included a request for the FERC to refrain from acting on the surrender application until after the transfer of the license to the KRRC is effective.
Under the amended KHSA, PacifiCorp and its customers are protected from uncapped dam removal costs and liabilities. The KRRC must indemnify PacifiCorp from liabilities associated with dam removal. The amended KHSA also limits PacifiCorp's contribution to facilities removal costs to no more than $200 million, of which up to $184 million would be collected from PacifiCorp's Oregon customers with the remainder to be collected from PacifiCorp's California customers. California voters approved a water bond measure in November 2014 from which the state of California's contribution toward facilities removal costs are being drawn. In accordance with this bond measure, additional funding of up to $250 million for facilities removal costs was included in the California state budget in 2016, with the funding effective for at least five years. If facilities removal costs exceed the combined funding that will be available from PacifiCorp's Oregon and California customers and the state of California, sufficient funds would need to be provided by the KRRC or an entity other than PacifiCorp for removal to proceed.
If certain conditions in the amended KHSA are not satisfied and the license does not transfer to the KRRC, PacifiCorp will resume relicensing with the FERC.
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.
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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 factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.
Results of Operations for the First Quarter of 2017 and 2016
Overview
Net income for the first quarter of 2017 was $179 million, an increase of $14 million or 8%, compared to 2016. Net income increased due to higher margins of $15 million, lower operations and maintenance of $15 million, partially offset by higher depreciation and amortization of $6 million and higher property taxes of $3 million. Margins increased primarily due to higher retail customer volumes, lower purchased electricity prices and higher wholesale electricity revenue from higher short-term market prices, partially offset by higher purchased electricity volumes and lower average retail rates. Retail customer volumes increased by 2.8% mainly due to the impacts of weather on residential and commercial customers, primarily in Oregon and Washington, an increase in the average number of residential and commercial customers, primarily in Utah, and higher industrial usage, partially offset by lower residential usage in Utah and Oregon. Energy generated decreased 4% for the first quarter of 2017 compared to 2016 primarily due to lower natural gas-fueled generation and wind-powered generation. Wholesale electricity sales volumes decreased 13% and purchased electricity volumes increased 27%.
Operating revenue and energy costs are the key drivers of PacifiCorp's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. PacifiCorp believes that a discussion of gross margin, representing operating revenue less energy costs, is therefore meaningful.
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A comparison of PacifiCorp's key operating results is as follows:
First Quarter | |||||||||||||||
2017 | 2016 | Change | |||||||||||||
Gross margin (in millions): | |||||||||||||||
Operating revenue | $ | 1,281 | $ | 1,252 | $ | 29 | 2 | % | |||||||
Energy costs | 441 | 427 | 14 | 3 | |||||||||||
Gross margin | $ | 840 | $ | 825 | $ | 15 | 2 | ||||||||
Sales (GWh): | |||||||||||||||
Residential | 4,461 | 4,260 | 201 | 5 | % | ||||||||||
Commercial | 4,195 | 4,091 | 104 | 3 | |||||||||||
Industrial, irrigation and other | 5,014 | 4,943 | 71 | 1 | |||||||||||
Total retail | 13,670 | 13,294 | 376 | 3 | |||||||||||
Wholesale | 1,650 | 1,894 | (244 | ) | (13 | ) | |||||||||
Total sales | 15,320 | 15,188 | 132 | 1 | |||||||||||
Average number of retail customers | |||||||||||||||
(in thousands) | 1,859 | 1,833 | 26 | 1 | % | ||||||||||
Average revenue per MWh: | |||||||||||||||
Retail | $ | 86.80 | $ | 87.99 | $ | (1.19 | ) | (1 | )% | ||||||
Wholesale | $ | 34.81 | $ | 24.53 | $ | 10.28 | 42 | % | |||||||
Heating degree days | 4,758 | 4,438 | 320 | 7 | % | ||||||||||
Sources of energy (GWh)(1): | |||||||||||||||
Coal | 8,840 | 8,732 | 108 | 1 | % | ||||||||||
Natural gas | 1,838 | 2,326 | (488 | ) | (21 | ) | |||||||||
Hydroelectric(2) | 1,379 | 1,344 | 35 | 3 | |||||||||||
Wind and other(2) | 880 | 1,009 | (129 | ) | (13 | ) | |||||||||
Total energy generated | 12,937 | 13,411 | (474 | ) | (4 | ) | |||||||||
Energy purchased | 3,585 | 2,826 | 759 | 27 | |||||||||||
Total | 16,522 | 16,237 | 285 | 2 | |||||||||||
Average cost of energy per MWh: | |||||||||||||||
Energy generated(3) | $ | 19.30 | $ | 17.89 | $ | 1.41 | 8 | % | |||||||
Energy purchased | $ | 41.82 | $ | 48.49 | $ | (6.67 | ) | (14 | )% | ||||||
(1) | GWh amounts are net of energy used by the related generating facilities. |
(2) | All or some of the renewable energy attributes associated with generation from these generating facilities may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of RECs or other environmental commodities. |
(3) | The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities. |
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Gross margin increased $15 million, or 2%, for the first quarter of 2017 compared to 2016 primarily due to:
• | $36 million of higher retail revenues due to increased retail customer volumes of 2.8% mainly due to the impacts of weather on residential and commercial customers, primarily in Oregon and Washington, an increase in the average number of residential and commercial customers, primarily in Utah, and higher industrial usage, partially offset by lower residential usage in Utah and Oregon; |
• | $22 million of lower purchased electricity due to lower average prices; |
• | $11 million of higher wholesale revenue, primarily due to higher average wholesale short-term market 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:
• | $35 million of higher purchased electricity costs due to higher volumes; |
• | $12 million of higher coal costs from higher average coal prices and volumes; |
• | $11 million of lower Demand Side Management ("DSM") revenues (offset in operating expenses), primarily driven by the recently implemented Utah Sustainable Transportation and Energy Plan ("STEP") program; and |
• | $5 million of lower average retail rates from unfavorable price mix. |
Operations and maintenance decreased $15 million, or 6%, for the first quarter of 2017 compared to 2016 primarily due to a decrease in DSM amortization expense (offset in revenues) driven by the establishment of the Utah STEP program, a decrease in pension expense primarily due to a current year plan change and lower plant maintenance. These decreases were partially offset by an increase in injury and damage expenses, primarily as a result of a first-quarter 2016 accrual for insurance proceeds.
Depreciation and amortization increased $6 million, or 3%, for the first quarter of 2017 compared to 2016 primarily due to higher plant-in-service.
Taxes, other than income taxes increased $3 million, or 6% for the first quarter of 2017 compared to 2016 due to higher assessed property values and lower capitalization of property taxes.
Income tax expense increased $7 million, or 9%, for the first quarter of 2017 compared to 2016 and the effective tax rate was 32% for 2017 and 2016.
Liquidity and Capital Resources
As of March 31, 2017, PacifiCorp's total net liquidity was as follows (in millions):
Cash and cash equivalents | $ | 15 | ||
Credit facilities | 1,000 | |||
Less: | ||||
Short-term debt | (8 | ) | ||
Tax-exempt bond support | (92 | ) | ||
Net credit facilities | 900 | |||
Total net liquidity | $ | 915 | ||
Credit facilities: | ||||
Maturity dates | 2018, 2019 | |||
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Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016 were $569 million and $532 million, respectively. The change was primarily due to an increase in cash collected from retail and wholesale customers, partially offset by increases in payments for payroll and purchased power.
In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% in 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. As a result of PATH, PacifiCorp's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019.
The timing of PacifiCorp's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016 were $(158) million and $(202) million, respectively. The change reflects a current year net distribution from an affiliate of $13 million and a decrease in capital expenditures of $22 million in 2017. Refer to "Future Uses of Cash" for discussion of capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month period ended March 31, 2017 was $(413) million. Uses of cash consisted substantially of $100 million for common stock dividends paid to PPW Holdings LLC, $50 million for the repayment of long-term debt and $262 million for the repayment of short-term debt.
Net cash flows from financing activities for the three-month period ended March 31, 2016 was $(175) million. Uses of cash consisted substantially of $100 million for common stock dividends paid to PPW Holdings LLC, $54 million for the repayment of long-term debt and $20 million for the repayment of short-term debt.
Short-term Debt
Regulatory authorities limit PacifiCorp to $1.5 billion of short-term debt. As of March 31, 2017, PacifiCorp had $8 million of short-term debt outstanding at a weighted average interest rate of 1.10%. As of December 31, 2016, PacifiCorp had $270 million of short-term debt outstanding at a weighted average interest rate of 0.96%.
Long-term Debt
PacifiCorp currently has regulatory authority from the OPUC and the IPUC to issue an additional $1.325 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance.
Future Uses of Cash
PacifiCorp has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Capital Expenditures
PacifiCorp has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, 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.
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Historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):
Three-Month Periods | Annual | ||||||||||
Ended March 31, | Forecast | ||||||||||
2016 | 2017 | 2017 | |||||||||
Transmission system investment | $ | 32 | $ | 25 | $ | 118 | |||||
Environmental | 15 | 5 | 32 | ||||||||
Wind investment | — | 2 | 35 | ||||||||
Operating and other | 153 | 146 | 652 | ||||||||
Total | $ | 200 | $ | 178 | $ | 837 | |||||
PacifiCorp's historical and forecast capital expenditures include the following:
• | Transmission system investment primarily reflects main grid reinforcement costs and 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 $14 million in 2017. |
• | Environmental includes the installation of new or the replacement of existing emissions control equipment at certain generating facilities, including installation or upgrade of selective catalytic reduction control systems and low nitrogen oxide burners to reduce nitrogen oxides, particulate matter control systems, sulfur dioxide emissions control systems and mercury emissions control systems, as well as expenditures for the management of coal combustion residuals. |
• | Wind investment includes initial costs for new wind plant construction projects and repowering of certain existing wind plants. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowering totals $6 million in 2017 and for the new wind-powered generating facilities totals $29 million in 2017. The repowering projects are expected to be placed in-service at various dates in 2019 and 2020. The new wind-powered generating facilities are also expected to be placed in-service in 2019 and 2020. The energy production from the repowered and new wind-powered generating facilities is expected to qualify for 100% of the federal renewable electricity production tax credit available for 10 years once the equipment is placed in-service. |
• | Remaining investments relate to operating projects that consist of routine expenditures for generation, transmission, distribution and other infrastructure needed to serve existing and expected demand, including upgrades to customer meters in Oregon and Idaho. |
Integrated Resource Plan
In April 2017, PacifiCorp filed its 2017 Integrated Resource Plan ("IRP") with its state commissions. The IRP includes investments in renewable energy resources, upgrades to the existing wind fleet, and energy efficiency measures to meet future customer needs. Implementation of wind upgrades, new transmission, and new wind renewable resources will require an estimated $3.5 billion in capital investment from 2017 through 2020. PacifiCorp's forecast capital expenditures for 2018 through 2019 increased $723 million from the forecast included in PacifiCorp's 2016 Annual Report on Form 10-K as a result of its 2017 IRP.
Request 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.
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Contractual Obligations
As of March 31, 2017, 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, 2016.
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, local and foreign laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact PacifiCorp's current and future operations. 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, local and international agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results. Refer to "Liquidity and Capital Resources" for discussion of PacifiCorp's forecast environmental-related capital expenditures.
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.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting PacifiCorp, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of the Form 10-Q.
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, 2016. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2016.
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MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company
Consolidated Financial Section
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PART I
Item 1. | Financial Statements |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
MidAmerican Energy Company
Des Moines, Iowa
We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of March 31, 2017, and the related statements of operations, changes in equity, and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of MidAmerican Energy's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.
Based on our reviews, we are not aware of any material modifications that should be made to such interim financial statements for them 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), the balance sheet of MidAmerican Energy Company as of December 31, 2016, and the related 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
May 5, 2017
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MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 489 | $ | 14 | |||
Receivables, net | 246 | 285 | |||||
Income taxes receivable | 44 | 9 | |||||
Inventories | 242 | 264 | |||||
Other current assets | 28 | 35 | |||||
Total current assets | 1,049 | 607 | |||||
Property, plant and equipment, net | 12,863 | 12,821 | |||||
Regulatory assets | 1,186 | 1,161 | |||||
Investments and restricted cash and investments | 678 | 653 | |||||
Other assets | 197 | 217 | |||||
Total assets | $ | 15,973 | $ | 15,459 | |||
The accompanying notes are an integral part of these financial statements.
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MIDAMERICAN ENERGY COMPANY
BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
LIABILITIES AND SHAREHOLDER'S EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 238 | $ | 303 | |||
Accrued interest | 49 | 45 | |||||
Accrued property, income and other taxes | 102 | 137 | |||||
Short-term debt | — | 99 | |||||
Current portion of long-term debt | 350 | 250 | |||||
Other current liabilities | 149 | 159 | |||||
Total current liabilities | 888 | 993 | |||||
Long-term debt | 4,544 | 4,051 | |||||
Deferred income taxes | 3,598 | 3,572 | |||||
Regulatory liabilities | 870 | 883 | |||||
Asset retirement obligations | 518 | 510 | |||||
Other long-term liabilities | 290 | 290 | |||||
Total liabilities | 10,708 | 10,299 | |||||
Commitments and contingencies (Note 8) | |||||||
Shareholder's equity: | |||||||
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding | — | — | |||||
Additional paid-in capital | 561 | 561 | |||||
Retained earnings | 4,704 | 4,599 | |||||
Total shareholder's equity | 5,265 | 5,160 | |||||
Total liabilities and shareholder's equity | $ | 15,973 | $ | 15,459 | |||
The accompanying notes are an integral part of these financial statements.
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MIDAMERICAN ENERGY COMPANY
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
Regulated electric | $ | 433 | $ | 399 | |||
Regulated gas and other | 262 | 226 | |||||
Total operating revenue | 695 | 625 | |||||
Operating costs and expenses: | |||||||
Cost of fuel, energy and capacity | 102 | 92 | |||||
Cost of gas sold and other | 172 | 135 | |||||
Operations and maintenance | 166 | 160 | |||||
Depreciation and amortization | 117 | 110 | |||||
Property and other taxes | 31 | 28 | |||||
Total operating costs and expenses | 588 | 525 | |||||
Operating income | 107 | 100 | |||||
Other income and (expense): | |||||||
Interest expense | (53 | ) | (49 | ) | |||
Allowance for borrowed funds | 2 | 1 | |||||
Allowance for equity funds | 6 | 4 | |||||
Other, net | 6 | 3 | |||||
Total other income and (expense) | (39 | ) | (41 | ) | |||
Income before income tax benefit | 68 | 59 | |||||
Income tax benefit | (37 | ) | (17 | ) | |||
Net income | $ | 105 | $ | 76 | |||
The accompanying notes are an integral part of these financial statements.
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MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
Common Stock | Retained Earnings | Accumulated Other Comprehensive Loss, Net | Total Equity | ||||||||||||
Balance, December 31, 2015 | $ | 561 | $ | 4,174 | $ | (30 | ) | $ | 4,705 | ||||||
Net income | — | 76 | — | 76 | |||||||||||
Other comprehensive income | — | — | 1 | 1 | |||||||||||
Dividend | — | (117 | ) | 27 | (90 | ) | |||||||||
Balance, March 31, 2016 | $ | 561 | $ | 4,133 | $ | (2 | ) | $ | 4,692 | ||||||
Balance, December 31, 2016 | $ | 561 | $ | 4,599 | $ | — | $ | 5,160 | |||||||
Net income | — | 105 | — | 105 | |||||||||||
Balance, March 31, 2017 | $ | 561 | $ | 4,704 | $ | — | $ | 5,265 | |||||||
The accompanying notes are an integral part of these financial statements.
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MIDAMERICAN ENERGY COMPANY
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 105 | $ | 76 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 117 | 110 | |||||
Deferred income taxes and amortization of investment tax credits | 13 | 11 | |||||
Changes in other assets and liabilities | 11 | 11 | |||||
Other, net | (6 | ) | (13 | ) | |||
Changes in other operating assets and liabilities: | |||||||
Receivables, net | 39 | 28 | |||||
Inventories | 22 | (1 | ) | ||||
Derivative collateral, net | — | 2 | |||||
Contributions to pension and other postretirement benefit plans, net | (3 | ) | (2 | ) | |||
Accounts payable | 1 | 4 | |||||
Accrued property, income and other taxes, net | (71 | ) | (48 | ) | |||
Other current assets and liabilities | (6 | ) | (6 | ) | |||
Net cash flows from operating activities | 222 | 172 | |||||
Cash flows from investing activities: | |||||||
Utility construction expenditures | (238 | ) | (332 | ) | |||
Purchases of available-for-sale securities | (40 | ) | (34 | ) | |||
Proceeds from sales of available-for-sale securities | 35 | 29 | |||||
Other, net | 7 | (3 | ) | ||||
Net cash flows from investing activities | (236 | ) | (340 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from long-term debt | 843 | — | |||||
Repayments of long-term debt | (255 | ) | (4 | ) | |||
Net (repayments of) proceeds from short-term debt | (99 | ) | 70 | ||||
Net cash flows from financing activities | 489 | 66 | |||||
Net change in cash and cash equivalents | 475 | (102 | ) | ||||
Cash and cash equivalents at beginning of period | 14 | 103 | |||||
Cash and cash equivalents at end of period | $ | 489 | $ | 1 | |||
The accompanying notes are an integral part of these financial statements.
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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 consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of March 31, 2017, and for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month periods ended March 31, 2017, 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, 2016, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2017.
(2) | New Accounting Pronouncements |
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
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In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB 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 in 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
In January 2016, the FASB issued ASU No. 2016-01, which amends FASB ASC Subtopic 825-10, "Financial Instruments - Overall." The amendments in this guidance address certain aspects of recognition, measurement, presentation and disclosure of financial instruments including a requirement that all investments in equity securities that do not qualify for equity method accounting or result in consolidation of the investee be measured at fair value with changes in fair value recognized in net income. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption not permitted, and is required to be adopted prospectively by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. MidAmerican Energy is currently evaluating the impact of adopting this guidance on its Financial Statements and disclosures included within Notes to Financial Statements. MidAmerican Energy currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when MidAmerican Energy has the right to invoice as it corresponds directly with the value to the customer of MidAmerican Energy’s performance to date. MidAmerican Energy's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by jurisdiction for each segment.
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(3) | Property, Plant and Equipment, Net |
Property, plant and equipment, net consists of the following (in millions):
As of | |||||||||
March 31, | December 31, | ||||||||
Depreciable Life | 2017 | 2016 | |||||||
Utility plant in service, net: | |||||||||
Generation | 20-70 years | $ | 11,317 | $ | 11,282 | ||||
Transmission | 52-75 years | 1,767 | 1,726 | ||||||
Electric distribution | 20-75 years | 3,216 | 3,197 | ||||||
Gas distribution | 28-70 years | 1,574 | 1,565 | ||||||
Utility plant in service | 17,874 | 17,770 | |||||||
Accumulated depreciation and amortization | (5,581 | ) | (5,448 | ) | |||||
Utility plant in service, net | 12,293 | 12,322 | |||||||
Nonregulated property, net: | |||||||||
Nonregulated property gross | 20-50 years | 7 | 7 | ||||||
Accumulated depreciation and amortization | (1 | ) | (1 | ) | |||||
Nonregulated property, net | 6 | 6 | |||||||
12,299 | 12,328 | ||||||||
Construction work-in-progress | 564 | 493 | |||||||
Property, plant and equipment, net | $ | 12,863 | $ | 12,821 | |||||
During the fourth quarter of 2016, MidAmerican Energy revised its electric and gas depreciation rates based on the results of a new depreciation study, the most significant impact of which was longer estimated useful lives for certain wind-powered generating facilities. The effect of this change was to reduce depreciation and amortization expense by $34 million annually, or $9 million for the three-month period ended March 31, 2017, based on depreciable plant balances at the time of the change.
(4) Recent Financing Transactions
In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds.
In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017.
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(5) | 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 | |||||
Ended March 31, | |||||
2017 | 2016 | ||||
Federal statutory income tax rate | 35 | % | 35 | % | |
Income tax credits | (80 | ) | (57 | ) | |
State income tax, net of federal income tax benefit | 2 | 5 | |||
Effects of ratemaking | (12 | ) | (12 | ) | |
Other, net | 1 | — | |||
Effective income tax rate | (54 | )% | (29 | )% | |
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.
Berkshire Hathaway includes BHE and subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, MidAmerican Energy's provision for income taxes has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income taxes are remitted to or received from BHE. MidAmerican Energy received net cash payments for income taxes from BHE totaling $- million and $4 million for the three-month periods ended March 31, 2017 and 2016, respectively.
(6) | Employee Benefit Plans |
MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.
Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Pension: | |||||||
Service cost | $ | 2 | $ | 3 | |||
Interest cost | 8 | 8 | |||||
Expected return on plan assets | (11 | ) | (11 | ) | |||
Net periodic benefit credit | $ | (1 | ) | $ | — | ||
Other postretirement: | |||||||
Service cost | $ | 1 | $ | 1 | |||
Interest cost | 2 | 2 | |||||
Expected return on plan assets | (3 | ) | (3 | ) | |||
Net amortization | (1 | ) | (1 | ) | |||
Net periodic benefit credit | $ | (1 | ) | $ | (1 | ) | |
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Employer contributions to the pension and other postretirement benefit plans are expected to be $8 million and $1 million, respectively, during 2017. As of March 31, 2017, $2 million and $- million of contributions had been made to the pension and other postretirement benefit plans, respectively.
(7) | Fair Value Measurements |
The carrying value of MidAmerican Energy's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
• | Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that MidAmerican Energy has the ability to access at the measurement date. |
• | Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs). |
• | Level 3 — Unobservable inputs reflect MidAmerican Energy's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. MidAmerican Energy develops these inputs based on the best information available, including its own data. |
The following table presents MidAmerican Energy's assets and liabilities recognized on the Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements | ||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(1) | Total | ||||||||||||||||
As of March 31, 2017: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | — | $ | 1 | $ | 1 | $ | (1 | ) | $ | 1 | |||||||||
Money market mutual funds(2) | 490 | — | — | — | 490 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 163 | — | — | — | 163 | |||||||||||||||
International government obligations | — | 4 | — | — | 4 | |||||||||||||||
Corporate obligations | — | 35 | — | — | 35 | |||||||||||||||
Municipal obligations | — | 2 | — | — | 2 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 1 | — | — | 1 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 263 | — | — | — | 263 | |||||||||||||||
International companies | 7 | — | — | — | 7 | |||||||||||||||
Investment funds | 14 | — | — | — | 14 | |||||||||||||||
$ | 937 | $ | 43 | $ | 1 | $ | (1 | ) | $ | 980 | ||||||||||
Liabilities - commodity derivatives | $ | (1 | ) | $ | (2 | ) | $ | — | $ | 1 | $ | (2 | ) | |||||||
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Input Levels for Fair Value Measurements | ||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other(1) | Total | ||||||||||||||||
As of December 31, 2016: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Commodity derivatives | $ | — | $ | 9 | $ | 1 | $ | (2 | ) | $ | 8 | |||||||||
Money market mutual funds(2) | 1 | — | — | — | 1 | |||||||||||||||
Debt securities: | ||||||||||||||||||||
United States government obligations | 161 | — | — | — | 161 | |||||||||||||||
International government obligations | — | 3 | — | — | 3 | |||||||||||||||
Corporate obligations | — | 36 | — | — | 36 | |||||||||||||||
Municipal obligations | — | 2 | — | — | 2 | |||||||||||||||
Agency, asset and mortgage-backed obligations | — | 2 | — | — | 2 | |||||||||||||||
Equity securities: | ||||||||||||||||||||
United States companies | 250 | — | — | — | 250 | |||||||||||||||
International companies | 5 | — | — | — | 5 | |||||||||||||||
Investment funds | 9 | — | — | — | 9 | |||||||||||||||
$ | 426 | $ | 52 | $ | 1 | $ | (2 | ) | $ | 477 | ||||||||||
Liabilities - commodity derivatives | $ | — | $ | (3 | ) | $ | (3 | ) | $ | 3 | $ | (3 | ) | |||||||
(1) | Represents netting under master netting arrangements and a net cash collateral receivable of $- million and $1 million as of March 31, 2017 and December 31, 2016, respectively. |
(2) | Amounts are included in cash and cash equivalents and investments and restricted cash and investments on the Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Derivative contracts are recorded on the 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 MidAmerican Energy transacts. When quoted prices for identical contracts are not available, MidAmerican Energy uses forward price curves. Forward price curves represent MidAmerican Energy's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. MidAmerican Energy 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 MidAmerican Energy. Market price quotations are generally readily obtainable for the applicable term of MidAmerican Energy's outstanding derivative contracts; therefore, MidAmerican Energy'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, MidAmerican Energy 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, related volatility, counterparty creditworthiness and duration of contracts.
MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value and are 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. The fair value of MidAmerican Energy's investments in auction rate securities, where there is no current liquid market, is determined using pricing models based on available observable market data and MidAmerican Energy's judgment about the assumptions, including liquidity and nonperformance risks, which market participants would use when pricing the asset.
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The following table reconciles the beginning and ending balances of MidAmerican Energy's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
Commodity Derivatives | Auction Rate Securities | ||||||
2017: | |||||||
Beginning balance | $ | (2 | ) | $ | — | ||
Changes in fair value recognized in net regulatory assets | 2 | — | |||||
Settlements | 1 | — | |||||
Ending balance | $ | 1 | $ | — | |||
2016: | |||||||
Beginning balance | $ | (6 | ) | $ | 26 | ||
Transfer to affiliate | (4 | ) | — | ||||
Changes in fair value recognized in OCI | — | 1 | |||||
Changes in fair value recognized in net regulatory assets | (1 | ) | — | ||||
Redemptions | — | (1 | ) | ||||
Settlements | 7 | — | |||||
Ending balance | $ | (4 | ) | $ | 26 | ||
MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value of MidAmerican Energy's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Energy's long-term debt (in millions):
As of March 31, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
Long-term debt | $ | 4,894 | $ | 5,353 | $ | 4,301 | $ | 4,735 | |||||||
(8) Commitments and Contingencies
Construction Commitments
During the three-month period ended March 31, 2017, MidAmerican Energy entered into contracts totaling $138 million for the construction of wind-powered generating facilities in 2017.
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 air and water quality, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact its current and future operations. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations.
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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 requires refunds, plus interest, for the period from November 2013 through February 2015. Customer refunds relative to the first complaint occurred in February 2017. The FERC is expected to rule on the second complaint in 2017, 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 March 31, 2017, has accrued a $10 million liability for refunds under the second complaint of amounts collected under the higher ROE from February 2015 through May 2016.
(9) | Components of Accumulated Other Comprehensive Income (Loss), Net |
The following table shows the change in accumulated other comprehensive income (loss), net ("AOCI") by each component of other comprehensive income, net of applicable income taxes (in millions):
Unrealized | Unrealized | Accumulated | ||||||||||
Losses on | Losses | Other | ||||||||||
Available-For-Sale | on Cash Flow | Comprehensive | ||||||||||
Securities | Hedges | Loss, Net | ||||||||||
Balance, December 31, 2015 | $ | (3 | ) | $ | (27 | ) | $ | (30 | ) | |||
Other comprehensive income | 1 | — | 1 | |||||||||
Dividend | — | 27 | 27 | |||||||||
Balance at March 31, 2016 | $ | (2 | ) | $ | — | $ | (2 | ) | ||||
(10) | Segment Information |
MidAmerican Energy has identified two reportable segments: regulated electric and regulated 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 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 gas owned by others through its distribution system. Pricing for regulated electric and regulated 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.
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The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
Regulated electric | $ | 433 | $ | 399 | |||
Regulated gas | 262 | 226 | |||||
Total operating revenue | $ | 695 | $ | 625 | |||
Depreciation and amortization: | |||||||
Regulated electric | $ | 107 | $ | 99 | |||
Regulated gas | 10 | 11 | |||||
Total depreciation and amortization | $ | 117 | $ | 110 | |||
Operating income: | |||||||
Regulated electric | $ | 67 | $ | 57 | |||
Regulated gas | 40 | 43 | |||||
Total operating income | $ | 107 | $ | 100 | |||
As of | |||||||
March 31, 2017 | December 31, 2016 | ||||||
Total assets: | |||||||
Regulated electric | $ | 14,659 | $ | 14,113 | |||
Regulated gas | 1,313 | 1,345 | |||||
Other | 1 | 1 | |||||
Total assets | $ | 15,973 | $ | 15,459 | |||
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Member of
MidAmerican Funding, LLC
Des Moines, Iowa
We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of March 31, 2017, and the related consolidated statements of operations, changes in equity, and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of MidAmerican Funding's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States) 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 Public Company Accounting Oversight Board (United States) 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.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries as of December 31, 2016, 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Des Moines, Iowa
May 5, 2017
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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 490 | $ | 15 | |||
Receivables, net | 246 | 287 | |||||
Income taxes receivable | 45 | 9 | |||||
Inventories | 242 | 264 | |||||
Other current assets | 28 | 35 | |||||
Total current assets | 1,051 | 610 | |||||
Property, plant and equipment, net | 12,877 | 12,835 | |||||
Goodwill | 1,270 | 1,270 | |||||
Regulatory assets | 1,186 | 1,161 | |||||
Investments and restricted cash and investments | 680 | 655 | |||||
Other assets | 197 | 216 | |||||
Total assets | $ | 17,261 | $ | 16,747 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)
(Amounts in millions)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
LIABILITIES AND MEMBER'S EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 239 | $ | 302 | |||
Accrued interest | 50 | 52 | |||||
Accrued property, income and other taxes | 103 | 138 | |||||
Note payable to affiliate | 39 | 31 | |||||
Short-term debt | — | 99 | |||||
Current portion of long-term debt | 350 | 250 | |||||
Other current liabilities | 149 | 160 | |||||
Total current liabilities | 930 | 1,032 | |||||
Long-term debt | 4,870 | 4,377 | |||||
Deferred income taxes | 3,595 | 3,568 | |||||
Regulatory liabilities | 870 | 883 | |||||
Asset retirement obligations | 518 | 510 | |||||
Other long-term liabilities | 290 | 291 | |||||
Total liabilities | 11,073 | 10,661 | |||||
Commitments and contingencies (Note 8) | |||||||
Member's equity: | |||||||
Paid-in capital | 1,679 | 1,679 | |||||
Retained earnings | 4,509 | 4,407 | |||||
Total member's equity | 6,188 | 6,086 | |||||
Total liabilities and member's equity | $ | 17,261 | $ | 16,747 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
Regulated electric | $ | 433 | $ | 399 | |||
Regulated gas and other | 263 | 227 | |||||
Total operating revenue | 696 | 626 | |||||
Operating costs and expenses: | |||||||
Cost of fuel, energy and capacity | 102 | 92 | |||||
Cost of gas sold and other | 172 | 135 | |||||
Operations and maintenance | 167 | 161 | |||||
Depreciation and amortization | 117 | 110 | |||||
Property and other taxes | 31 | 28 | |||||
Total operating costs and expenses | 589 | 526 | |||||
Operating income | 107 | 100 | |||||
Other income and (expense): | |||||||
Interest expense | (59 | ) | (54 | ) | |||
Allowance for borrowed funds | 2 | 1 | |||||
Allowance for equity funds | 6 | 4 | |||||
Other, net | 6 | 3 | |||||
Total other income and (expense) | (45 | ) | (46 | ) | |||
Income before income tax benefit | 62 | 54 | |||||
Income tax benefit | (40 | ) | (19 | ) | |||
Net income | $ | 102 | $ | 73 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts in millions)
Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Loss, Net | Total Equity | ||||||||||||
Balance, December 31, 2015 | $ | 1,679 | $ | 3,876 | $ | (30 | ) | $ | 5,525 | ||||||
Net income | — | 73 | — | 73 | |||||||||||
Other comprehensive loss | — | — | 1 | 1 | |||||||||||
Transfer to affiliate | — | — | 27 | 27 | |||||||||||
Other equity transactions | — | (1 | ) | — | (1 | ) | |||||||||
Balance, March 31, 2016 | $ | 1,679 | $ | 3,948 | $ | (2 | ) | $ | 5,625 | ||||||
Balance, December 31, 2016 | $ | 1,679 | $ | 4,407 | $ | — | $ | 6,086 | |||||||
Net income | — | 102 | — | 102 | |||||||||||
Balance, March 31, 2017 | $ | 1,679 | $ | 4,509 | $ | — | $ | 6,188 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
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MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 102 | $ | 73 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 117 | 110 | |||||
Deferred income taxes and amortization of investment tax credits | 13 | 11 | |||||
Changes in other assets and liabilities | 10 | 11 | |||||
Other, net | (6 | ) | (13 | ) | |||
Changes in other operating assets and liabilities: | |||||||
Receivables, net | 41 | 31 | |||||
Inventories | 22 | (1 | ) | ||||
Derivative collateral, net | — | 2 | |||||
Contributions to pension and other postretirement benefit plans, net | (3 | ) | (2 | ) | |||
Accounts payable | 2 | 4 | |||||
Accrued property, income and other taxes, net | (73 | ) | (51 | ) | |||
Other current assets and liabilities | (11 | ) | (12 | ) | |||
Net cash flows from operating activities | 214 | 163 | |||||
Cash flows from investing activities: | |||||||
Utility construction expenditures | (238 | ) | (332 | ) | |||
Purchases of available-for-sale securities | (40 | ) | (34 | ) | |||
Proceeds from sales of available-for-sale securities | 35 | 29 | |||||
Other, net | 7 | (2 | ) | ||||
Net cash flows from investing activities | (236 | ) | (339 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from long-term debt | 843 | — | |||||
Repayments of long-term debt | (255 | ) | (4 | ) | |||
Net change in note payable to affiliate | 8 | 9 | |||||
Net (repayments of) proceeds from short-term debt | (99 | ) | 70 | ||||
Net cash flows from financing activities | 497 | 75 | |||||
Net change in cash and cash equivalents | 475 | (101 | ) | ||||
Cash and cash equivalents at beginning of period | 15 | 103 | |||||
Cash and cash equivalents at end of period | $ | 490 | $ | 2 | |||
The accompanying notes are an integral part of these consolidated financial statements.
88
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 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 March 31, 2017, and for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month periods ended March 31, 2017, 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, 2016, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2017.
(2) | New Accounting Pronouncements |
Refer to Note 2 of MidAmerican Energy's Notes to Financial Statements.
(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 March 31, 2017 and December 31, 2016, nonregulated property gross of $22 million, related accumulated depreciation and amortization of $9 million, and construction work-in-progress of $1 million, which consisted primarily of a corporate aircraft owned by MHC.
(4) Recent Financing Transactions
Refer to Note 4 of MidAmerican Energy's Notes to Financial Statements.
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(5) | 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 | |||||
Ended March 31, | |||||
2017 | 2016 | ||||
Federal statutory income tax rate | 35 | % | 35 | % | |
Income tax credits | (87 | ) | (62 | ) | |
State income tax, net of federal income tax benefit | 2 | 5 | |||
Effects of ratemaking | (13 | ) | (14 | ) | |
Other, net | (2 | ) | 1 | ||
Effective income tax rate | (65 | )% | (35 | )% | |
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.
Berkshire Hathaway includes BHE and subsidiaries in its United States federal income tax return. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income taxes have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income taxes are remitted to or received from BHE. MidAmerican Funding received net cash payments for income taxes from BHE totaling $- million and $4 million for the three-month periods ended March 31, 2017 and 2016, respectively.
(6) | Employee Benefit Plans |
Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.
(7) | Fair Value Measurements |
Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of MidAmerican Funding's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of MidAmerican Funding's long-term debt (in millions):
As of March 31, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
Long-term debt | $ | 5,220 | $ | 5,781 | $ | 4,627 | $ | 5,164 | |||||||
(8) Commitments and Contingencies
MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.
Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.
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(9) | Components of Accumulated Other Comprehensive Income (Loss), Net |
Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.
(10) Segment Information
MidAmerican Funding has identified two reportable segments: regulated electric and regulated 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 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 gas owned by others through its distribution system. Pricing for regulated electric and regulated gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in the tables below consists of the financial results and assets of nonregulated operations, MHC and MidAmerican Funding.
The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Operating revenue: | |||||||
Regulated electric | $ | 433 | $ | 399 | |||
Regulated gas | 262 | 226 | |||||
Other | 1 | 1 | |||||
Total operating revenue | $ | 696 | $ | 626 | |||
Depreciation and amortization: | |||||||
Regulated electric | $ | 107 | $ | 99 | |||
Regulated gas | 10 | 11 | |||||
Total depreciation and amortization | $ | 117 | $ | 110 | |||
Operating income: | |||||||
Regulated electric | $ | 67 | $ | 57 | |||
Regulated gas | 40 | 43 | |||||
Total operating income | $ | 107 | $ | 100 | |||
As of | |||||||
March 31, 2017 | December 31, 2016 | ||||||
Total assets(1): | |||||||
Regulated electric | $ | 15,850 | $ | 15,304 | |||
Regulated gas | 1,392 | 1,424 | |||||
Other | 19 | 19 | |||||
Total assets | $ | 17,261 | $ | 16,747 | |||
(1) | Total assets by reportable segment reflect the assignment of goodwill to applicable reporting units. |
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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 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 First Quarter of 2017 and 2016
Overview
MidAmerican Energy -
MidAmerican Energy's net income for the first quarter of 2017 was $105 million, an increase of $29 million, or 38%, compared to 2016 due to higher electric margins of $24 million and higher recognized production tax credits of $21 million, partially offset by higher operations and maintenance expenses of $6 million, higher depreciation and amortization of $7 million and higher property and other taxes of $3 million. Electric margins reflect higher wholesale revenue from higher sales prices and volumes and higher retail customer volumes from industrial growth, partially offset by higher purchased electricity and coal costs.
MidAmerican Funding -
MidAmerican Funding's net income for the first quarter of 2017 was $102 million, an increase of $29 million, or 40%, compared to 2016. The increase was due to the changes in MidAmerican Energy's earnings discussed above.
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Regulated Electric Gross Margin
A comparison of key operating results related to regulated electric gross margin is as follows:
First Quarter | ||||||||||||||
2017 | 2016 | Change | ||||||||||||
Gross margin (in millions): | ||||||||||||||
Operating revenue | $ | 433 | $ | 399 | $ | 34 | 9 | % | ||||||
Cost of fuel, energy and capacity | 102 | 92 | 10 | 11 | ||||||||||
Gross margin | $ | 331 | $ | 307 | $ | 24 | 8 | |||||||
Electricity Sales (GWh): | ||||||||||||||
Residential | 1,569 | 1,632 | (63 | ) | (4 | )% | ||||||||
Commercial | 927 | 948 | (21 | ) | (2 | ) | ||||||||
Industrial | 3,005 | 2,820 | 185 | 7 | ||||||||||
Other | 392 | 401 | (9 | ) | (2 | ) | ||||||||
Total retail | 5,893 | 5,801 | 92 | 2 | ||||||||||
Wholesale | 2,713 | 2,018 | 695 | 34 | ||||||||||
Total sales | 8,606 | 7,819 | 787 | 10 | ||||||||||
Average number of retail customers (in thousands) | 766 | 758 | 8 | 1 | % | |||||||||
Average revenue per MWh: | ||||||||||||||
Retail | $ | 60.36 | $ | 59.01 | $ | 1.35 | 2 | % | ||||||
Wholesale | $ | 22.43 | $ | 19.07 | $ | 3.36 | 18 | % | ||||||
Heating degree days | 2,663 | 2,842 | (179 | ) | (6 | )% | ||||||||
Sources of energy (GWh)(1): | ||||||||||||||
Coal | 2,962 | 2,911 | 51 | 2 | % | |||||||||
Nuclear | 932 | 936 | (4 | ) | — | |||||||||
Natural gas | 7 | 28 | (21 | ) | (75 | ) | ||||||||
Wind and other(2) | 3,784 | 3,131 | 653 | 21 | ||||||||||
Total energy generated | 7,685 | 7,006 | 679 | 10 | ||||||||||
Energy purchased | 1,076 | 966 | 110 | 11 | ||||||||||
Total | 8,761 | 7,972 | 789 | 10 | ||||||||||
(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. |
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Regulated electric gross margin increased $24 million for the first quarter of 2017 compared to 2016 primarily due to:
(1) | Higher wholesale gross margin of $21 million primarily due to higher margins per unit on higher sales volumes enabled by greater availability of lower cost generation; |
(2) | Higher retail gross margin of $4 million due to - |
• | an increase of $7 million from higher recoveries through bill riders; |
• | an increase of $7 million primarily from non-weather-related usage factors, including higher industrial sales volumes; |
• | a decrease of $9 million from higher retail energy costs primarily due to higher purchased power costs and a higher average cost of fuel for generation; and |
• | a decrease of $2 million from the impact of warmer temperatures; partially offset by |
(3) | Lower Multi-Value Projects ("MVPs") transmission revenue of $1 million due to refund accruals. |
Regulated Gas Gross Margin
A comparison of key operating results related to regulated gas gross margin is as follows:
First Quarter | ||||||||||||||
2017 | 2016 | Change | ||||||||||||
Gross margin (in millions): | ||||||||||||||
Operating revenue | $ | 262 | $ | 226 | $ | 36 | 16 | % | ||||||
Cost of gas sold | 172 | 135 | 37 | 27 | ||||||||||
Gross margin | $ | 90 | $ | 91 | $ | (1 | ) | (1 | ) | |||||
Natural gas throughput (000's Dth): | ||||||||||||||
Residential | 21,118 | 22,328 | (1,210 | ) | (5) | % | ||||||||
Commercial | 10,269 | 10,822 | (553 | ) | (5 | ) | ||||||||
Industrial | 1,483 | 1,595 | (112 | ) | (7 | ) | ||||||||
Other | 21 | 19 | 2 | 11 | ||||||||||
Total retail sales | 32,891 | 34,764 | (1,873 | ) | (5 | ) | ||||||||
Wholesale sales | 12,599 | 11,783 | 816 | 7 | ||||||||||
Total sales | 45,490 | 46,547 | (1,057 | ) | (2 | ) | ||||||||
Gas transportation service | 25,359 | 24,065 | 1,294 | 5 | ||||||||||
Total gas throughput | 70,849 | 70,612 | 237 | — | ||||||||||
Average number of retail customers (in thousands) | 748 | 742 | 6 | 1 | % | |||||||||
Average revenue per retail Dth sold | $ | 6.54 | $ | 5.55 | $ | 0.99 | 18 | % | ||||||
Average cost of natural gas per retail Dth sold | $ | 4.11 | $ | 3.22 | $ | 0.89 | 28 | % | ||||||
Combined retail and wholesale average cost of natural gas per Dth sold | $ | 3.77 | $ | 2.90 | $ | 0.87 | 30 | % | ||||||
Heating degree days | 2,809 | 2,972 | (163 | ) | (5) | % | ||||||||
Regulated gas revenue includes purchased gas adjustment clauses through which MidAmerican Energy is allowed to recover the cost of gas sold from its retail gas utility customers. Consequently, fluctuations in the cost of gas sold do not directly affect gross margin or net income because regulated gas revenue reflects comparable fluctuations through the purchased gas adjustment clauses. For the first quarter of 2017, MidAmerican Energy's combined retail and wholesale average per-unit cost of gas sold increased 30%, resulting in an increase of $40 million in gas revenue and cost of gas sold compared to 2016. Additionally, higher gas wholesale sales increased revenue and cost of gas sold but did not affect regulated gas gross margin.
Regulated gas gross margin decreased $1 million for the first quarter of 2017 compared to 2016 due to lower retail sales volumes from warmer winter temperatures, partially offset by higher demand-side management ("DSM") recoveries.
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Operating Costs and Expenses
MidAmerican Energy -
Operations and maintenance increased $6 million for the first quarter of 2017 compared to 2016 primarily due to $4 million of higher DSM program costs, which is offset in operating revenue, and $3 million of higher wind-powered generation maintenance from additional wind turbines.
Depreciation and amortization increased $7 million for the first quarter of 2017 compared to 2016 due to utility plant additions, including wind-powered generating facilities placed in-service in the second half of 2016, and an accrual for an Iowa regulatory arrangement, partially offset by $9 million from lower depreciation rates implemented in December 2016
Other Income and (Expense)
MidAmerican Energy -
Interest expense increased $4 million for the first quarter of 2017 compared to 2016 due to higher interest expense from the issuance of $850 million of first mortgage bonds in February 2017, partially offset by the redemption of a $250 million of 5.95% Senior Notes in February 2017.
Allowance for borrowed and equity funds increased $3 million for the first quarter of 2017 compared to 2016 primarily due to higher construction work-in-progress balances related to wind-powered generation.
Other, net increased $3 million for the first quarter of 2017 compared to 2016 due to higher returns on corporate-owned life insurance policies.
Income Tax Benefit
MidAmerican Energy -
MidAmerican Energy's income tax benefit increased $20 million for the first quarter of 2017 compared to 2016, and the effective tax rate was (54)% for 2017 and (29)% for 2016. The change in the effective tax rate was substantially due to an increase in recognized production tax credits, partially offset by a higher pre-tax income.
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 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 were placed in service.
MidAmerican Funding -
MidAmerican Funding's income tax benefit increased $21 million for the first quarter of 2017 compared to 2016, and the effective tax rate was (65)% for 2017 and (35)% for 2016. The change in the effective tax rate was principally due to the factors discussed for MidAmerican Energy.
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Liquidity and Capital Resources
As of March 31, 2017, MidAmerican Energy's total net liquidity was $874 million consisting of $489 million of cash and cash equivalents and $605 million of credit facilities reduced by $220 million of the credit facilities reserved to support MidAmerican Energy's variable-rate tax-exempt bond obligations. As of March 31, 2017, MidAmerican Funding's total net liquidity was $879 million, including MHC Inc.'s $4 million credit facility.
Operating Activities
MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016, were $222 million and $172 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016, were $214 million and $163 million, respectively. Cash flows from operating activities increased primarily due to higher gross margins for MidAmerican Energy's regulated electric business and a decrease in natural gas inventory.
In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Production tax credits were extended and phased-out for wind power and other forms of non-solar renewable energy projects that begin construction before the end of 2019. Production tax credits are maintained at the following levels for projects for which construction begins before the end of the respective year as follows: at full value for 2016, at 80% of present value for 2017, at 60% of present value for 2018, and 40% of present value for 2019. As a result of PATH, MidAmerican Energy's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in service through 2019 and production tax credits earned on qualifying wind projects through 2029.
The timing of MidAmerican Energy's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
MidAmerican Energy's net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016, were $(236) million and $(340) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016, were $(236) million and $(339) million, respectively. Net cash flows from investing activities consist almost entirely of utility construction expenditures, which decreased for the first three months of 2017 compared to 2016 due to lower expenditures for wind-powered generation construction. Purchases and proceeds related to available-for-sale securities primarily consist of activity within the Quad Cities Generating Station nuclear decommissioning trust.
Financing Activities
MidAmerican Energy's net cash flows from financing activities for the three-month periods ended March 31, 2017 and 2016 were $489 million and $66 million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2017 and 2016, were $497 million and $75 million, respectively. In February 2017, MidAmerican Energy issued $375 million of its 3.10% First Mortgage Bonds due May 2027 and $475 million of its 3.95% First Mortgage Bonds due August 2047. An amount equal to the net proceeds was used to finance capital expenditures, disbursed during the period from February 2, 2016 to February 1, 2017, with respect to investments in MidAmerican Energy's 551-megawatt Wind X and 2,000-megawatt Wind XI projects, which were previously financed with MidAmerican Energy's general funds. In February 2017, MidAmerican Energy redeemed in full through optional redemption its $250 million of 5.95% Senior Notes due July 2017. In January 2016, MidAmerican Energy repaid $4 million of variable-rate tax-exempt pollution control refunding revenue bonds due January 2016. Through its commercial paper program, MidAmerican Energy made payments totaling $99 million in 2017 and received $70 million in 2016. MidAmerican Funding received $8 million and $9 million in 2017 and 2016, respectively, through its note payable with BHE.
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Debt Authorizations and Related Matters
MidAmerican Energy has authority from the FERC to issue through February 28, 2019, commercial paper and bank notes aggregating $905 million at interest rates not to exceed the applicable London Interbank Offered Rate ("LIBOR") plus a spread of up to 400 basis points. MidAmerican Energy has a $600 million unsecured credit facility expiring in March 2018. MidAmerican Energy may request that the banks extend the credit facility up to two years. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on LIBOR or a base rate, at MidAmerican Energy's option, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.
MidAmerican Energy currently has an effective registration statement with the United States Securities and Exchange Commission to issue an indeterminate amount of long-term debt securities through September 16, 2018. Additionally, MidAmerican Energy has authorization from the Illinois Commerce Commission to issue up to an aggregate of $500 million of additional long-term debt securities, of which $350 million expires March 15, 2018, and $150 million expires September 22, 2018.
In conjunction with the March 1999 merger, MidAmerican Energy committed to the IUB to use commercially reasonable efforts to maintain an investment grade rating on its long-term debt and to maintain its common equity level above 42% of total capitalization unless circumstances beyond its control result in the common equity level decreasing to below 39% of total capitalization. MidAmerican Energy must seek the approval of the IUB of a reasonable utility capital structure if MidAmerican Energy's common equity level decreases below 42% of total capitalization, unless the decrease is beyond the control of MidAmerican Energy. MidAmerican Energy is also required to seek the approval of the IUB if MidAmerican Energy's equity level decreases to below 39%, even if the decrease is due to circumstances beyond the control of MidAmerican Energy. If MidAmerican Energy's common equity level were to drop below the required thresholds, MidAmerican Energy's ability to issue debt could be restricted. As of March 31, 2017, MidAmerican Energy's common equity ratio was 54% computed on a basis consistent with its commitment.
Future Uses of Cash
MidAmerican Energy and MidAmerican Funding have available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.
Utility Construction Expenditures
MidAmerican Energy's primary need for capital is utility construction 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.
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MidAmerican Energy's forecast utility construction expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $1.8 billion for 2017 and include:
• | $731 million for the construction of 2,000 MW (nominal ratings) of wind-powered generating facilities expected to be placed in service in 2017 through 2019. 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 expected to be placed in service in 2017 through 2019. The ratemaking principles establish a cost cap of $3.6 billion, including AFUDC, and 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. The cost cap ensures that as long as total costs are below the cap, the investment will be deemed prudent in any future Iowa rate proceeding. Additionally, the ratemaking principles modify the revenue sharing mechanism currently in effect. The revised sharing mechanism will be effective in 2018 and will be triggered each year by actual equity returns above the weighted average return on equity for MidAmerican Energy calculated annually. Pursuant to the change in revenue sharing, MidAmerican Energy will share 100% of the revenue in excess of this trigger with customers. Such revenue sharing will reduce coal and nuclear generation rate base, which is intended to mitigate future base rate increases. Each of these projects is expected to qualify for 100% of production tax credits currently available. |
• | $297 million for the repowering of certain existing wind-powered generating facilities in Iowa. This project entails the replacement of significant components of the oldest turbines in MidAmerican Energy’s fleet. The energy production from such repowered facilities is expected to qualify for 100% of the federal production tax credits available for ten years following completion. |
• | $40 million for transmission MVP investments. MidAmerican Energy has approval from the Midcontinent Independent System Operator, Inc. for the construction of four MVPs located in Iowa and Illinois, which, when complete, will add approximately 250 miles of 345 kV transmission line to MidAmerican Energy's transmission system. |
• | 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 March 31, 2017, 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, 2016, other than contracts totaling $138 million for the construction of wind-powered generating facilities in 2017.
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.
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 will go into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits 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 in the Northern District of Illinois against the Illinois Power Agency alleging that the state’s zero emission credit program violates certain provisions of the U.S. Constitution. Both complaints argue that the Illinois zero emission credit program will distort the FERC’s energy and capacity market auction system of setting wholesale prices. As majority owner and operator of Quad Cities Station, Exelon has intervened in both suits and has filed motions to dismiss in both matters. These motions are currently pending.
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On January 9, 2017 the Electric Power Supply Association filed two requests with the FERC seeking to expand Minimum Price Offer 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 timing of the FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
Environmental Laws and Regulations
MidAmerican Energy is subject to federal, state and local laws and regulations regarding air and water quality, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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 "Liquidity and Capital Resources" for discussion of MidAmerican Energy's forecast environmental-related capital expenditures.
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.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting MidAmerican Energy and MidAmerican Funding, refer to Note 2 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
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, 2016. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2016.
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Nevada Power Company and its subsidiaries
Consolidated Financial Section
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PART I
Item 1. | Financial Statements |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Nevada Power Company
Las Vegas, Nevada
We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of March 31, 2017, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of Nevada Power's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of Nevada Power Company and subsidiaries as of December 31, 2016, 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
May 5, 2017
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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 79 | $ | 279 | |||
Accounts receivable, net | 182 | 243 | |||||
Inventories | 66 | 73 | |||||
Regulatory assets | 42 | 20 | |||||
Other current assets | 52 | 38 | |||||
Total current assets | 421 | 653 | |||||
Property, plant and equipment, net | 6,834 | 6,997 | |||||
Regulatory assets | 1,146 | 1,000 | |||||
Other assets | 121 | 39 | |||||
Total assets | $ | 8,522 | $ | 8,689 | |||
LIABILITIES AND SHAREHOLDER'S EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 167 | $ | 187 | |||
Accrued interest | 39 | 50 | |||||
Accrued property, income and other taxes | 75 | 93 | |||||
Regulatory liabilities | 41 | 37 | |||||
Current portion of long-term debt and financial and capital lease obligations | 19 | 17 | |||||
Customer deposits | 77 | 78 | |||||
Other current liabilities | 37 | 39 | |||||
Total current liabilities | 455 | 501 | |||||
Long-term debt and financial and capital lease obligations | 2,971 | 3,049 | |||||
Regulatory liabilities | 414 | 416 | |||||
Deferred income taxes | 1,495 | 1,474 | |||||
Other long-term liabilities | 280 | 277 | |||||
Total liabilities | 5,615 | 5,717 | |||||
Commitments and contingencies (Note 9) | |||||||
Shareholder's equity: | |||||||
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding | — | — | |||||
Other paid-in capital | 2,308 | 2,308 | |||||
Retained earnings | 602 | 667 | |||||
Accumulated other comprehensive loss, net | (3 | ) | (3 | ) | |||
Total shareholder's equity | 2,907 | 2,972 | |||||
Total liabilities and shareholder's equity | $ | 8,522 | $ | 8,689 | |||
The accompanying notes are an integral part of the consolidated financial statements. | |||||||
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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | ||||||||
Ended March 31, | ||||||||
2017 | 2016 | |||||||
Operating revenue | $ | 392 | $ | 399 | ||||
Operating costs and expenses: | ||||||||
Cost of fuel, energy and capacity | 165 | 168 | ||||||
Operating and maintenance | 89 | 99 | ||||||
Depreciation and amortization | 76 | 75 | ||||||
Property and other taxes | 10 | 11 | ||||||
Total operating costs and expenses | 340 | 353 | ||||||
Operating income | 52 | 46 | ||||||
Other income (expense): | ||||||||
Interest expense | (44 | ) | (48 | ) | ||||
Allowance for borrowed funds | — | 1 | ||||||
Allowance for equity funds | 1 | 1 | ||||||
Other, net | 6 | 5 | ||||||
Total other income (expense) | (37 | ) | (41 | ) | ||||
Income before income tax expense | 15 | 5 | ||||||
Income tax expense | 5 | 2 | ||||||
Net income | $ | 10 | $ | 3 | ||||
The accompanying notes are an integral part of these consolidated financial statements. | ||||||||
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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
Accumulated | |||||||||||||||||||||||
Other | Other | Total | |||||||||||||||||||||
Common Stock | Paid-in | Retained | Comprehensive | Shareholder's | |||||||||||||||||||
Shares | Amount | Capital | Earnings | Loss, Net | Equity | ||||||||||||||||||
Balance, December 31, 2015 | 1,000 | $ | — | $ | 2,308 | $ | 858 | $ | (3 | ) | $ | 3,163 | |||||||||||
Net income | — | — | — | 3 | — | 3 | |||||||||||||||||
Balance, March 31, 2016 | 1,000 | $ | — | $ | 2,308 | $ | 861 | $ | (3 | ) | $ | 3,166 | |||||||||||
Balance, December 31, 2016 | 1,000 | $ | — | $ | 2,308 | $ | 667 | $ | (3 | ) | $ | 2,972 | |||||||||||
Net income | — | — | — | 10 | — | 10 | |||||||||||||||||
Dividends declared | — | — | — | (75 | ) | — | (75 | ) | |||||||||||||||
Balance, March 31, 2017 | 1,000 | $ | — | $ | 2,308 | $ | 602 | $ | (3 | ) | $ | 2,907 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements. | |||||||||||||||||||||||
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NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 10 | $ | 3 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 76 | 75 | |||||
Deferred income taxes and amortization of investment tax credits | 22 | 2 | |||||
Allowance for equity funds | (1 | ) | (1 | ) | |||
Changes in regulatory assets and liabilities | 3 | 7 | |||||
Deferred energy | (25 | ) | 23 | ||||
Amortization of deferred energy | 3 | (14 | ) | ||||
Other, net | (2 | ) | — | ||||
Changes in other operating assets and liabilities: | |||||||
Accounts receivable and other assets | 51 | 47 | |||||
Inventories | 7 | — | |||||
Accrued property, income and other taxes | (26 | ) | (1 | ) | |||
Accounts payable and other liabilities | (29 | ) | (18 | ) | |||
Net cash flows from operating activities | 89 | 123 | |||||
Cash flows from investing activities: | |||||||
Capital expenditures | (58 | ) | (98 | ) | |||
Acquisitions | (77 | ) | — | ||||
Net cash flows from investing activities | (135 | ) | (98 | ) | |||
Cash flows from financing activities: | |||||||
Repayments of long-term debt and financial and capital lease obligations | (79 | ) | (214 | ) | |||
Dividends paid | (75 | ) | — | ||||
Net cash flows from financing activities | (154 | ) | (214 | ) | |||
Net change in cash and cash equivalents | (200 | ) | (189 | ) | |||
Cash and cash equivalents at beginning of period | 279 | 536 | |||||
Cash and cash equivalents at end of period | $ | 79 | $ | 347 | |||
The accompanying notes are an integral part of these consolidated financial statements. | |||||||
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NEVADA POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Organization and Operations
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 March 31, 2017 and for the three-month periods ended March 31, 2017 and 2016. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month period ended March 31, 2017 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, 2016 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2017.
(2) New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
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In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB 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 in 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Nevada Power is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Nevada Power currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Nevada Power has the right to invoice as it corresponds directly with the value to the customer of Nevada Power’s performance to date. Nevada Power's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by customer class.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of | |||||||||
Depreciable Life | March 31, | December 31, | |||||||
2017 | 2016 | ||||||||
Utility plant: | |||||||||
Generation | 30 - 55 years | $ | 3,583 | $ | 4,271 | ||||
Distribution | 20 - 65 years | 3,248 | 3,231 | ||||||
Transmission | 45 - 65 years | 1,860 | 1,846 | ||||||
General and intangible plant | 5 - 65 years | 764 | 738 | ||||||
Utility plant | 9,455 | 10,086 | |||||||
Accumulated depreciation and amortization | (2,715 | ) | (3,205 | ) | |||||
Utility plant, net | 6,740 | 6,881 | |||||||
Other non-regulated, net of accumulated depreciation and amortization | 45 years | 3 | 2 | ||||||
Plant, net | 6,743 | 6,883 | |||||||
Construction work-in-progress | 91 | 114 | |||||||
Property, plant and equipment, net | $ | 6,834 | $ | 6,997 | |||||
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Acquisitions
In April 2017, Nevada Power purchased the remaining 25% interest in the Silverhawk natural gas-fueled generating facility for $77 million. The PUCN approved the purchase of the facility in Nevada Power’s triennial Integrated Resource Plan filing in December 2015. Nevada Power paid the purchase price in March 2017 and recorded the transaction in other long-term assets on the Consolidated Balance Sheet and in acquisitions within the investing section of the Consolidated Statement of Cash Flows.
(4) 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 Public Utilities Commission of Nevada ("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, energy and capacity in future time periods.
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 applicants' 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 May 2015, Wynn Las Vegas, LLC ("Wynn"), filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In December 2015, the PUCN granted the application subject to conditions, including paying an impact fee, on-going charges and receiving approval for specific alternative energy providers and terms. In December 2015, Wynn filed a petition for reconsideration. In January 2016, the PUCN granted reconsideration and updated some of the terms, including removing a limitation related to energy purchased indirectly from NV Energy. In September 2016, Wynn paid impact fees totaling $15 million. In October 2016, Wynn became a distribution only service customer and started procuring energy from another energy supplier. In April 2017, Wynn filed a motion with the PUCN seeking relief from the January 2016 order and requested the PUCN adopt an alternative impact fee and revise on-going charges associated with retirement of assets and high cost renewable contracts.
In September 2016, Switch, Ltd. ("Switch"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions, including paying an impact fee to Nevada Power. In March 2017, Switch provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.
In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Nevada Power, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Nevada Power. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.
Emissions Reduction and Capacity Replacement Plan ("ERCR Plan")
In March 2017, Nevada Power retired Reid Gardner Unit 4, a 257-MW coal-fueled generating facility. The early retirement was approved by the PUCN in December 2016 as a part of Nevada Power's second amendment to the ERCR Plan. The remaining net book value of $151 million was moved from property, plant and equipment, net to noncurrent regulatory assets on the Consolidated Balance Sheet as of March 31, 2017 in compliance with the ERCR Plan. Refer to Note 9 for additional information on the ERCR Plan.
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(5) Recent Financing Transactions
In January 2017, Nevada Power (1) issued a notice to the bondholders for the repurchase of the remaining outstanding amounts of its $38 million Pollution Control Revenue Bonds Series 2006 and $38 million Pollution Control Revenue Bonds Series 2006A and (2) redeemed the Pollution Control Revenue Bonds Series 2006A aggregate principal amount outstanding plus accrued interest with the use of cash on hand. In February 2017, Nevada Power redeemed the Pollution Control Revenue Bonds Series 2006 aggregate principal amount outstanding plus accrued interest with the use of cash on hand.
(6) 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 | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
Qualified Pension Plan - | |||||||
Other long-term liabilities | $ | (25 | ) | $ | (24 | ) | |
Non-Qualified Pension Plans: | |||||||
Other current liabilities | (1 | ) | (1 | ) | |||
Other long-term liabilities | (9 | ) | (9 | ) | |||
Other Postretirement Plans - | |||||||
Other long-term liabilities | (4 | ) | (4 | ) | |||
(7) Risk Management and Hedging Activities
Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity, natural gas and coal market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.
Nevada Power has established a risk management process that is designed to identify, assess, manage, mitigate, monitor and report each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.
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There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.
The following table, which excludes contracts that have been designated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the fair value of Nevada Power'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 | |||||||||||
Current | Long-term | |||||||||||
Liabilities | Liabilities | Total | ||||||||||
As of March 31, 2017 | ||||||||||||
Commodity liabilities(1) | $ | (7 | ) | $ | (7 | ) | $ | (14 | ) | |||
As of December 31, 2016 | ||||||||||||
Commodity liabilities(1) | $ | (7 | ) | $ | (7 | ) | $ | (14 | ) | |||
(1) | Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates and as of March 31, 2017 and December 31, 2016, a regulatory asset of $14 million was recorded related to the derivative liability of $14 million. |
Derivative Contract Volumes
The following table summarizes the net notional amounts of outstanding derivative contracts with indexed and fixed price terms that comprise the mark-to-market values (in millions):
As of | |||||||
Unit of | March 31, | December 31, | |||||
Measure | 2017 | 2016 | |||||
Electricity sales | Megawatt hours | (1 | ) | (2 | ) | ||
Natural gas purchases | Decatherms | 147 | 114 | ||||
Credit Risk
Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establish limits on the amount of unsecured credit to be extended to each counterparty and evaluate the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.
Collateral and Contingent Features
In accordance with industry practice, certain wholesale derivative contracts contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating agencies. These derivative contracts may either specifically provide rights to demand cash or other security in the event of a credit rating downgrade ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance," in the event of a material adverse change in creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2017, credit ratings from the three recognized credit rating agencies were investment grade.
The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features was $3 million and $2 million as of March 31, 2017 and December 31, 2016, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.
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(8) | Fair Value Measurements |
The carrying value of Nevada Power's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Nevada Power has various financial assets and liabilities that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
• | Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Nevada Power has the ability to access at the measurement date. |
• | Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs). |
• | Level 3 - Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including its own data. |
The following table presents Nevada Power's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
As of March 31, 2017 | |||||||||||||||
Assets: | |||||||||||||||
Money market mutual funds(1) | $ | 35 | $ | — | $ | — | $ | 35 | |||||||
Investment funds | 2 | — | — | 2 | |||||||||||
$ | 37 | $ | — | $ | — | $ | 37 | ||||||||
Liabilities - commodity derivatives | $ | — | $ | — | $ | (14 | ) | $ | (14 | ) | |||||
As of December 31, 2016 | |||||||||||||||
Assets: | |||||||||||||||
Money market mutual funds(1) | $ | 220 | $ | — | $ | — | $ | 220 | |||||||
Investment funds | 6 | — | — | 6 | |||||||||||
$ | 226 | $ | — | $ | — | $ | 226 | ||||||||
Liabilities - commodity derivatives | $ | — | $ | — | $ | (14 | ) | $ | (14 | ) | |||||
(1) | Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
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Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of March 31, 2017 and December 31, 2016, 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. Refer to Note 7 for further discussion regarding Nevada Power's risk management and hedging activities.
Nevada Power's investments in money market mutual funds and equity securities are accounted for as available-for- sale securities and 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 liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
Three-Month Periods | ||||||||
Ended March 31, | ||||||||
2017 | 2016 | |||||||
Beginning balance | $ | (14 | ) | $ | (22 | ) | ||
Changes in fair value recognized in regulatory assets | (1 | ) | (3 | ) | ||||
Settlements | 1 | 3 | ||||||
Ending balance | $ | (14 | ) | $ | (22 | ) | ||
Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Nevada Power's long‑term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Nevada Power's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of Nevada Power's long‑term debt (in millions):
As of March 31, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying | Fair | Carrying | Fair | ||||||||||||
Value | Value | Value | Value | ||||||||||||
Long-term debt | $ | 2,505 | $ | 2,952 | $ | 2,581 | $ | 3,040 | |||||||
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(9) | Commitments and Contingencies |
Environmental Laws and Regulations
Nevada Power is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.
Senate Bill 123
In June 2013, the Nevada State Legislature passed Senate Bill No. 123 ("SB 123"), which included the retirement of coal plants and replacing the capacity with renewable facilities and other generating facilities. In May 2014, Nevada Power filed its Emissions Reduction Capacity Replacement Plan ("ERCR Plan") in compliance with SB 123. In July 2015, Nevada Power filed an amendment to its ERCR Plan with the PUCN which was approved in September 2015. In June 2015, the Nevada State Legislature passed Assembly Bill No. 498, which modified the capacity replacement components of SB 123.
Consistent with the ERCR Plan, Nevada Power acquired a 272-MW natural gas co-generating facility in 2014, acquired a 210-MW natural gas peaking facility in 2014, constructed a 15-MW solar photovoltaic facility in 2015, contracted two renewable power purchase agreements with 100-MW solar photovoltaic generating facilities in 2015, contracted a renewable power purchase agreement with 100-MW solar photovoltaic generating facility in 2016 and acquired the remaining 130 MW, 25%, of the Silverhawk natural gas-fueled generating facility in April 2017, of which 54 MW were approved as part of the ERCR Plan. Nevada Power has the option to acquire 35 MW of nameplate renewable energy capacity in the future under the ERCR Plan, subject to PUCN approval. Nevada Power retired Reid Gardner Units 1, 2, and 3, 300 MW of coal-fueled generation, in 2014 and Reid Gardner Unit 4, 257 MW of coal-fueled generation, in March 2017. These transactions are related to Nevada Power's compliance with SB 123, resulting in the retirement of 812 MW of coal-fueled generation by 2019.
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.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
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 factors. This discussion should be read in conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the future could differ significantly from the historical results.
Results of Operations for the First Quarter of 2017 and 2016
Net income for the first quarter of 2017 was $10 million, an increase of $7 million compared to 2016 due to lower interest expense from the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in 2016, lower planned maintenance and other generating costs, and higher margins due to customers purchasing energy from alternative providers and becoming distribution only service customers.
Operating revenue and cost of fuel, energy and capacity are key drivers of Nevada Power's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to customers. Nevada Power believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful.
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A comparison of Nevada Power's key operating results is as follows:
First Quarter | |||||||||||||||
2017 | 2016 | Change | |||||||||||||
Gross margin (in millions): | |||||||||||||||
Operating revenue | $ | 392 | $ | 399 | $ | (7 | ) | (2 | ) | % | |||||
Cost of fuel, energy and capacity | 165 | 168 | (3 | ) | (2 | ) | |||||||||
Gross margin | $ | 227 | $ | 231 | $ | (4 | ) | (2 | ) | ||||||
GWh sold: | |||||||||||||||
Residential | 1,518 | 1,573 | (55 | ) | (3 | ) | % | ||||||||
Commercial | 974 | 984 | (10 | ) | (1 | ) | |||||||||
Industrial | 1,447 | 1,651 | (204 | ) | (12 | ) | |||||||||
Other | 49 | 49 | — | — | |||||||||||
Total fully bundled(1) | 3,988 | 4,257 | (269 | ) | (16 | ) | |||||||||
Distribution only service | 320 | 84 | 236 | * | |||||||||||
Total retail | 4,308 | 4,341 | (33 | ) | (1 | ) | |||||||||
Wholesale | 109 | 55 | 54 | 98 | |||||||||||
Total GWh sold | 4,417 | 4,396 | 21 | — | |||||||||||
Average number of retail customers (in thousands): | |||||||||||||||
Residential | 805 | 791 | 14 | 2 | % | ||||||||||
Commercial | 106 | 105 | 1 | 1 | |||||||||||
Industrial | 2 | 2 | — | — | |||||||||||
Total | 913 | 898 | 15 | 2 | |||||||||||
Average retail revenue per MWh: | |||||||||||||||
Fully bundled(1) | $ | 93.81 | $ | 91.27 | $ | 2.54 | 3 | % | |||||||
Heating degree days | 775 | 790 | (15 | ) | (2 | ) | % | ||||||||
Cooling degree days | 111 | 64 | 47 | 73 | % | ||||||||||
Sources of energy (GWh)(2): | |||||||||||||||
Natural gas | 2,460 | 3,111 | (651 | ) | (21 | ) | % | ||||||||
Coal | 506 | 185 | 321 | * | |||||||||||
Renewables | 16 | 8 | 8 | * | |||||||||||
Total energy generated | 2,982 | 3,304 | (322 | ) | (10 | ) | |||||||||
Energy purchased | 1,189 | 1,232 | (43 | ) | (3 | ) | |||||||||
Total | 4,171 | 4,536 | (365 | ) | (8 | ) | |||||||||
Average total cost of energy per MWh(3): | $ | 39.61 | $ | 37.11 | $ | 2.50 | 7 | % | |||||||
* Not meaningful
(1) | Fully bundled includes sales to customers for combined energy, transmission and distribution services. |
(2) | GWh amounts are net of energy used by the related generating facilities. |
(3) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
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Gross margin decreased $4 million, or 2%, for the first quarter of 2017 compared to 2016 due to:
• | $6 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense and |
• | $1 million in lower commercial and industrial retail revenue from customers purchasing energy from alternative providers and becoming distribution only service customers. |
The decrease in gross margin was offset by:
• | $2 million in higher other retail revenue primarily from amortization of impacts fees relating to customers becoming distribution only service customers and |
• | $1 million in higher transmission revenue primarily due to customers becoming distribution only service customers. |
Operating and maintenance decreased $10 million, or 10%, for the first quarter of 2017 compared to 2016 due to lower energy efficiency program costs, which are fully recovered in operating revenue, and lower planned maintenance and other generating costs.
Other income (expense) is favorable $4 million, or 10%, for the first quarter of 2017 compared to 2016 due to the redemption of $210 million Series M, 5.950% General and Refunding Mortgage Notes in 2016 and lower interest expense on deferred charges.
Liquidity and Capital Resources
As of March 31, 2017, Nevada Power's total net liquidity was $479 million consisting of $79 million in cash and cash equivalents and $400 million of a credit facility.
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016 were $89 million and $123 million, respectively. The change was due to decreased collections from customers from lower retail rates as a result of deferred energy adjustment mechanisms, an increase in operating costs and higher payments for fuel costs, offset by lower interest payments on long-term debt and lower payments for energy efficiency and renewable energy programs.
In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Nevada Power's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.
The timing of Nevada Power's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016 were $(135) million and $(98) million, respectively. The change was due to the acquisition of the remaining 25% in the Silverhawk generating station, partially offset by lower capital maintenance expenditures.
Financing Activities
Net cash flows from financing activities for the three-month periods ended March 31, 2017 and 2016 were $(154) million and $(214) million, respectively. The change was due to lower repayments of long-term debt, partially offset by higher dividends paid to NV Energy, Inc. in 2017.
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Ability to Issue Debt
Nevada Power's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of March 31, 2017, Nevada Power 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) refinancing authority up to $1.3 billion of long-term debt securities; and (3) maintain a revolving credit facility of up to $1.3 billion. Nevada Power's revolving credit facility contains a financial maintenance covenant which Nevada Power was in compliance with as of March 31, 2017.
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 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
Nevada Power 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, 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.
Nevada Power's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Three-Month Periods | Annual | ||||||||||
Ended March 31, | Forecast | ||||||||||
2016 | 2017 | 2017 | |||||||||
Distribution | $ | 26 | $ | 23 | $ | 101 | |||||
Transmission system investment | 11 | 3 | 14 | ||||||||
Other | 61 | 32 | 135 | ||||||||
Total | $ | 98 | $ | 58 | $ | 250 | |||||
Nevada Power's approved 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.
In April 2017, Nevada Power purchased the remaining 25% interest in the Silverhawk natural gas-fueled generating facility for $77 million. The PUCN approved the purchase of the facility in Nevada Power’s triennial Integrated Resource Plan filing in December 2015. Nevada Power paid the purchase price in March 2017 and recorded the transaction in other long-term assets on the Consolidated Balance Sheet and in acquisitions within the investing section of the Consolidated Statement of Cash Flows.
Contractual Obligations
As of March 31, 2017, 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, 2016.
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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 air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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 "Liquidity and Capital Resources" for discussion of Nevada Power's forecasted environmental-related capital expenditures.
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.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Nevada Power, refer to Note 2 of Notes to Consolidated Financial Statements in Nevada Power's Part I, Item 1 of this Form 10-Q.
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, 2016. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2016.
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Sierra Pacific Power Company and its subsidiaries
Consolidated Financial Section
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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
Las Vegas, Nevada
We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of March 31, 2017, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2017 and 2016. These interim financial statements are the responsibility of Sierra Pacific's management.
We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 Public Company Accounting Oversight Board (United States), 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.
Based on our reviews, we are not aware of any material modifications that should be made to such consolidated interim financial statements for them 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), the consolidated balance sheet of Sierra Pacific Power Company and subsidiaries as of December 31, 2016, 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 24, 2017, 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, 2016 is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.
/s/ Deloitte & Touche LLP
Las Vegas, Nevada
May 5, 2017
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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 5 | $ | 55 | |||
Accounts receivable, net | 93 | 117 | |||||
Inventories | 48 | 45 | |||||
Regulatory assets | 26 | 25 | |||||
Other current assets | 21 | 13 | |||||
Total current assets | 193 | 255 | |||||
Property, plant and equipment, net | 2,827 | 2,822 | |||||
Regulatory assets | 407 | 410 | |||||
Other assets | 8 | 6 | |||||
Total assets | $ | 3,435 | $ | 3,493 | |||
LIABILITIES AND SHAREHOLDER'S EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 77 | $ | 146 | |||
Accrued interest | 11 | 14 | |||||
Accrued property, income and other taxes | 11 | 10 | |||||
Regulatory liabilities | 40 | 69 | |||||
Short-term debt | 6 | — | |||||
Current portion of long-term debt and financial and capital lease obligations | 1 | 1 | |||||
Customer deposits | 17 | 16 | |||||
Other current liabilities | 15 | 12 | |||||
Total current liabilities | 178 | 268 | |||||
Long-term debt and financial and capital lease obligations | 1,152 | 1,152 | |||||
Regulatory liabilities | 222 | 221 | |||||
Deferred income taxes | 630 | 617 | |||||
Other long-term liabilities | 123 | 127 | |||||
Total liabilities | 2,305 | 2,385 | |||||
Commitments and contingencies (Note 7) | |||||||
Shareholder's equity: | |||||||
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding | — | — | |||||
Other paid-in capital | 1,111 | 1,111 | |||||
Retained earnings (deficit) | 20 | (2 | ) | ||||
Accumulated other comprehensive loss, net | (1 | ) | (1 | ) | |||
Total shareholder's equity | 1,130 | 1,108 | |||||
Total liabilities and shareholder's equity | $ | 3,435 | $ | 3,493 | |||
The accompanying notes are an integral part of the consolidated financial statements. | |||||||
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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
Three-Month Periods | ||||||||
Ended March 31, | ||||||||
2017 | 2016 | |||||||
Operating revenue: | ||||||||
Electric | $ | 159 | $ | 170 | ||||
Natural gas | 34 | 47 | ||||||
Total operating revenue | 193 | 217 | ||||||
Operating costs and expenses: | ||||||||
Cost of fuel, energy and capacity | 56 | 70 | ||||||
Natural gas purchased for resale | 16 | 30 | ||||||
Operating and maintenance | 41 | 41 | ||||||
Depreciation and amortization | 28 | 29 | ||||||
Property and other taxes | 6 | 6 | ||||||
Total operating costs and expenses | 147 | 176 | ||||||
Operating income | 46 | 41 | ||||||
Other income (expense): | ||||||||
Interest expense | (11 | ) | (16 | ) | ||||
Allowance for equity funds | 1 | 1 | ||||||
Other, net | 1 | 1 | ||||||
Total other income (expense) | (9 | ) | (14 | ) | ||||
Income before income tax expense | 37 | 27 | ||||||
Income tax expense | 13 | 10 | ||||||
Net income | $ | 24 | $ | 17 | ||||
The accompanying notes are an integral part of these consolidated financial statements. | ||||||||
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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
Accumulated | |||||||||||||||||||||||
Other | Retained | Other | Total | ||||||||||||||||||||
Common Stock | Paid-in | Earnings | Comprehensive | Shareholder's | |||||||||||||||||||
Shares | Amount | Capital | (Deficit) | Loss, Net | Equity | ||||||||||||||||||
Balance, December 31, 2015 | 1,000 | $ | — | $ | 1,111 | $ | (35 | ) | $ | — | $ | 1,076 | |||||||||||
Net income | — | — | — | 17 | — | 17 | |||||||||||||||||
Balance, March 31, 2016 | 1,000 | $ | — | $ | 1,111 | $ | (18 | ) | $ | — | $ | 1,093 | |||||||||||
Balance, December 31, 2016 | 1,000 | $ | — | $ | 1,111 | $ | (2 | ) | $ | (1 | ) | $ | 1,108 | ||||||||||
Net income | — | — | — | 24 | — | 24 | |||||||||||||||||
Dividends declared | — | — | — | (2 | ) | — | (2 | ) | |||||||||||||||
Balance, March 31, 2017 | 1,000 | $ | — | $ | 1,111 | $ | 20 | $ | (1 | ) | $ | 1,130 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements. | |||||||||||||||||||||||
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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts in millions)
Three-Month Periods | |||||||
Ended March 31, | |||||||
2017 | 2016 | ||||||
Cash flows from operating activities: | |||||||
Net income | $ | 24 | $ | 17 | |||
Adjustments to reconcile net income to net cash flows from operating activities: | |||||||
Depreciation and amortization | 28 | 29 | |||||
Allowance for equity funds | (1 | ) | (1 | ) | |||
Deferred income taxes and amortization of investment tax credits | 13 | 10 | |||||
Changes in regulatory assets and liabilities | 3 | (3 | ) | ||||
Deferred energy | (11 | ) | 23 | ||||
Amortization of deferred energy | (21 | ) | (9 | ) | |||
Other, net | 2 | — | |||||
Changes in other operating assets and liabilities: | |||||||
Accounts receivable and other assets | 20 | 18 | |||||
Inventories | (3 | ) | 1 | ||||
Accrued property, income and other taxes | (3 | ) | — | ||||
Accounts payable and other liabilities | (63 | ) | (7 | ) | |||
Net cash flows from operating activities | (12 | ) | 78 | ||||
Cash flows from investing activities: | |||||||
Capital expenditures | (41 | ) | (48 | ) | |||
Net cash flows from investing activities | (41 | ) | (48 | ) | |||
Cash flows from financing activities: | |||||||
Net proceeds from short-term debt | 6 | — | |||||
Repayments of long-term debt and financial and capital lease obligations | (1 | ) | (1 | ) | |||
Dividends paid | (2 | ) | — | ||||
Net cash flows from financing activities | 3 | (1 | ) | ||||
Net change in cash and cash equivalents | (50 | ) | 29 | ||||
Cash and cash equivalents at beginning of period | 55 | 106 | |||||
Cash and cash equivalents at end of period | $ | 5 | $ | 135 | |||
The accompanying notes are an integral part of these consolidated financial statements. | |||||||
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SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Organization and Operations
Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2017 and for the three-month periods ended March 31, 2017 and 2016. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2017 and 2016. The results of operations for the three-month period ended March 31, 2017 are not necessarily indicative of the results to be expected for the full year.
The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2016 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's assumptions regarding significant accounting estimates and policies during the three-month period ended March 31, 2017.
(2) New Accounting Pronouncements
In March 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-07, which amends FASB Accounting Standards Codification ("ASC") Topic 715, "Compensation - Retirement Benefits." The amendments in this guidance require that an employer disaggregate the service cost component from the other components of net benefit cost and report the service cost component in the same line item as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost are required to be presented in the statement of operations separately from the service cost component and outside the subtotal of operating income. Additionally, the guidance only allows the service cost component to be eligible for capitalization when applicable. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. This guidance must be adopted retrospectively for the presentation of the service cost component and the other components of net benefit cost in the statement of operations and prospectively for the capitalization of the service cost component in the balance sheet. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In November 2016, the FASB issued ASU No. 2016-18, which amends FASB ASC Subtopic 230-10, “Statement of Cash Flows - Overall.” The amendments in this guidance require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
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In August 2016, the FASB issued ASU No. 2016-15, which amends FASB ASC Topic 230, "Statement of Cash Flows." The amendments in this guidance address the classification of eight specific cash flow issues within the statement of cash flows with the objective of reducing the existing diversity in practice. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted, and is required to be adopted retrospectively. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements.
In February 2016, the FASB issued ASU No. 2016-02, which creates FASB 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 in 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. This guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted, and is required to be adopted using a modified retrospective approach. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements.
In May 2014, the FASB issued ASU No. 2014-09, which creates FASB ASC Topic 606, "Revenue from Contracts with Customers" and supersedes ASC Topic 605, "Revenue Recognition." The guidance replaces industry-specific guidance and establishes a single five-step model to identify and recognize revenue. The core principle of the guidance is that an entity should recognize revenue upon transfer of control of promised goods or services to customers in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. Additionally, the guidance requires the entity to disclose further quantitative and qualitative information regarding the nature and amount of revenues arising from contracts with customers, as well as other information about the significant judgments and estimates used in recognizing revenues from contracts with customers. In August 2015, the FASB issued ASU No. 2015-14, which defers the effective date of ASU No. 2014-09 one year to interim and annual reporting periods beginning after December 15, 2017. During 2016, the FASB issued several ASUs that clarify the implementation guidance for ASU No. 2014-09 but do not change the core principle of the guidance. This guidance may be adopted retrospectively or under a modified retrospective method where the cumulative effect is recognized at the date of initial application. Sierra Pacific is currently evaluating the impact of adopting this guidance on its Consolidated Financial Statements and disclosures included within Notes to Consolidated Financial Statements. Sierra Pacific currently does not expect the timing and amount of revenue currently recognized to be materially different after adoption of the new guidance as a majority of revenue is recognized when Sierra Pacific has the right to invoice as it corresponds directly with the value to the customer of Sierra Pacific’s performance to date. Sierra Pacific's current plan is to quantitatively disaggregate revenue in the required financial statement footnote by segment and customer class.
(3) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following (in millions):
As of | |||||||||
Depreciable Life | March 31, | December 31, | |||||||
2017 | 2016 | ||||||||
Utility plant: | |||||||||
Electric generation | 25 - 60 years | $ | 1,139 | $ | 1,137 | ||||
Electric distribution | 20 - 100 years | 1,423 | 1,417 | ||||||
Electric transmission | 50 - 100 years | 772 | 771 | ||||||
Electric general and intangible plant | 5 - 70 years | 173 | 164 | ||||||
Natural gas distribution | 35 - 70 years | 383 | 381 | ||||||
Natural gas general and intangible plant | 5 - 70 years | 15 | 15 | ||||||
Common general | 5 - 70 years | 280 | 267 | ||||||
Utility plant | 4,185 | 4,152 | |||||||
Accumulated depreciation and amortization | (1,460 | ) | (1,442 | ) | |||||
Utility plant, net | 2,725 | 2,710 | |||||||
Other non-regulated, net of accumulated depreciation and amortization | 70 years | 5 | 5 | ||||||
Plant, net | 2,730 | 2,715 | |||||||
Construction work-in-progress | 97 | 107 | |||||||
Property, plant and equipment, net | $ | 2,827 | $ | 2,822 | |||||
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(4) 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 Public Utilities Commission of Nevada ("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, energy and capacity in future time periods.
Regulatory Rate Review
In June 2016, Sierra Pacific filed an electric regulatory rate review with the PUCN. The filing requested no incremental annual revenue relief. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving most, but not all, issues in the proceeding and reduced Sierra Pacific's electric revenue requirement by $3 million spread evenly to all rate classes. In December 2016, the PUCN approved the settlement agreement and established an additional six MW of net metering capacity under the grandfathered rates, which are those net metering rates that were in effect prior to January 2016; the order establishes cost-based rates and a value-based excess energy credit for customers who choose to install private generation after the six MW limitation is reached. The new rates were effective January 1, 2017. In January 2017, Sierra Pacific filed a petition for reconsideration relating to the creation of the additional six MWs of net metering at the grandfathered rates. Sierra Pacific believes the effects of the PUCN decision result in additional cost shifting to non-net metering customers and reduces the stipulated rate reduction for other customer classes.
In June 2016, Sierra Pacific filed a gas regulatory rate review with the PUCN. The filing requested a slight decrease in its incremental annual revenue requirement. In October 2016, Sierra Pacific filed with the PUCN a settlement agreement resolving all issues in the proceeding and reduced Sierra Pacific's gas revenue requirement by $2 million. In December 2016, the PUCN approved the settlement agreement. The new rates were effective January 1, 2017.
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 applicants' 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 September 2016, Switch, Ltd. ("Switch"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In December 2016, the PUCN approved a stipulation agreement that allows Switch to purchase energy from alternative providers subject to conditions. In March 2017, Switch provided notice that it intends to proceed with purchasing energy from alternative providers.
In November 2016, Caesars Enterprise Service ("Caesars"), a customer of Sierra Pacific, filed an application with the PUCN to purchase energy from alternative providers of a new electric resource and become a distribution only service customer of Sierra Pacific. In March 2017, the PUCN approved the application allowing Caesars to purchase energy from alternative providers subject to conditions, including paying an impact fee. In March 2017, Caesars provided notice that it intends to pay the impact fee and proceed with purchasing energy from alternative providers.
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(5) Employee Benefit Plans
Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Sierra Pacific contributed $4 million and $- million to the Other Postretirement Plans for the three-months ended March 31, 2017 and 2016, respectively. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.
Amounts payable to NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):
As of | |||||||
March 31, | December 31, | ||||||
2017 | 2016 | ||||||
Qualified Pension Plan - | |||||||
Other long-term liabilities | $ | (12 | ) | $ | (12 | ) | |
Non-Qualified Pension Plans: | |||||||
Other current liabilities | (1 | ) | (1 | ) | |||
Other long-term liabilities | (9 | ) | (9 | ) | |||
Other Postretirement Plans - | |||||||
Other long-term liabilities | (24 | ) | (28 | ) | |||
(6) Fair Value Measurements
The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Sierra Pacific has various financial assets and liabilities, that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
• | Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that Sierra Pacific has the ability to access at the measurement date. |
• | Level 2 - Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs). |
• | Level 3 - Unobservable inputs reflect Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data. |
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The following table presents Sierra Pacific's assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):
Input Levels for Fair Value Measurements | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
As of March 31, 2017 | |||||||||||||||
Assets - investment funds | $ | — | $ | — | $ | — | $ | — | |||||||
As of December 31, 2016 | |||||||||||||||
Assets: | |||||||||||||||
Money market mutual funds(1) | $ | 35 | $ | — | $ | — | $ | 35 | |||||||
Investment funds | 1 | — | — | 1 | |||||||||||
$ | 36 | $ | — | $ | — | $ | 36 | ||||||||
(1) | Amounts are included in cash and cash equivalents on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost. |
Sierra Pacific's investments in money market mutual funds and equity securities are accounted for as available-for-sale securities and are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value.
Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying 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 March 31, 2017 | As of December 31, 2016 | ||||||||||||||
Carrying | Fair | Carrying | Fair | ||||||||||||
Value | Value | Value | Value | ||||||||||||
Long-term debt | $ | 1,120 | $ | 1,188 | $ | 1,119 | $ | 1,191 | |||||||
(7) | Commitments and Contingencies |
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact 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 consolidated financial results.
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(8) 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.
Sierra Pacific believes presenting gross margin allows the reader to assess the impact of Sierra Pacific's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale ("cost of sales").
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The following tables provide information on a reportable segment basis (in millions):
Three-Month Periods | ||||||||
Ended March 31, | ||||||||
2017 | 2016 | |||||||
Operating revenue: | ||||||||
Regulated electric | $ | 159 | $ | 170 | ||||
Regulated gas | 34 | 47 | ||||||
Total operating revenue | $ | 193 | $ | 217 | ||||
Cost of sales: | ||||||||
Regulated electric | $ | 56 | $ | 70 | ||||
Regulated gas | 16 | 30 | ||||||
Total cost of sales | $ | 72 | $ | 100 | ||||
Gross margin: | ||||||||
Regulated electric | $ | 103 | $ | 100 | ||||
Regulated gas | 18 | 17 | ||||||
Total gross margin | $ | 121 | $ | 117 | ||||
Operating and maintenance: | ||||||||
Regulated electric | $ | 36 | $ | 36 | ||||
Regulated gas | 5 | 5 | ||||||
Total operating and maintenance | $ | 41 | $ | 41 | ||||
Depreciation and amortization: | ||||||||
Regulated electric | $ | 25 | $ | 25 | ||||
Regulated gas | 3 | 4 | ||||||
Total depreciation and amortization | $ | 28 | $ | 29 | ||||
Operating income: | ||||||||
Regulated electric | $ | 36 | $ | 33 | ||||
Regulated gas | 10 | 8 | ||||||
Total operating income | $ | 46 | $ | 41 | ||||
Interest expense: | ||||||||
Regulated electric | $ | 10 | $ | 14 | ||||
Regulated gas | 1 | 2 | ||||||
Total interest expense | $ | 11 | $ | 16 | ||||
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As of | |||||||||||
March 31, | December 31, | ||||||||||
2017 | 2016 | ||||||||||
Total assets: | |||||||||||
Regulated electric | $ | 3,112 | $ | 3,119 | |||||||
Regulated gas | 310 | 314 | |||||||||
Regulated common assets(1) | 13 | 60 | |||||||||
Total assets | $ | 3,435 | $ | 3,493 | |||||||
(1) | Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments. |
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
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 and resources. Sierra Pacific 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 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 consolidated financial condition and results of operations of Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth and other factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.
Results of Operations for the First Quarter of 2017 and 2016
Overview
Net income for the first quarter of 2017 was $24 million, an increase of $7 million, or 41%, compared to 2016 due to higher electric margins primarily from increased customer usage due to the impacts of weather and a decrease in interest expense from financing transactions in 2016.
Operating revenue, cost of fuel, energy and capacity and natural gas purchased for resale are key drivers of Sierra Pacific's results of operations as they encompass retail and wholesale electricity and natural gas revenue and the direct costs associated with providing electricity and natural gas to customers. Sierra Pacific believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale, is therefore meaningful.
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A comparison of Sierra Pacific's key operating results is as follows:
Electric Gross Margin
First Quarter | |||||||||||||||
2017 | 2016 | Change | |||||||||||||
Gross margin (in millions): | |||||||||||||||
Operating electric revenue | $ | 159 | $ | 170 | $ | (11 | ) | (6 | ) | % | |||||
Cost of fuel, energy and capacity | 56 | 70 | (14 | ) | (20 | ) | |||||||||
Gross margin | $ | 103 | $ | 100 | $ | 3 | 3 | ||||||||
GWh sold: | |||||||||||||||
Residential | 630 | 609 | 21 | 3 | % | ||||||||||
Commercial | 679 | 649 | 30 | 5 | |||||||||||
Industrial | 744 | 738 | 6 | 1 | |||||||||||
Other | 4 | 4 | — | — | |||||||||||
Total fully bundled(1) | 2,057 | 2,000 | 57 | 3 | |||||||||||
Distribution only service | 348 | 339 | 9 | 3 | |||||||||||
Total retail | 2,405 | 2,339 | 66 | 3 | |||||||||||
Wholesale | 182 | 188 | (6 | ) | (3 | ) | |||||||||
Total GWh sold | 2,587 | 2,527 | 60 | 2 | |||||||||||
Average number of retail customers (in thousands): | |||||||||||||||
Residential | 293 | 290 | 3 | 1 | % | ||||||||||
Commercial | 47 | 47 | — | — | |||||||||||
Total | 340 | 337 | 3 | 1 | |||||||||||
Average revenue per MWh: | |||||||||||||||
Retail fully bundled(1) | $ | 69.89 | $ | 78.10 | $ | (8.21 | ) | (11 | ) | % | |||||
Wholesale | $ | 50.06 | $ | 53.04 | $ | (2.98 | ) | (6 | ) | ||||||
Heating degree days | 2,133 | 1,960 | 173 | 9 | % | ||||||||||
Sources of energy (GWh)(2): | |||||||||||||||
Natural gas | 1,010 | 989 | 21 | 2 | % | ||||||||||
Coal | — | 214 | (214 | ) | * | ||||||||||
Renewables | 5 | — | 5 | * | |||||||||||
Total energy generated | 1,015 | 1,203 | (188 | ) | (16 | ) | |||||||||
Energy purchased | 1,423 | 1,144 | 279 | 24 | |||||||||||
Total | 2,438 | 2,347 | 91 | 4 | |||||||||||
Average total cost of energy per MWh(3): | $ | 23.07 | $ | 29.59 | $ | (6.52 | ) | (22 | ) | % | |||||
* Not meaningful
(1) | Fully bundled includes sales to customers for combined energy, transmission and distribution services. |
(2) | GWh amounts are net of energy used by the related generating facilities. |
(3) | The average total cost of energy per MWh includes the cost of fuel, purchased power and deferrals and does not include other costs. |
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Natural Gas Gross Margin
First Quarter | |||||||||||||||
2017 | 2016 | Change | |||||||||||||
Gross margin (in millions): | |||||||||||||||
Operating natural gas revenue | $ | 34 | $ | 47 | $ | (13 | ) | (28 | ) | % | |||||
Natural gas purchased for resale | 16 | 30 | (14 | ) | (47 | ) | |||||||||
Gross margin | $ | 18 | $ | 17 | $ | 1 | 6 | ||||||||
Dth sold: | |||||||||||||||
Residential | 4,459 | 3,864 | 595 | 15 | % | ||||||||||
Commercial | 2,196 | 2,032 | 164 | 8 | |||||||||||
Industrial | 660 | 573 | 87 | 15 | |||||||||||
Total retail | 7,315 | 6,469 | 846 | 13 | |||||||||||
Average number of retail customers (in thousands) | 163 | 161 | 2 | 1 | % | ||||||||||
Average revenue per retail Dth sold | $ | 4.58 | $ | 7.04 | $ | (2.46 | ) | (35 | ) | % | |||||
Average cost of natural gas per retail Dth sold | $ | 2.20 | $ | 4.50 | $ | (2.30 | ) | (51 | ) | % | |||||
Heating degree days | 2,133 | 1,960 | 173 | 9 | % | ||||||||||
Electric gross margin increased $3 million, or 3%, for the first quarter of 2017 compared to 2016 primarily due to higher customer usage from the impacts of weather.
Other income (expense) is favorable $5 million, or 36%, for the first quarter of 2017 compared to 2016 primarily due to a decrease in interest expense from financing transactions in 2016.
Liquidity and Capital Resources
As of March 31, 2017, Sierra Pacific's total net liquidity was as follows (in millions):
Cash and cash equivalents | $ | 5 | ||
Credit facility | 250 | |||
Less: | ||||
Tax-exempt bond support | (80 | ) | ||
Short-term debt | (6 | ) | ||
Net credit facility | 164 | |||
Total net liquidity | $ | 169 | ||
Operating Activities
Net cash flows from operating activities for the three-month periods ended March 31, 2017 and 2016 were $(12) million and $78 million, respectively. The change was due to higher payments for fuel costs, decreased collections from customers due to lower retail rates as a result of deferred energy adjustment mechanisms and higher contributions to retirement plans.
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In December 2015, the Protecting Americans from Tax Hikes Act of 2015 ("PATH") was signed into law, extending bonus depreciation for qualifying property acquired and placed in-service before January 1, 2020 (bonus depreciation rates will be 50% for 2015-2017, 40% in 2018, and 30% in 2019), with an additional year for certain longer lived assets. Investment tax credits were extended and phased-down for solar projects that are under construction before the end of 2021 (investment tax credit rates are 30% through 2019, 26% in 2020 and 22% in 2021; they revert to the statutory rate of 10% thereafter). As a result of PATH, Sierra Pacific's cash flows from operations are expected to benefit due to bonus depreciation on qualifying assets placed in-service through 2019 and investment tax credits (once the net operating loss is fully utilized) earned on qualifying projects through 2021.
The timing of Sierra Pacific's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions for each payment date.
Investing Activities
Net cash flows from investing activities for the three-month periods ended March 31, 2017 and 2016 were $(41) million and $(48) million, respectively. The change was primarily due to decreased capital expenditures.
Financing Activities
Net cash flows from financing activities for the three-month periods ended March 31, 2017 and 2016 were $3 million and $(1) million, respectively. The change was due to proceeds from short-term debt offset by higher dividends paid to NV Energy, Inc. in 2017.
Ability to Issue Debt
Sierra Pacific's ability to issue debt is primarily impacted by its financing authority from the PUCN. As of March 31, 2017, Sierra Pacific has financing authority from the PUCN consisting of the ability to: (1) issue additional long-term debt securities of up to $350 million; (2) refinance up to $55 million of long-term debt securities; and (3) maintain a revolving credit facility of up to $600 million. Sierra Pacific's revolving credit facility contains a financial maintenance covenant which Sierra Pacific was in compliance with as of March 31, 2017.
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 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
Sierra Pacific 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, 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.
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Sierra Pacific's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items are as follows (in millions):
Three-Month Periods | Annual | ||||||||||
Ended March 31, | Forecast | ||||||||||
2016 | 2017 | 2017 | |||||||||
Distribution | $ | 16 | $ | 22 | $ | 112 | |||||
Transmission system investment | 3 | 1 | 23 | ||||||||
Other | 29 | 18 | 42 | ||||||||
Total | $ | 48 | $ | 41 | $ | 177 | |||||
Sierra Pacific's forecast capital expenditures include investments that relate 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 March 31, 2017, 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, 2016.
Regulatory Matters
Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.
Environmental Laws and Regulations
Sierra Pacific is subject to federal, state and local laws and regulations regarding air and water quality, RPS, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact Sierra Pacific's current and future operations. In addition to imposing continuing compliance obligations and capital expenditure requirements, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance including fines, injunctive relief and other sanctions. These laws and regulations are administered by the EPA and various state and local agencies. All such laws and regulations are subject to a range of interpretation, which may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on its operations and consolidated financial results. Sierra Pacific believes it is in material compliance with all applicable laws and regulations. Refer to "Liquidity and Capital Resources" for discussion of Sierra Pacific's forecasted environmental-related capital expenditures.
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.
New Accounting Pronouncements
For a discussion of new accounting pronouncements affecting Sierra Pacific, refer to Note 2 of Notes to Consolidated Financial Statements in Sierra Pacific's Part I, Item 1 of this Form 10-Q.
Critical Accounting Estimates
Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2016. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2016.
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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, 2016. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2016. Refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, Note 5 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q and Note 7 of the Notes to Consolidated Financial Statements of Nevada Power in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of March 31, 2017.
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 March 31, 2017 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
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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, 2016.
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 exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.
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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: May 5, 2017 | /s/ Patrick J. Goodman |
Patrick J. Goodman | |
Executive Vice President and Chief Financial Officer | |
(principal financial and accounting officer) | |
PACIFICORP | |
Date: May 5, 2017 | /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: May 5, 2017 | /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: May 5, 2017 | /s/ E. Kevin Bethel |
E. Kevin Bethel | |
Senior Vice President and Chief Financial Officer | |
(principal financial and accounting officer) | |
SIERRA PACIFIC POWER COMPANY | |
Date: May 5, 2017 | /s/ E. Kevin Bethel |
E. Kevin Bethel | |
Senior Vice President and Chief Financial Officer | |
(principal financial and accounting officer) | |
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EXHIBIT INDEX
Exhibit No. | Description |
BERKSHIRE HATHAWAY ENERGY
15.1 | Awareness Letter of Independent Registered Public Accounting Firm. |
31.1 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.2 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.1 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.2 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
PACIFICORP
15.2 | Awareness Letter of Independent Registered Public Accounting Firm. |
31.3 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.4 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.3 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.4 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
BERKSHIRE HATHAWAY ENERGY AND PACIFICORP
95 | Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act. |
MIDAMERICAN ENERGY
15.3 | Awareness Letter of Independent Registered Public Accounting Firm. |
31.5 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.6 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.5 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.6 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
MIDAMERICAN FUNDING
31.7 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.8 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.7 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.8 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
141
Exhibit No. Description
NEVADA POWER
15.4 | Awareness Letter of Independent Registered Public Accounting Firm. |
31.9 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.10 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.9 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.10 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
SIERRA PACIFIC
31.11 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
31.12 | Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
32.11 | Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
32.12 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
ALL REGISTRANTS
101 | The following financial information from each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, 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. |
142