UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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þ
| | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED September 30, 2013 |
ORFor the quarterly period ended June 30, 2014
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¨ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO |
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from _____ to _____
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| | | | | | |
| | Registrant, Address of | | I.R.S. Employer | | |
| | Principal Executive Offices | | Identification | | State of |
| Commission File Number | | and Telephone NumberExact name of registrant as specified in its charter; State or other jurisdiction of incorporation or organization | | Number | | Incorporation |
| | | | | | |
001-08788 | | NV ENERGY, INC. | | 88-0198358 | | Nevada |
| | 6226 West Sahara Avenue | | | | |
| | Las Vegas, Nevada 89146 | | | | |
| | (702) 402-5000 | | | | |
| | | | | | IRS Employer Identification No. |
| 000-52378 | | NEVADA POWER COMPANY d/b/a | | 88-0420104 | | Nevada |
| | | NV ENERGY | | (A Nevada Corporation) | | |
| | | 6226 West Sahara Avenue | | | | |
| | | Las Vegas, Nevada 89146 | | | | |
| | | (702) 402-5000 | | 702-402-5000 | | |
| | | | | | | |
000-00508 | | SIERRA PACIFIC POWER COMPANY d/b/a | | 88-0044418 | | Nevada |
| | | NV ENERGY | | Securities registered pursuant to Section 12(b) of the Act: None | | |
| | | P.O. Box 10100 | | Securities registered pursuant to Section 12(g) of the Act: | | |
| | | (6100 Neil Road) | | | | |
| | Reno, Nevada 89520-0400 (89511) | | | | |
| | (775) 834-4011 | | Common Stock, $1.00 stated value | | |
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.
Yes þ T No o (Response applicable to all registrants)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website,Web site, 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 registrant was required to submit and post such files).
Yes þ T No o (Response applicable to all registrants)
Indicate by check mark whether anythe registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large"large accelerated filer",filer," "accelerated filer", "non-accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
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| | | | |
NV Energy, Inc.: | Large accelerated filer þ
| Accelerated filer o
| Non-accelerated filer o
| Smaller reporting company o
|
Nevada Power Company: | Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o
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Sierra Pacific Power Company: | Large accelerated filer o
| Accelerated filer o
| Non-accelerated filer þx
| Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ (Response applicable to all registrants)T
Indicate the numberAll shares of shares outstanding common stock of each of the issuer’s classes of Common Stock, as of the latest practicable date.
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| | |
Class | | Outstanding at November 1, 2013 |
Common Stock, $1.00 par value
of NV Energy, Inc.
| | 235,581,074 Shares |
Nevada Power Company are held by its parent company, NV Energy, Inc., which is the sole holderan indirect, wholly owned subsidiary of theBerkshire Hathaway Energy Company. As of July 31, 2014, 1,000 shares of outstanding Common Stock,common stock, $1.00 stated value, of Nevada Power Company.
NV Energy, Inc. is the sole holder of the 1,000 shares of outstanding Common Stock, $3.75 stated value, of Sierra Pacific Power Company.
This combined Quarterly Report on Form 10-Q is separately filed by NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company. Information contained in this document relating to Nevada Power Company is filed by NV Energy, Inc. and separately by Nevada Power Company on its own behalf. Nevada Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Nevada Power Company. Information contained in this document relating to Sierra Pacific Power Company is filed by NV Energy, Inc. and separately by Sierra Pacific Power Company on its own behalf. Sierra Pacific Power Company makes no representation as to information relating to NV Energy, Inc. or its subsidiaries, except as it may relate to Sierra Pacific Power Company.were outstanding.
NV ENERGY, INC
NEVADA POWER COMPANY
SIERRA PACIFIC POWER COMPANY
QUARTERLY REPORTS ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2013
TABLE OF CONTENTS
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PART I – FINANCIAL INFORMATION |
Acronyms & Terms | | |
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ITEM 1. | Financial Statements | |
| NV Energy, Inc. | |
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| Nevada Power Company | |
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| Sierra Pacific Power Company | |
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| Condensed Notes to Financial Statements | |
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ITEM 2. | | |
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ITEM 3. | | |
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PART II – OTHER INFORMATION | |
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ACRONYMS AND TERMSDefinition of Abbreviations and Industry Terms
(The
When used in Forward-Looking Statements, Part I - Items 2 through 4, and Part II - Items 1 through 6, the following common acronyms and terms are found in multiple locations withinhave the document)
definitions indicated.
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Acronym/Term | | MeaningNevada Power Company and Related Entities |
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2012 Form 10-KCompany | | NVE’s, NPC’sNevada Power Company and SPPC’s Annual Report on Form 10-K for the year ended December 31, 2012its subsidiaries |
AFUDC-debtBHE | | Berkshire Hathaway Energy Company |
| NV Energy | | NV Energy, Inc. |
| Sierra Pacific | | Sierra Pacific Power Company, an electric and natural gas utility wholly owned by NV Energy |
| Higgins Generating Station | | 530-megawatt generating facility in Nevada |
| Lenzie Generating Station | | 1,102-megawatt generating facility in Nevada |
| Navajo Generating Station | | 2,250-megawatt generating facility in Arizona |
| ON Line | | 500-kilovolt transmission line connecting the Company and Sierra Pacific |
| Reid Gardner Generating Station | | 557-megawatt generating facility in Nevada |
| | |
| Certain Industry Terms |
| | |
| AFUDC | | Allowance for Borrowed Funds Used During Construction |
AFUDC-equity | | Allowance for Equity Funds Used During Construction |
ARO | | Asset Retirement Obligation |
ASC | | Accounting Standards Codification |
BOD | | Board of Directors |
BTER | | Base Tariff Energy Rate |
BTGR | | Base Tariff General Rate |
CA ISO | | California Independent System Operator Corporation |
California Assets | | SPPC's California electric distribution and generation assets |
CalPeco | | California Pacific Electric Company |
CDD | | Cooling degree days |
CDWR | | California Department of Water Resources |
CIAC | | Contributions in Aid of Construction |
CWIP | | Construction Work-in-Progress |
dba | | Doing business as |
DEAA | | Deferred Energy Accounting Adjustment |
Dth | | Decatherm |
EEIR | | Energy Efficiency Implementation Rate |
EEPR | | Energy Efficiency Program Rate |
| EPA | | United States Environmental Protection Agency |
EPS | | Earnings per Share |
FASB | | Financial Accounting Standards Board |
FASC | | FASB Accounting Standards Codification |
| FERC | | Federal Energy Regulatory Commission |
FitchGWh | | Fitch Ratings, Ltd. |
Ft. Churchill Generating Station | | 226 megawatt nominally rated Fort Churchill Generating Station |
GAAP | | Generally Accepted Accounting Principles in the United States |
GBT | | Great Basin Transmission, LLC, a wholly owned subsidiary of Texas Nevada Transmission, LLC |
GBT-South | | Great Basin Transmission South, LLC, a wholly owned subsidiary of GBT |
GRC | | General Rate Case |
Harry Allen Generating Station | | 642 megawatt nominally rated Harry Allen Generating Station |
HDD | | Heating degree days |
Higgins Generating Station | | 598 megawatt nominally rated Walter M. Higgins, III Generating Station |
IRP | | Integrated resource plan |
kV | | Kilovolt |
Lenzie Generating Station | | 1,102 megawatt nominally rated Chuck Lenzie Generating Station |
MEHC | | MidAmerican Energy Holdings Company, an Iowa corporation, and subsidiary of Berkshire Hathaway, Inc. |
MidAmerican Merger | | The merger contemplated by the MidAmerican Merger Agreement of Silver Merger Sub, Inc., a Nevada corporation |
| | and wholly-owned subsidiary of MEHC, with and into NVE, with NVE continuing as the surviving corporation. |
MidAmerican Merger | | The agreement and plan of merger dated as of May 29, 2013, among NVE, MEHC and Silver Merger Sub, Inc., |
Agreement | | a Nevada corporation and wholly-owned subsidiary of MEHC |
Mohave Generating Station | | 1,580 megawatt nominally rated Mohave Generating Station |
Moody’s | | Moody’s Investors Services, Inc.Gigawatt Hours |
| MW | | MegawattMegawatts |
| MWh | | Megawatt hour |
Navajo Generating Station | | 255 megawatt nominally rated Navajo Generating Station |
NEICO | | Nevada Electric Investment Company |
NERC | | North American Electric Reliability Corporation |
Ninth Circuit | | United States Court of Appeals for the Ninth Circuit |
NOL | | Net Operating Loss |
NPC | | Nevada Power Company d/b/a NV Energy |
NPC Credit Agreement | | $500 million Revolving Credit Facility entered into in March 2012 between NPC and Wells Fargo Bank, |
| | N.A., as administrative agent for the lenders a party thereto |
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NPC Indenture | | NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank |
| | of New York Mellon Trust Company, N.A., as Trustee |
NRSRO | | Nationally Recognized Statistical Rating Organization |
NVE | | NV Energy, Inc. |
NV Energize | | A smart grid infrastructure that is expected to enable the widespread use of Smart Meters that will provide |
| | customers the ability to more directly manage their energy usage |
NVEOC | | NV Energy Operating Company |
NVision | | A comprehensive plan of NVE for the reduction of emissions from coal-fired generation plants through the |
| | accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with |
| | increased capacity from renewable energy facilities and other electric generating plants |
ON Line | | 250 mile 500 kV transmission line connecting NVE’s northern and southern service territories |
One Company Merger | | The merger between NPC and SPPC, whereby SPPC will be merged into NPC and the surviving entity will be called NVEOC |
Portfolio Standard | | Nevada Renewable Energy Portfolio StandardHours |
| PUCN | | Public Utilities Commission of Nevada |
Reid Gardner Generating Station | | 325 megawatt nominally rated Reid Gardner Generating Station |
REPR | | Renewable Energy Program Rate |
ROR | | Rate of return |
SB 123 | | Senate Bill 123 passed into law by the Nevada State Legislature in June 2013, requiring certain electric utilities in |
| | Nevada to file with the PUCN an emissions reduction and capacity replacement plan; and prescribing the minimum |
| | requirements of such a plan |
S&P | | Standard & Poor's |
Salt River | | Salt River Project |
SEC | | United States Securities and Exchange Commission |
Silverhawk Generating Station | | 395 megawatt nominally rated Silverhawk Generating Station |
SPPC | | Sierra Pacific Power Company d/b/a NV Energy |
SPPC Credit Agreement | | $250 million Revolving Credit Facility entered into in March 2012 between SPPC and Wells Fargo |
| | Bank, N.A., as administrative agent for the lenders a party thereto |
SPPC Indenture | | SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and |
| | the Bank of New York Mellon Trust Company, N.A., as Trustee |
Term Loan | | $195 million loan agreement entered into on October 7, 2011 between NVE and JPMorgan Chase Bank, |
| | N.A., as administrative agent for the lenders a party thereto |
TMWA | | Truckee Meadows Water Authority |
Tracy Generating Station | | 541 megawatt nominally rated Frank A. Tracy Generating Station |
TRED | | Temporary Renewable Energy Development |
TUA | | Transmission Use and Capacity Exchange Agreement with GBT-South |
U.S. | | United States of America |
Utilities | | Nevada Power Company and Sierra Pacific Power Company |
Valmy Generating Station | | 261 megawatt nominally rated Valmy Generating Station |
VIE | | Variable Interest Entity |
WSPP | | Western Systems Power Pool |
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 Company'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 the Company 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 reliability and safety standards, affecting the Company'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 generating facility output, accelerate generating facility retirements or delay generating facility construction or acquisition;
the outcome of rate cases and other proceedings conducted by regulatory commissions or other governmental and legal bodies and the Company's ability to recover costs in rates in a timely manner;
changes in economic, industry or weather conditions, as well as demographic trends, new technologies and various conservation, energy efficiency and distributed generation measures and programs, that could affect customer growth and usage, electricity supply or the Company's ability to obtain long-term contracts with customers and suppliers;
a high degree of variance between actual and forecasted load or generation that could impact the Company's hedging strategy and the cost of balancing its generation resources with its retail load obligations;
performance and availability of the Company's generating facilities, including the impacts of outages and repairs, transmission constraints, weather and operating conditions;
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 effects of catastrophic and other unforeseen events, which may be caused by factors beyond the Company's control or by a breakdown or failure of the Company's operating assets, including storms, floods, fires, earthquakes, explosions, landslides, litigation, wars, terrorism and embargoes;
the financial condition and creditworthiness of the Company'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 Company's credit facility;
changes in the Company's credit ratings;
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 Company's ability to recover such costs in rates;
increases in employee healthcare costs, including the implementation of the Affordable Care Act;
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 related to the Company's participation in NV Energy's benefit plans;
unanticipated construction delays, changes in costs, receipt of required permits and authorizations, ability to fund capital projects and other factors that could affect future generating facilities and infrastructure additions;
the impact of new accounting guidance or changes in current accounting estimates and assumptions on the Company's consolidated financial results; and
other business or investment considerations that may be disclosed from time to time in the Company's filings with the United States Securities and Exchange Commission or in other publicly disseminated written documents.
Further details of the potential risks and uncertainties affecting the Company are described in the Company's filings with the United States Securities and Exchange Commission, including Part II, Item 1A and other discussions contained in this Form 10‑Q. The Company 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.
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 (the "Company") as of June 30, 2014, and the related consolidated statements of operations for the three-month and six-month periods ended June 30, 2014 and 2013, and of changes in shareholder's equity and cash flows for the six-month periods ended June 30, 2014 and 2013. 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 Nevada Power Company and subsidiaries as of December 31, 2013, 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 March 31, 2014, 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, 2013 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
August 1, 2014
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Unaudited)
(Amounts in millions, except share data)
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| | | | | | | |
| | As of |
| | June 30, | | December 31, |
| | 2014 | | 2013 |
| ASSETS |
| | | | |
| Current assets: | | | |
| Cash and cash equivalents | $ | 168 |
| | $ | 126 |
|
| Accounts receivable, net | 376 |
| | 227 |
|
| Inventories | 72 |
| | 73 |
|
| Regulatory assets | 62 |
| | 81 |
|
| Deferred income taxes | 128 |
| | 152 |
|
| Other current assets | 38 |
| | 39 |
|
| Total current assets | 844 |
| | 698 |
|
| | | | |
| Property, plant and equipment, net | 6,966 |
| | 6,992 |
|
| Regulatory assets | 1,008 |
| | 1,057 |
|
| Other assets | 87 |
| | 88 |
|
| | | | |
| Total assets | $ | 8,905 |
| | $ | 8,835 |
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| LIABILITIES AND SHAREHOLDER'S EQUITY |
| Current liabilities: | | | |
| Accounts payable | $ | 228 |
| | $ | 240 |
|
| Accrued interest | 60 |
| | 61 |
|
| Accrued property, income and other taxes | 27 |
| | 29 |
|
| Accrued employee expenses | 15 |
| | 6 |
|
| Regulatory liabilities | 60 |
| | 74 |
|
| Current portion of long-term debt | 259 |
| | 22 |
|
| Customer deposits and other | 89 |
| | 74 |
|
| Total current liabilities | 738 |
| | 506 |
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| Long-term debt | 3,316 |
| | 3,555 |
|
| Regulatory liabilities | 322 |
| | 312 |
|
| Deferred income taxes | 1,312 |
| | 1,298 |
|
| Other long-term liabilities | 258 |
| | 274 |
|
| Total liabilities | 5,946 |
| | 5,945 |
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| Commitments and contingencies (Note 9) |
| |
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| | | | |
| 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 | 654 |
| | 586 |
|
| Accumulated other comprehensive loss, net | (3 | ) | | (4 | ) |
| Total shareholder's equity | 2,959 |
| | 2,890 |
|
| | | | |
| Total liabilities and shareholder's equity | $ | 8,905 |
| | $ | 8,835 |
|
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| The accompanying notes are an integral part of the consolidated financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(Amounts in millions)
|
| | | | | | | | | | | | | | | |
| | Three-Month Periods | | Six-Month Periods |
| | Ended June 30, | | Ended June 30, |
| | 2014 | | 2013 | | 2014 | | 2013 |
| | | | | | | | |
| Operating revenue | $ | 595 |
| | $ | 536 |
| | $ | 1,012 |
| | $ | 906 |
|
| | | | | | | | |
| Operating costs and expenses: | | | | | | | |
| Cost of fuel, energy and capacity | 284 |
| | 209 |
| | 487 |
| | 351 |
|
| Operating and maintenance expense | 87 |
| | 104 |
| | 169 |
| | 203 |
|
| Depreciation and amortization | 69 |
| | 65 |
| | 135 |
| | 130 |
|
| Property and other taxes | 10 |
| | 10 |
| | 21 |
| | 20 |
|
| Merger-related expenses | — |
| | 9 |
| | — |
| | 9 |
|
| Total operating costs and expenses | 450 |
| | 397 |
| | 812 |
| | 713 |
|
| | | | | | | | |
| Operating income | 145 |
| | 139 |
| | 200 |
| | 193 |
|
| | | | | | | | |
| Other income (expense): | | | | | | | |
| Interest expense, net of allowance for debt funds | (52 | ) | | (53 | ) | | (103 | ) | | (106 | ) |
| Allowance for equity funds | — |
| | 2 |
| | — |
| | 4 |
|
| Other, net | 4 |
| | 3 |
| | 10 |
| | 8 |
|
| Total other income (expense) | (48 | ) | | (48 | ) | | (93 | ) | | (94 | ) |
| | | | | | | | |
| Income before income tax expense | 97 |
| | 91 |
| | 107 |
| | 99 |
|
| Income tax expense | 35 |
| | 32 |
| | 39 |
| | 35 |
|
| Net income | $ | 62 |
| | $ | 59 |
| | $ | 68 |
| | $ | 64 |
|
| | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. | | |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)
(Amounts in millions, except shares)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Accumulated | | |
| | | | | | | Other | | | | Other | | Total |
| | | Common Stock | | Paid-in | | Retained | | Comprehensive | | Shareholder's |
| | | Shares | | Amount | | Capital | | Earnings | | Loss, Net | | Equity |
| Balance at December 31, 2012 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 619 |
| | $ | (4 | ) | | $ | 2,923 |
|
| Net income | | — |
| | — |
| | — |
| | 64 |
| | — |
| | 64 |
|
| Dividends declared | | — |
| | — |
| | — |
| | (80 | ) | | — |
| | (80 | ) |
| Balance at June 30, 2013 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 603 |
| | $ | (4 | ) | | $ | 2,907 |
|
| | | | | | | | | | | | | |
| Balance at December 31, 2013 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 586 |
| | $ | (4 | ) | | $ | 2,890 |
|
| Net income | | — |
| | — |
| | — |
| | 68 |
| | — |
| | 68 |
|
| Other | | — |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Balance at June 30, 2014 | | 1,000 |
| | $ | — |
| | $ | 2,308 |
| | $ | 654 |
| | $ | (3 | ) | | $ | 2,959 |
|
| | | | | | | | | | | | | |
| The accompanying notes are an integral part of these consolidated financial statements. |
ITEM 1. FINANCIAL STATEMENTS
NV ENERGY, INC.NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOMECASH FLOWS (Unaudited)
(DollarsAmounts in Thousands, Except Share Amounts)millions)
(Unaudited)
|
| | | | | | | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | |
| OPERATING REVENUES | $ | 1,013,151 |
| | $ | 1,026,488 |
| | $ | 2,329,011 |
| | $ | 2,378,606 |
|
| | | | | | | | |
| OPERATING EXPENSES: | | | | | | | |
| Fuel for power generation | 217,954 |
| | 171,316 |
| | 554,181 |
| | 400,936 |
|
| Purchased power | 205,970 |
| | 205,686 |
| | 498,141 |
| | 486,894 |
|
| Gas purchased for resale | 7,383 |
| | 5,382 |
| | 62,277 |
| | 46,491 |
|
| Deferred energy | (55,270 | ) | | (29,036 | ) | | (221,022 | ) | | (30,285 | ) |
| Energy efficiency program costs | 16,042 |
| | 32,584 |
| | 38,486 |
| | 76,609 |
|
| Regulatory disallowance | 17,335 |
| | — |
| | 17,335 |
| | — |
|
| Merger-related costs (Note 2) | 7,857 |
| | — |
| | 21,409 |
| | — |
|
| Other operating expenses | 106,068 |
| | 100,108 |
| | 317,538 |
| | 307,080 |
|
| Maintenance | 17,176 |
| | 19,014 |
| | 66,128 |
| | 76,190 |
|
| Depreciation and amortization | 96,801 |
| | 94,512 |
| | 291,687 |
| | 281,690 |
|
| Taxes other than income | 14,214 |
| | 15,682 |
| | 46,536 |
| | 44,457 |
|
| Total Operating Expenses | 651,530 |
| | 615,248 |
| | 1,692,696 |
| | 1,690,062 |
|
| OPERATING INCOME | 361,621 |
| | 411,240 |
| | 636,315 |
| | 688,544 |
|
|
|
| |
|
| |
|
| |
|
|
| | | | | | | | |
| OTHER INCOME (EXPENSE): | | | |
| | |
| | |
|
| Interest expense | |
| | |
| | |
| | |
|
| (net of AFUDC-debt: $1,957 , $1,976 , $5,770 and $5,479) | (74,438 | ) | | (73,667 | ) | | (221,305 | ) | | (226,162 | ) |
| Interest expense on regulatory items | (281 | ) | | (2,024 | ) | | (1,124 | ) | | (6,203 | ) |
| AFUDC-equity | 2,591 |
| | 2,415 |
| | 7,730 |
| | 6,666 |
|
| Other income | 3,239 |
| | 8,827 |
| | 10,872 |
| | 19,312 |
|
| Other expense | (3,829 | ) | | (4,209 | ) | | (12,116 | ) | | (11,909 | ) |
| Total Other Income (Expense) | (72,718 | ) | | (68,658 | ) | | (215,943 | ) | | (218,296 | ) |
| Income Before Income Tax Expense | 288,903 |
| | 342,582 |
| | 420,372 |
| | 470,248 |
|
| | | | | | | | |
| Income tax expense | 101,669 |
| | 119,412 |
| | 148,430 |
| | 165,466 |
|
| | | | | | | | |
| NET INCOME | 187,234 |
| | 223,170 |
| | 271,942 |
| | 304,782 |
|
| | | | | | | | |
| Other comprehensive income (loss) | | | | | | | |
| Change in compensation retirement benefits liability and amortization | |
| | |
| | |
| | |
|
| (Net of taxes $(133), $(74), $(398) and $(246)) | 246 |
| | 155 |
| | 738 |
| | 464 |
|
| Change in market value of risk management assets and liabilities | | | | | | | |
| (Net of taxes $(154), $91, $(261) and $355) | (11 | ) | | (193 | ) | | 485 |
| | (668 | ) |
| Unrealized net gain/(loss) on investment | | | | | | | |
| (Net of taxes $(49), $0, $(18) and $0) | 98 |
| | — |
| | 33 |
| | — |
|
| | | | | | | | |
| OTHER COMPREHENSIVE INCOME(LOSS) | 333 |
| | (38 | ) | | 1,256 |
| | (204 | ) |
| | | | | | | | |
| COMPREHENSIVE INCOME | $ | 187,567 |
| | $ | 223,132 |
| | $ | 273,198 |
| | $ | 304,578 |
|
| | | | | | | | |
| Amount per share basic and diluted (Note 9) | | | | | | | |
| Net income per share - basic | $ | 0.79 |
| | $ | 0.95 |
| | $ | 1.16 |
| | $ | 1.29 |
|
| Net income per share - diluted | $ | 0.79 |
| | $ | 0.94 |
| | $ | 1.15 |
| | $ | 1.28 |
|
| | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding - basic | 235,578,310 |
| | 235,961,402 |
| | 235,421,933 |
| | 235,986,874 |
|
| Weighted Average Shares of Common Stock Outstanding - diluted | 237,605,514 |
| | 238,121,732 |
| | 237,339,039 |
| | 237,850,530 |
|
| Dividends Declared Per Share of Common Stock | $ | 0.19 |
| | $ | 0.17 |
| | $ | 0.57 |
| | $ | 0.47 |
|
| | | | | | | | |
| The accompanying notes are an integral part of the financial statements. |
|
| | | | | | | |
| | Six-Month Periods |
| | Ended June 30, |
| | 2014 | | 2013 |
| | | | |
| Cash flows from operating activities: | | | |
| Net income | $ | 68 |
| | $ | 64 |
|
| Adjustments to reconcile net income to net cash flows from operating activities: | | | |
| Depreciation and amortization | 135 |
| | 130 |
|
| Allowance for equity funds | — |
| | (4 | ) |
| Deferred income taxes and amortization of investment tax credits | 39 |
| | 35 |
|
| Amortization of other regulatory assets | 66 |
| | (3 | ) |
| Other, net | 21 |
| | 14 |
|
| Changes in other operating assets and liabilities: | | | |
| Accounts receivable and other assets | (201 | ) | | (138 | ) |
| Inventories | 1 |
| | — |
|
| Accounts payable and other liabilities | 19 |
| | 32 |
|
| Net cash flows from operating activities | 148 |
| | 130 |
|
| | | | |
| Cash flows from investing activities: | | | |
| Capital expenditures | (97 | ) | | (107 | ) |
| Net cash flows from investing activities | (97 | ) | | (107 | ) |
| | | | |
| Cash flows from financing activities: | | | |
| Repayment of long-term debt | (9 | ) | | (2 | ) |
| Dividends paid | — |
| | (80 | ) |
| Net cash flows from financing activities | (9 | ) | | (82 | ) |
| | | | |
| Net change in cash and cash equivalents | 42 |
| | (59 | ) |
| Cash and cash equivalents at beginning of period | 126 |
| | 201 |
|
| Cash and cash equivalents at end of period | $ | 168 |
| | $ | 142 |
|
| | | | |
| The accompanying notes are an integral part of these consolidated financial statements. |
NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | |
| | | | September 30, | | December 31, |
| | | | 2013 | | 2012 |
| ASSETS | | | |
| | | | | | |
| Current Assets: | | | |
| | Cash and cash equivalents | $ | 373,026 |
| | $ | 298,271 |
|
| | Accounts receivable less allowance for uncollectible accounts: | | | |
| | | 2013 - $9,643; 2012 - $8,748 | 483,178 |
| | 373,099 |
|
| | Materials, supplies and fuel, at average cost | 121,699 |
| | 138,337 |
|
| | Deferred energy costs (Note 4) | 82,235 |
| | — |
|
| | Deferred income taxes | 120,186 |
| | 60,592 |
|
| | Other current assets | 49,041 |
| | 40,750 |
|
| Total Current Assets | 1,229,365 |
| | 911,049 |
|
| | | | | | |
| Utility Property: | | | |
| | Plant in service | 12,195,312 |
| | 12,031,053 |
|
| | Construction work-in-progress | 821,430 |
| | 708,109 |
|
| | | Total | 13,016,742 |
| | 12,739,162 |
|
| | Less accumulated provision for depreciation | 3,526,824 |
| | 3,313,188 |
|
| | | Total Utility Property, Net | 9,489,918 |
| | 9,425,974 |
|
| | | | | | |
| Investments and other property, net | 65,354 |
| | 56,660 |
|
| | | | | | |
| Deferred Charges and Other Assets: | | | |
| | Deferred energy (Note 4) | 85,055 |
| | 87,072 |
|
| | Regulatory assets | 1,048,204 |
| | 1,132,768 |
|
| | Regulatory asset for pension plans | 270,565 |
| | 281,195 |
|
| | Other deferred charges and assets | 76,705 |
| | 89,418 |
|
| Total Deferred Charges and Other Assets | 1,480,529 |
| | 1,590,453 |
|
| | | | | | |
| TOTAL ASSETS | $ | 12,265,166 |
| | $ | 11,984,136 |
|
| | | |
| | | (Continued) |
NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2013 | | 2012 |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | |
| | | | | |
| Current Liabilities: | | | |
| | Current maturities of long-term debt (Note 5) | $ | 129,457 |
| | $ | 356,283 |
|
| | Accounts payable | 316,681 |
| | 332,245 |
|
| | Accrued expenses | 104,781 |
| | 127,693 |
|
| | Deferred energy (Note 4) | — |
| | 136,865 |
|
| | Other current liabilities | 88,299 |
| | 66,221 |
|
| Total Current Liabilities | 639,218 |
| | 1,019,307 |
|
| | | | | |
| Long-term debt (Note 5) | 4,791,809 |
| | 4,669,798 |
|
| | | | | |
| Commitments and Contingencies (Note 8) |
| |
|
| | | | | |
| Deferred Credits and Other Liabilities: | | | |
| | Deferred income taxes | 1,680,896 |
| | 1,470,973 |
|
| | Deferred investment tax credit | 11,623 |
| | 13,538 |
|
| | Accrued retirement benefits | 144,696 |
| | 162,260 |
|
| | Regulatory liabilities | 631,368 |
| | 550,687 |
|
| | Other deferred credits and liabilities | 656,963 |
| | 540,202 |
|
| Total Deferred Credits and Other Liabilities | 3,125,546 |
| | 2,737,660 |
|
| | | | | |
| Shareholders' Equity: | | | |
| | Common stock, $1.00 par value; 350 million shares authorized; 235,999,750 issued | | | |
| | for 2013 and 2012; 235,581,074 and 235,079,156 outstanding for 2013 and 2012, respectively | 236,000 |
| | 236,000 |
|
| | Treasury stock at cost, 418,675 shares and 920,594 shares for 2013 and 2012, respectively | (7,898 | ) | | (16,804 | ) |
| | Other paid-in capital | 2,716,311 |
| | 2,712,943 |
|
| | Retained earnings | 772,995 |
| | 635,303 |
|
| | Accumulated other comprehensive loss | (8,815 | ) | | (10,071 | ) |
| Total Shareholders' Equity | 3,708,593 |
| | 3,557,371 |
|
| | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 12,265,166 |
| | $ | 11,984,136 |
|
| | | | | |
| | The accompanying notes are an integral part of the financial statements. |
| | |
| | (Concluded) |
NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
|
| | | | | | | | | |
| | | | For the Nine Months Ended |
| | | | September 30, |
| | | | 2013 | | 2012 |
| CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: | | | |
| | Net Income | $ | 271,942 |
| | $ | 304,782 |
|
| | Adjustments to reconcile net income to net cash from operating activities: | | | |
| | | Depreciation and amortization | 291,687 |
| | 281,690 |
|
| | | Deferred taxes and deferred investment tax credit | 152,280 |
| | 187,229 |
|
| | | AFUDC-equity | (7,730 | ) | | (6,666 | ) |
| | | Deferred energy | (218,156 | ) | | (18,702 | ) |
| | | Regulatory disallowance | 17,335 |
| | — |
|
| | | Amortization of other regulatory assets | 134,846 |
| | 114,626 |
|
| | | Deferred rate increase | 9,241 |
| | 2,252 |
|
| | | Other, net | 3,649 |
| | (50,012 | ) |
| | Changes in certain assets and liabilities: | | | |
| | | Accounts receivable | (101,079 | ) | | (151,420 | ) |
| | | Materials, supplies and fuel | 16,909 |
| | (18,034 | ) |
| | | Other current assets | (8,292 | ) | | (10,390 | ) |
| | | Accounts payable | 7,042 |
| | 22,646 |
|
| | | Accrued retirement benefits | (17,563 | ) | | (12,946 | ) |
| | | Other current liabilities | (594 | ) | | (23,643 | ) |
| | | Other deferred assets | (3,634 | ) | | (3,572 | ) |
| | | Other regulatory assets | (3,276 | ) | | 34,420 |
|
| | | Other deferred liabilities | 9,099 |
| | (8,066 | ) |
| Net Cash from Operating Activities | 553,706 |
| | 644,194 |
|
| | | | |
| CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: | | | |
| | | Additions to utility plant (excluding AFUDC-equity) | (267,798 | ) | | (387,790 | ) |
| | | Customer advances for construction | 921 |
| | (1,508 | ) |
| | | Contributions in aid of construction | 38,714 |
| | 63,864 |
|
| | | Investments and other property - net | (5,144 | ) | | 217 |
|
| Net Cash used by Investing Activities | (233,307 | ) | | (325,217 | ) |
| | | | | | |
| CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: | | | |
| | | Proceeds from issuance of long-term debt, net of costs | 247,245 |
| | 130,764 |
|
| | | Retirement of long-term debt | (354,443 | ) | | (272,353 | ) |
| | | Sale of common stock | 2,133 |
| | — |
|
| | | Common stock repurchased | (6,329 | ) | | (4,509 | ) |
| | | Dividends paid | (134,250 | ) | | (110,920 | ) |
| Net Cash used by Financing Activities | (245,644 | ) | | (257,018 | ) |
| | | | | | |
| Net Increase in Cash and Cash Equivalents | 74,755 |
| | 61,959 |
|
| Beginning Balance in Cash and Cash Equivalents | 298,271 |
| | 145,944 |
|
| Ending Balance in Cash and Cash Equivalents | $ | 373,026 |
| | $ | 207,903 |
|
| | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | |
| | Cash paid during period for: | | | |
| | | Interest | $ | 233,502 |
| | $ | 237,262 |
|
| | | Income taxes | $ | 2 |
| | $ | 151 |
|
| | Significant non-cash transactions: | | | |
| | | Accrued construction expenses as of September 30, | $ | 141,214 |
| | $ | 132,112 |
|
| | | Issuance of treasury stock | $ | 13,102 |
| | $ | — |
|
| | | | | | |
| | | The accompanying notes are an integral part of the financial statements. |
NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Shares | Common Stock Amount | Treasury Stock Shares | Treasury Stock Amount | Other Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity |
| December 31, 2011 | 235,999,750 |
| | $ | 236,000 |
| | — |
| | $ | — |
| | $ | 2,713,736 |
| | $ | 464,277 |
| | $ | (7,934 | ) | | $ | 3,406,079 |
|
| Net Income | | | | | | | | | | | 304,782 |
| | | | 304,782 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(246)) | | | | | | | | | | | | | 464 |
| | 464 |
|
| Change in market value of risk management assets and liabilities (net of taxes $355) | | | | | | | | | | | | | (668 | ) | | (668 | ) |
| Common stock repurchased | | | | | (252,000 | ) | | (4,509 | ) | | | | | | | | (4,509 | ) |
| Dividends Declared | | | | | | | | | | | (110,920 | ) | | | | (110,920 | ) |
| September 30, 2012 | 235,999,750 |
| | $ | 236,000 |
| | (252,000 | ) | | $ | (4,509 | ) | | $ | 2,713,736 |
| | $ | 658,139 |
| | $ | (8,138 | ) | | $ | 3,595,228 |
|
| | | | | | | | | | | | | | | | |
| December 31, 2012 | 235,999,750 |
| | $ | 236,000 |
| | (920,594 | ) | | $ | (16,804 | ) | | $ | 2,712,943 |
| | $ | 635,303 |
| | $ | (10,071 | ) | | $ | 3,557,371 |
|
| Net Income | | | | | | | | | | | 271,942 |
| | | | 271,942 |
|
| Employee Benefits | | | | | 827,097 |
| | 15,235 |
| | 3,368 |
| | | | | | 18,603 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(398)) | | | | | | | | | | | | | 738 |
| | 738 |
|
| Change in market value of risk management assets and liabilities (net of taxes $(261)) | | | | | | | | | | | | | 485 |
| | 485 |
|
| Unrealized net gain/(loss) on investment (net of taxes $(18)) | | | | | | | | | | | | | 33 |
| | 33 |
|
| Common stock repurchased | | | | | (325,178 | ) | | (6,329 | ) | | | | | | | | (6,329 | ) |
| Dividends Declared | | | | | | | | | | | (134,250 | ) | | | | (134,250 | ) |
| September 30, 2013 | 235,999,750 |
| | $ | 236,000 |
| | (418,675 | ) | | $ | (7,898 | ) | | $ | 2,716,311 |
| | $ | 772,995 |
| | $ | (8,815 | ) | | $ | 3,708,593 |
|
| | | | | | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. |
NEVADA POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| OPERATING REVENUES | $ | 786,142 |
| | $ | 802,334 |
| | $ | 1,695,129 |
| | $ | 1,751,165 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | |
| | Fuel for power generation | 163,127 |
| | 123,992 |
| | 412,904 |
| | 285,799 |
|
| | Purchased power | 172,582 |
| | 171,687 |
| | 383,386 |
| | 388,494 |
|
| | Deferred energy | (45,381 | ) | | (22,685 | ) | | (154,484 | ) | | (15,461 | ) |
| | Energy efficiency program costs | 13,998 |
| | 28,492 |
| | 32,807 |
| | 65,466 |
|
| | Regulatory disallowance | 11,866 |
| | — |
| | 11,866 |
| | — |
|
| | Merger-related costs (Note 2) | 5,620 |
| | — |
| | 14,487 |
| | — |
|
| | Other operating expenses | 70,844 |
| | 65,372 |
| | 208,336 |
| | 200,484 |
|
| | Maintenance | 11,208 |
| | 12,533 |
| | 45,172 |
| | 52,594 |
|
| | Depreciation and amortization | 68,849 |
| | 66,975 |
| | 207,915 |
| | 201,096 |
|
| | Taxes other than income | 8,213 |
| | 9,743 |
| | 27,804 |
| | 26,793 |
|
| Total Operating Expenses | 480,926 |
| | 456,109 |
| | 1,190,193 |
| | 1,205,265 |
|
| OPERATING INCOME | 305,216 |
| | 346,225 |
| | 504,936 |
| | 545,900 |
|
|
| |
| |
|
| |
|
|
| | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | |
| | Interest expense | | | | | | | |
| | (net of AFUDC-debt: $1,520, $1,528, $4,763 and $4,021) | (52,856 | ) | | (51,784 | ) | | (155,758 | ) | | (158,791 | ) |
| | Interest income (expense) on regulatory items | (194 | ) | | (1,623 | ) | | (1,177 | ) | | (5,488 | ) |
| | AFUDC-equity | 1,959 |
| | 1,833 |
| | 6,151 |
| | 4,823 |
|
| | Other income | 1,948 |
| | 7,096 |
| | 5,330 |
| | 14,197 |
|
| | Other expense | (1,966 | ) | | (2,823 | ) | | (6,200 | ) | | (7,162 | ) |
| Total Other Income (Expense) | (51,109 | ) | | (47,301 | ) | | (151,654 | ) | | (152,421 | ) |
| Income Before Income Tax Expense | 254,107 |
| | 298,924 |
| | 353,282 |
| | 393,479 |
|
| | | | | | | | |
| Income tax expense | 89,665 |
| | 103,754 |
| | 124,730 |
| | 137,328 |
|
| | | | | | | | |
| NET INCOME | 164,442 |
| | 195,170 |
| | 228,552 |
| | 256,151 |
|
| | | | | | | | |
| Other comprehensive income | | | | | | | |
| Change in compensation retirement benefits liability and amortization | | | | | | | |
| (Net of taxes $(52), $(33), $(156) and $(103)) | 96 |
| | 65 |
| | 290 |
| | 192 |
|
| | | | | | | | |
| COMPREHENSIVE INCOME | $ | 164,538 |
| | $ | 195,235 |
| | $ | 228,842 |
| | $ | 256,343 |
|
| | |
| | The accompanying notes are an integral part of the financial statements. |
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | |
| | | | September 30, | | December 31, |
| | | | 2013 | | 2012 |
| | | | | | |
| ASSETS | | | |
| | | | | | |
| Current Assets: | | | |
| | Cash and cash equivalents | $ | 255,236 |
| | $ | 201,202 |
|
| | Accounts receivable less allowance for uncollectible accounts: | | | |
| | | 2013 - $8,584; 2012 - $7,622 | 367,365 |
| | 248,501 |
|
| | Materials, supplies and fuel, at average cost | 70,929 |
| | 77,675 |
|
| | Deferred energy costs (Note 4) | 68,391 |
| | — |
|
| | Deferred income taxes | 80,062 |
| | 48,590 |
|
| | Other current assets | 35,984 |
| | 28,763 |
|
| Total Current Assets | 877,967 |
| | 604,731 |
|
| | | | | | |
| Utility Property: | | | |
| | Plant in service | 8,459,208 |
| | 8,363,566 |
|
| | Construction work-in-progress | 695,749 |
| | 567,941 |
|
| | | Total | 9,154,957 |
| | 8,931,507 |
|
| | Less accumulated provision for depreciation | 2,203,320 |
| | 2,035,322 |
|
| | | Total Utility Property, Net | 6,951,637 |
| | 6,896,185 |
|
| | | | | | |
| Investments and other property, net | 51,114 |
| | 49,808 |
|
| | | | | | |
| Deferred Charges and Other Assets: | | | |
| | | Deferred energy (Note 4) | 84,041 |
| | 87,072 |
|
| | | Regulatory assets | 746,286 |
| | 804,013 |
|
| | | Regulatory asset for pension plans | 131,628 |
| | 136,682 |
|
| | | Other deferred charges and assets | 58,097 |
| | 62,654 |
|
| Total Deferred Charges and Other Assets | 1,020,052 |
| | 1,090,421 |
|
| | | | | | |
| TOTAL ASSETS | $ | 8,900,770 |
| | $ | 8,641,145 |
|
| | | | | | |
| | | (Continued) |
NEVADA POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2013 | | 2012 |
| | | | | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| | | | | |
| Current Liabilities: | | | |
| | Current maturities of long-term debt (Note 5) | $ | 129,186 |
| | $ | 106,048 |
|
| | Accounts payable | 202,915 |
| | 201,193 |
|
| | Accounts payable, affiliated companies | 43,800 |
| | 42,036 |
|
| | Accrued expenses | 63,465 |
| | 86,433 |
|
| | Deferred energy (Note 4) | — |
| | 86,102 |
|
| | Other current liabilities | 69,479 |
| | 52,567 |
|
| Total Current Liabilities | 508,845 |
| | 574,379 |
|
| | | | | |
| Long-term debt (Note 5) | 3,103,980 |
| | 3,230,808 |
|
| | | | | |
| Commitments and Contingencies (Note 8) |
| |
|
| | | | | |
| Deferred Credits and Other Liabilities: | | | |
| | Deferred income taxes | 1,257,818 |
| | 1,101,804 |
|
| | Deferred investment tax credit | 3,857 |
| | 4,688 |
|
| | Accrued retirement benefits | 52,429 |
| | 49,381 |
|
| | Regulatory liabilities | 376,136 |
| | 323,400 |
|
| | Other deferred credits and liabilities | 551,545 |
| | 434,367 |
|
| Total Deferred Credits and Other Liabilities | 2,241,785 |
| | 1,913,640 |
|
| | | | | |
| Shareholder's Equity: | | | |
| | Common stock, $1.00 par value; 1,000 shares authorized | | | |
| | issued and outstanding for 2013 and 2012 | 1 |
| | 1 |
|
| | Other paid-in capital | 2,308,211 |
| | 2,308,211 |
|
| | Retained earnings | 742,164 |
| | 618,612 |
|
| | Accumulated other comprehensive loss | (4,216 | ) | | (4,506 | ) |
| Total Shareholder's Equity | 3,046,160 |
| | 2,922,318 |
|
| | | | | |
| TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | $ | 8,900,770 |
| | $ | 8,641,145 |
|
| | | | | |
| The accompanying notes are an integral part of the financial statements. |
| |
| (Concluded) |
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
|
| | | | | | | | | |
| | | | For the Nine Months Ended |
| | | | September 30, |
| | | | 2013 | | 2012 |
| CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: | | | |
| | Net Income | $ | 228,552 |
| | $ | 256,151 |
|
| | Adjustments to reconcile net income to net cash from operating activities: | | | |
| | | Depreciation and amortization | 207,915 |
| | 201,096 |
|
| | | Deferred taxes and deferred investment tax credit | 126,080 |
| | 150,289 |
|
| | | AFUDC-equity | (6,151 | ) | | (4,823 | ) |
| | | Deferred energy | (152,534 | ) | | (7,335 | ) |
| | | Regulatory disallowance | 11,866 |
| | — |
|
| | | Amortization of other regulatory assets | 75,893 |
| | 56,012 |
|
| | | Deferred rate increase | 9,241 |
| | 2,252 |
|
| | | Other, net | (722 | ) | | (35,553 | ) |
| | Changes in certain assets and liabilities: | | | |
| | | Accounts receivable | (118,863 | ) | | (164,858 | ) |
| | | Materials, supplies and fuel | 7,017 |
| | (5,119 | ) |
| | | Other current assets | (7,222 | ) | | (3,715 | ) |
| | | Accounts payable | 20,856 |
| | 53,985 |
|
| | | Accrued retirement benefits | 3,048 |
| | 3,708 |
|
| | | Other current liabilities | (5,819 | ) | | (25,246 | ) |
| | | Other deferred assets | (1,613 | ) | | (2,412 | ) |
| | | Other regulatory assets | 26 |
| | 50,008 |
|
| | | Other deferred liabilities | 1,613 |
| | (10,412 | ) |
| Net Cash from Operating Activities | 399,183 |
| | 514,028 |
|
| | | | | | |
| CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: | | | |
| | | Additions to utility plant (excluding AFUDC-equity) | (159,063 | ) | | (232,608 | ) |
| | | Customer advances for construction | 1,035 |
| | 713 |
|
| | | Contributions in aid of construction | 20,263 |
| | 34,274 |
|
| | | Investments and other property - net | 1,595 |
| | 193 |
|
| Net Cash used by Investing Activities | (136,170 | ) | | (197,428 | ) |
| | | | | | |
| CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: | | | |
| | | Proceeds from issuance of long-term debt, net of costs | (261 | ) | | 132,259 |
|
| | | Retirement of long-term debt | (103,718 | ) | | (271,241 | ) |
| | | Dividends paid | (105,000 | ) | | (119,000 | ) |
| Net Cash used by Financing Activities | (208,979 | ) | | (257,982 | ) |
| | | | | | |
| Net Increase in Cash and Cash Equivalents | 54,034 |
| | 58,618 |
|
| Beginning Balance in Cash and Cash Equivalents | 201,202 |
| | 65,887 |
|
| Ending Balance in Cash and Cash Equivalents | $ | 255,236 |
| | $ | 124,505 |
|
| | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | |
| | Cash paid during period for: | | | |
| | | Interest | $ | 174,050 |
| | $ | 177,459 |
|
| | | Income taxes | $ | 1 |
| | $ | 1 |
|
| | Significant non-cash transactions: | | | |
| | | Accrued construction expenses as of September 30, | $ | 119,943 |
| | $ | 111,052 |
|
| | | | | | |
| The accompanying notes are an integral part of the financial statements. |
NEVADA POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Shares | Common Stock Amount | Other Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity |
| December 31, 2011 | 1,000 |
| | $ | 1 |
| | $ | 2,308,219 |
| | $ | 544,874 |
| | $ | (4,117 | ) | | $ | 2,848,977 |
|
| Net Income | | | | | | | 256,151 |
| | | | 256,151 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(103)) | | | | | | | | | 192 |
| | 192 |
|
| Dividends Declared | | | | | | | (119,000 | ) | | | | (119,000 | ) |
| September 30, 2012 | 1,000 |
| | $ | 1 |
| | $ | 2,308,219 |
| | $ | 682,025 |
| | $ | (3,925 | ) | | $ | 2,986,320 |
|
| | | | | | | | | | | | |
| December 31, 2012 | 1,000 |
| | $ | 1 |
| | $ | 2,308,211 |
| | $ | 618,612 |
| | $ | (4,506 | ) | | $ | 2,922,318 |
|
| Net Income | | | | | | | 228,552 |
| | | | 228,552 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(156)) | | | | | | | | | 290 |
| | 290 |
|
| Dividends Declared | | | | | | | (105,000 | ) | | | | (105,000 | ) |
| September 30, 2013 | 1,000 |
| | $ | 1 |
| | $ | 2,308,211 |
| | $ | 742,164 |
| | $ | (4,216 | ) | | $ | 3,046,160 |
|
| | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. |
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
| | | September 30, | | September 30, |
| | | 2013 | | 2012 | | 2013 | | 2012 |
| | | | | | | | | |
| OPERATING REVENUES: | | | | | | | |
| | Electric | $ | 213,463 |
| | $ | 212,073 |
| | $ | 560,392 |
| | $ | 549,886 |
|
| | Gas | 13,543 |
| | 12,077 |
| | 73,480 |
| | 77,543 |
|
| Total Operating Revenues | 227,006 |
| | 224,150 |
| | 633,872 |
| | 627,429 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | |
| | Fuel for power generation | 54,827 |
| | 47,324 |
| | 141,277 |
| | 115,137 |
|
| | Purchased power | 33,388 |
| | 33,999 |
| | 114,755 |
| | 98,400 |
|
| | Gas purchased for resale | 7,383 |
| | 5,382 |
| | 62,277 |
| | 46,491 |
|
| | Deferral of energy - electric - net (Note 4) | (7,925 | ) | | (5,498 | ) | | (44,223 | ) | | (13,854 | ) |
| | Deferral of energy - gas - net (Note 4) | (1,964 | ) | | (853 | ) | | (22,315 | ) | | (970 | ) |
| | Energy efficiency program costs | 2,044 |
| | 4,092 |
| | 5,679 |
| | 11,143 |
|
| | Regulatory disallowance | 5,469 |
| | — |
| | 5,469 |
| | — |
|
| | Merger-related costs (Note 2) | 2,008 |
| | — |
| | 5,528 |
| | — |
|
| | Other operating expenses | 34,394 |
| | 34,128 |
| | 106,455 |
| | 104,214 |
|
| | Maintenance | 5,968 |
| | 6,481 |
| | 20,956 |
| | 23,596 |
|
| | Depreciation and amortization | 27,952 |
| | 27,537 |
| | 83,772 |
| | 80,594 |
|
| | Taxes other than income | 5,944 |
| | 5,894 |
| | 18,414 |
| | 17,382 |
|
| Total Operating Expenses | 169,488 |
| | 158,486 |
| | 498,044 |
| | 482,133 |
|
| OPERATING INCOME | 57,518 |
| | 65,664 |
| | 135,828 |
| | 145,296 |
|
| | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | |
| | Interest expense | | | | | | | |
| | (net of AFUDC-debt: $437, $448, $1,007 and $1,458) | (15,122 | ) | | (15,298 | ) | | (46,020 | ) | | (47,650 | ) |
| | Interest expense on regulatory items | (87 | ) | | (401 | ) | | 53 |
| | (715 | ) |
| | AFUDC-equity | 632 |
| | 582 |
| | 1,579 |
| | 1,843 |
|
| | Other income | 983 |
| | 1,399 |
| | 4,641 |
| | 4,181 |
|
| | Other expense | (982 | ) | | (998 | ) | | (3,803 | ) | | (3,609 | ) |
| Total Other Income (Expense) | (14,576 | ) | | (14,716 | ) | | (43,550 | ) | | (45,950 | ) |
| Income Before Income Tax Expense | 42,942 |
| | 50,948 |
| | 92,278 |
| | 99,346 |
|
| | | | | | | | | |
| Income tax expense | 13,691 |
| | 16,521 |
| | 30,347 |
| | 33,596 |
|
| | | | | | | | | |
| NET INCOME | 29,251 |
| | 34,427 |
| | 61,931 |
| | 65,750 |
|
| | | | | | | | | |
| Other comprehensive income | | | | | | | |
| Change in compensation retirement benefits liability and amortization | | | | | | | |
| (Net of taxes $(32), $(22), $(95) and $(68)) | 59 |
| | 42 |
| | 176 |
| | 127 |
|
| | | | | | | | | |
| COMPREHENSIVE INCOME | $ | 29,310 |
| | $ | 34,469 |
| | $ | 62,107 |
| | $ | 65,877 |
|
| | |
| | The accompanying notes are an integral part of the financial statements. |
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | |
| | | | September 30, | | December 31, |
| | | | 2013 | | 2012 |
| | | | | | |
| ASSETS | | | |
| | | | | | |
| Current Assets: | | | |
| | Cash and cash equivalents | $ | 84,128 |
| | $ | 60,786 |
|
| | Accounts receivable less allowance for uncollectible accounts: | | | |
| | | 2013 - $1,059; 2012 - $1,126 | 115,765 |
| | 124,464 |
|
| | Materials, supplies and fuel, at average cost | 50,770 |
| | 60,662 |
|
| | Deferred energy costs (Note 4) | 13,844 |
| | — |
|
| | Intercompany income taxes receivable | 10,351 |
| | 10,351 |
|
| | Deferred income taxes | 49,748 |
| | 21,589 |
|
| | Other current assets | 12,566 |
| | 11,633 |
|
| Total Current Assets | 337,172 |
| | 289,485 |
|
| | | | | | |
| Utility Property: | | | |
| | Plant in service | 3,736,104 |
| | 3,667,487 |
|
| | Construction work-in-progress | 125,681 |
| | 140,168 |
|
| | | Total | 3,861,785 |
| | 3,807,655 |
|
| | Less accumulated provision for depreciation | 1,323,504 |
| | 1,277,866 |
|
| | | Total Utility Property, Net | 2,538,281 |
| | 2,529,789 |
|
| | | | | | |
| Investments and other property, net | 7,126 |
| | 6,499 |
|
| | | | | | |
| Deferred Charges and Other Assets: | | | |
| | | Regulatory assets | 301,918 |
| | 328,755 |
|
| | | Regulatory asset for pension plans | 135,257 |
| | 140,268 |
|
| | | Deferred energy (Note 4) | 1,014 |
| | — |
|
| | | Other deferred charges and assets | 13,524 |
| | 21,477 |
|
| Total Deferred Charges and Other Assets | 451,713 |
| | 490,500 |
|
| | | | | | |
| TOTAL ASSETS | $ | 3,334,292 |
| | $ | 3,316,273 |
|
| |
| (Continued) |
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | |
| | | September 30, | | December 31, |
| | | 2013 | | 2012 |
| | | | | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | | | |
| | | | | |
| Current Liabilities: | | | |
| | Current maturities of long-term debt (Note 5) | $ | 271 |
| | $ | 250,235 |
|
| | Accounts payable | 84,277 |
| | 106,415 |
|
| | Accounts payable, affiliated companies | 21,543 |
| | 21,534 |
|
| | Accrued expenses | 29,909 |
| | 32,936 |
|
| | Deferred energy (Note 4) | — |
| | 50,763 |
|
| | Other current liabilities | 18,821 |
| | 13,655 |
|
| Total Current Liabilities | 154,821 |
| | 475,538 |
|
| | | | | |
| Long-term debt (Note 5) | 1,177,829 |
| | 928,990 |
|
| | | | | |
| Commitments and Contingencies (Note 8) |
| |
|
| | | | | |
| Deferred Credits and Other Liabilities: | | | |
| | Deferred income taxes | 525,694 |
| | 465,508 |
|
| | Deferred investment tax credit | 7,766 |
| | 8,850 |
|
| | Accrued retirement benefits | 75,133 |
| | 98,676 |
|
| | Regulatory liabilities | 255,232 |
| | 227,287 |
|
| | Other deferred credits and liabilities | 76,974 |
| | 72,688 |
|
| Total Deferred Credits and Other Liabilities | 940,799 |
| | 873,009 |
|
| | | | | |
| Shareholder's Equity: | | | |
| | Common stock, $3.75 par value; 20,000,000 shares authorized | | | |
| | 1,000 shares issued and outstanding for 2013 and 2012 | 4 |
| | 4 |
|
| | Other paid-in capital | 1,111,266 |
| | 1,111,266 |
|
| | Retained deficit | (49,055 | ) | | (70,986 | ) |
| | Accumulated other comprehensive loss | (1,372 | ) | | (1,548 | ) |
| Total Shareholder's Equity | 1,060,843 |
| | 1,038,736 |
|
| | | | | |
| TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | $ | 3,334,292 |
| | $ | 3,316,273 |
|
| | | | | |
| | The accompanying notes are an integral part of the financial statements. |
| | |
| | (Concluded) |
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
|
| | | | | | | | | |
| | | | For the Nine Months Ended |
| | | | September 30, |
| | | | 2013 | | 2012 |
| CASH FLOWS FROM (USED BY) OPERATING ACTIVITIES: | | | |
| | Net Income | $ | 61,931 |
| | $ | 65,750 |
|
| | Adjustments to reconcile net income to net cash from operating activities: | | | |
| | | Depreciation and amortization | 83,772 |
| | 80,594 |
|
| | | Deferred taxes and deferred investment tax credit | 32,847 |
| | 42,809 |
|
| | | AFUDC-equity | (1,579 | ) | | (1,843 | ) |
| | | Deferred energy | (65,622 | ) | | (11,367 | ) |
| | | Regulatory disallowance | 5,469 |
| | — |
|
| | | Amortization of other regulatory assets | 58,769 |
| | 58,484 |
|
| | | Other, net | 185 |
| | (15,532 | ) |
| | Changes in certain assets and liabilities: | | | |
| | | Accounts receivable | 17,700 |
| | 13,452 |
|
| | | Materials, supplies and fuel | 9,892 |
| | (12,915 | ) |
| | | Other current assets | (934 | ) | | (6,512 | ) |
| | | Accounts payable | (16,893 | ) | | (21,002 | ) |
| | | Accrued retirement benefits | (23,544 | ) | | (18,477 | ) |
| | | Other current liabilities | 2,141 |
| | (3,522 | ) |
| | | Other deferred assets | (2,021 | ) | | (1,160 | ) |
| | | Other regulatory assets | (3,302 | ) | | (15,588 | ) |
| | | Other deferred liabilities | (1,876 | ) | | (6,282 | ) |
| Net Cash from Operating Activities | 156,935 |
| | 146,889 |
|
| | | | | | |
| CASH FLOWS FROM (USED BY) INVESTING ACTIVITIES: | | | |
| | | Additions to utility plant (excluding AFUDC-equity) | (108,735 | ) | | (155,182 | ) |
| | | Customer advances for construction | (114 | ) | | (2,221 | ) |
| | | Contributions in aid of construction | 18,451 |
| | 29,590 |
|
| | | Investments and other property - net | 24 |
| | 24 |
|
| Net Cash used by Investing Activities | (90,374 | ) | | (127,789 | ) |
| | | | | | |
| CASH FLOWS FROM (USED BY) FINANCING ACTIVITIES: | | | |
| | | Proceeds from issuance of long-term debt, net of costs | 247,506 |
| | (1,447 | ) |
| | | Retirement of long-term debt | (250,725 | ) | | (1,112 | ) |
| | | Dividends paid | (40,000 | ) | | (20,000 | ) |
| Net Cash used by Financing Activities | (43,219 | ) | | (22,559 | ) |
| | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | 23,342 |
| | (3,459 | ) |
| Beginning Balance in Cash and Cash Equivalents | 60,786 |
| | 55,195 |
|
| Ending Balance in Cash and Cash Equivalents | $ | 84,128 |
| | $ | 51,736 |
|
| | | | | | |
| Supplemental Disclosures of Cash Flow Information: | | | |
| | Cash paid during period for: | | | |
| | | Interest | $ | 45,554 |
| | $ | 45,772 |
|
| | Significant non-cash transactions: | | | |
| | | Accrued construction expenses as of September 30, | $ | 21,271 |
| | $ | 21,060 |
|
| | | | | | |
| The accompanying notes are an integral part of the financial statements. |
SIERRA PACIFIC POWER COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Dollars in Thousands, Except Share Amounts)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock Shares | Common Stock Amount | Other Paid-in Capital | Retained Earnings | Accumulated Other Comprehensive Income (Loss) | Total Shareholders' Equity |
| | | | | | | | | | | | |
| December 31, 2011 | 1,000 |
| | $ | 4 |
| | $ | 1,111,262 |
| | $ | (135,340 | ) | | $ | (1,384 | ) | | $ | 974,542 |
|
| Net Income | | | | | | | 65,750 |
| | | | 65,750 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(68)) | | | | | | | | | 127 |
| | 127 |
|
| Dividends Declared | | | | | | | (20,000 | ) | | | | (20,000 | ) |
| September 30, 2012 | 1,000 |
| | $ | 4 |
| | $ | 1,111,262 |
| | $ | (89,590 | ) | | $ | (1,257 | ) | | $ | 1,020,419 |
|
| | | | | | | | | | | | |
| December 31, 2012 | 1,000 |
| | $ | 4 |
| | $ | 1,111,266 |
| | $ | (70,986 | ) | | $ | (1,548 | ) | | $ | 1,038,736 |
|
| Net Income | | | | | | | 61,931 |
| | | | 61,931 |
|
| Change in compensation retirement benefits liability and amortization (net of taxes $(95)) | | | | | | | | | 176 |
| | 176 |
|
| Dividends Declared | | | | | | | (40,000 | ) | | | | (40,000 | ) |
| September 30, 2013 | 1,000 |
| | $ | 4 |
| | $ | 1,111,266 |
| | $ | (49,055 | ) | | $ | (1,372 | ) | | $ | 1,060,843 |
|
| | | | | | | | | | | | |
| The accompanying notes are an integral part of the financial statements. |
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1) Organization and Operations
NOTE1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The significant accounting policies for both utility and non-utility operations are as follows:
Basis of Presentation
The consolidated financial statements includeNevada Power Company, together with its subsidiaries (collectively, the accounts"Company"), is a wholly owned subsidiary of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC,("NV Energy"), a holding company that also owns Sierra Pacific Communications, LandsPower Company ("Sierra Pacific") and certain other subsidiaries. The Company is a United States utility company serving electric 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 Sierra,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., NVE Insurance Company, Inc. and Sierra Gas Holding Company. All intercompany balances and transactions
The unaudited Consolidated Financial Statements have been eliminatedprepared in consolidation.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 June 30, 2014 and for the three- and six-month periods ended June 30, 2014 and 2013. Certain amounts in the prior periods Consolidated Statement of Operations have been reclassified to conform to the current period's presentation. Such reclassifications did not impact previously reported net income. The results of operations for the three- and six-month periods ended June 30, 2014 are not necessarily indicative of the results to be expected for the full year.
The preparation of consolidated financial statementsthe unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities. These estimates and assumptions also affect the disclosure of contingent assets and liabilities at the date of the financial statementsunaudited Consolidated Financial Statements and the reported amounts of certain revenuesrevenue and expenses during the reporting period. Actual results couldmay differ from these estimates.
In the opinionestimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of the management of NVE, NPC and SPPC, the accompanying unaudited interim consolidated financial statements contain normal and recurring adjustments necessaryNotes to present fairly the consolidated financial position, results of operations and cash flows for the periods shown. These consolidated financial statements do not contain the complete detail concerning accounting policies and other matters, which are included in full year financial statements; therefore, they should be read in conjunction with the audited financial statementsConsolidated Financial Statements included in the 2012Company's Annual Report on Form 10-K.
The results of operations and cash flows of NVE, NPC and SPPC10-K for the nine monthsyear ended September 30,December 31, 2013 are not necessarily indicativedescribes the most significant accounting policies used in the preparation of the resultsunaudited Consolidated Financial Statements. There have been no significant changes in the Company's assumptions regarding significant accounting estimates and policies during the six-month period ended June 30, 2014.
(2) New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, which creates FASB Accounting Standards Codification ("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 expectedentitled in exchange for those goods or services. Additionally, the full year.
Accounting Policies
Consolidations of VIEs
To identify potential variable interests, management reviewed contracts under leases, long-term purchase power contracts, tolling contracts and jointly owned facilities. The Utilities identified certain long-term purchase power contracts that could be defined as variable interests. However, the Utilities are not the primary beneficiary as they primarily lacked the power to direct the activities ofguidance requires the entity includingto disclose further quantitative and qualitative information regarding the ability to operate the generating facilitiesnature and make management decisions. The Utilities' maximum exposure to loss is limited to the cost of replacing these purchase power contracts if the providers are unable to deliver power. However, the Utilities believe their exposure is mitigated as they would likely recover these costs through their deferred energy accounting mechanism. As of September 30, 2013, the carrying amount of assetsrevenues arising from contracts with customers, as well as other information about the significant judgments and liabilitiesestimates used in the Utilities’ balance sheets that relate to their involvementrecognizing revenues from contracts with VIEs are predominately related to working capital accounts and generally represent the amounts owed by the Utilities for the deliveries associated with the current billing cycle under the contracts.
Recent Accounting Standards Update
Derivatives and Hedging (ASC815)
In July 2013, the FASB amended its existingcustomers. This guidance related to hedge accounting. The amendment permits the Fed Funds Effective Swap Rate (OIS) to be used as a U.S benchmark interest rate for hedge accounting purposes under ASC 815, in addition, to the current approved U.S. rates which include interest rates on direct Treasury obligations of the U.S. government (UST) and LIBOR. The amendment is effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. The adoption of this guidance did not have an impact on the presentation of the consolidated financial statements or disclosure requirements for NVE and the Utilities.
Income Taxes (ASC 740)
In July 2013, the FASB amended its existing guidance related to the presentation of an unrecognized tax benefit on the financial statements. ASC 740, Income Taxes, does not include explicit guidance on the financial statement presentation of an unrecognized tax benefit when a NOL carryforward, a similar tax loss, or a tax credit carryforward exists. As a result, there is diversity in practice in the presentation of unrecognized tax benefits. The objective of the amendment is to eliminate the diversity in practice, requiring the
unrecognized tax benefit, or a portion of an unrecognized tax benefit, be presented in the financial statements as a reduction to a deferred tax asset for a NOL carryforward, a similar tax loss, or a tax credit carryforward with certain exceptions. The amendment can be applied prospectively or retrospectively and is effective for fiscal years,interim and interimannual reporting periods within those years, beginning after December 15, 2016. Early application is not permitted. 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.
In February 2013, the FASB issued ASU No. 2013-04, which amends FASB ASC Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for public entities. NVEwhich the total amount of the obligation is fixed at the reporting date as the amount the reporting entity agreed to pay plus any additional amounts the reporting entity expects to pay on behalf of its co-obligor. Additionally, the guidance requires the entity to disclose the nature and amount of the Utilities have elected to early adoptobligation, as well as other information about those obligations. This guidance is effective for interim and annual reporting periods beginning after December 15, 2013. The Company adopted this amendment prospectively as of September 30, 2013, presenting their unrecognized tax benefit as a reduction to their NOL deferred tax asset.guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the presentation of the financial statements for NVE and the Utilities.
Federal Income Tax Regulations
In September 2013, the Internal Revenue Service and the U.S. Treasury Department released final tax regulations on the deduction and capitalization of expenditures related to tangible property. These regulations apply to tax years beginning on or after January 1, 2014. NVE and the Utilities continue to evaluate the effects of the tangible property regulations as well as the generation guidance in Revenue Procedure 2013-24, but do not believe that these tax regulations will have a material impact on the presentation of the financial statements for NVE and the Utilities.
Other Comprehensive Income (ASC 220)
In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income. In February 2013, the FASB reinstated certain portions of the deferred amendment. The reinstated amendment is applied prospectively and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have an impact on the presentation of the financial statements for NVE and the Utilities.
Balance Sheet Offsetting Disclosures (ASC 210)
In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance currentCompany's disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. The scope of this amendment includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements. The amendment is applied retrospectively to all periods presented and is effective for NVE and the Utilities as of January 1, 2013. The adoption of this guidance did not have an impact on the disclosure requirements for NVE and the Utilities.
NOTE 2. MERGER-RELATED ACTIVITIES
MidAmerican Merger
On May 29, 2013, NVE entered into the MidAmerican Merger Agreement. The MidAmerican Merger Agreement provides for the merger of Silver Merger Sub, Inc. with and into NVE, with NVE continuing as the surviving corporation. Once merged, NVE will become an indirect wholly owned subsidiary of MEHC. The closing is expected to occur in late 2013 or the first quarter of 2014.
Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest and subject to applicable withholding taxes.
The MidAmerican Merger Agreement has been approved by the BOD of both NVE and MEHC, but the consummation of the MidAmerican Merger is subject to the satisfaction or waiver of specified closing conditions, including:
the approval of the MidAmerican Merger Agreement by the holders of a majority of the outstanding shares of NVE common stock. On September 25, 2013, NVE’s stockholders approved the MidAmerican Merger Agreement. Consequently, this closing condition has been satisfied;
the receipt of regulatory approvals and other consents required to consummate the MidAmerican Merger, including, among others, approvals from the PUCN and the FERC on terms and conditions specified in the MidAmerican Merger Agreement (in July 2013, filings were made with the PUCN and FERC. See Note 4, Regulatory Actions, for further details of these filings);
the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. On July 22, 2013, NVE was advised that the Department of Justice and the U.S. Federal Trade Commission
had terminated the applicable waiting period under the Hart-Scott-Rodino Act. Consequently, the closing condition with respect to the Hart-Scott-Rodino Act has been satisfied;
the absence of the occurrence of a company material adverse effect (as defined in the MidAmerican Merger Agreement) after the date of the MidAmerican Merger Agreement; and
other customary closing conditions.
The MidAmerican Merger Agreement contains customary representations, warranties and covenants for both NVE and MEHC. These covenants include an obligation for us, subject to certain exceptions, to conduct our business in a manner substantially consistent with our current practice. In addition, the covenants contain several restrictions that apply unless MEHC’s consent is received, including limitations on making certain business acquisitions, limitations on our total capital spending, limitations on the extent to which we may obtain financing through long-term debt or equity issuances and limitations on increasing our common stock dividend payout.
The MidAmerican Merger Agreement contains certain termination rights and fees for both NVE and MEHC. In the event of termination of the MidAmerican Merger under certain circumstances, NVE may be obligated to pay MEHC a termination fee of up to $169.7 million.
During the three and nine month periods ending September 30, 2013, NVE incurred $7.9 million (pre-tax) and $21.4 million (pre-tax) of merger-related fees and stock compensation costs related to the MidAmerican Merger which have been expensed and presented on the Statement of Comprehensive Income as Merger-Related Costs. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation, upon announcement of the MidAmerican Merger. NVE expects to incur additional merger fees relating to the MidAmerican Merger upon consummation of the MidAmerican Merger.
As a result of the pending MidAmerican Merger, NVE, its directors, Silver Merger Sub, Inc. and, in some cases, MEHC, have been named as defendants in certain lawsuits brought by alleged NVE shareholders seeking, among other things, to enjoin the proposed MidAmerican Merger; see Note 8, Commitments and Contingencies for further details. In addition, NVE has ceased the repurchase of any common stock for NVE stock compensation plans; see Note 10, Common Stock and Other Paid-In Capital.
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities. As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of parincluded within 10 days after the MidAmerican Merger closing. At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these debt securities is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively. To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of the Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.
One Company Merger between NPC and SPPC
As detailed further in Note 4, Regulatory Actions, NPC and SPPC filed a joint application with the PUCN to merge SPPC into NPC (“One Company Merger”) and to call the surviving entity NVEOC. The One Company Merger is subject to approval by the PUCN and FERC.
NOTE 3. SEGMENT INFORMATION
The Utilities operate three regulated business segments, NPC electric, SPPC electric and SPPC natural gas service, which are reported in accordance with Segment Reporting of the FASC. Electric service is provided to Las Vegas and surrounding Clark County by NPC, and to northern Nevada by SPPC. Natural gas services are provided by SPPC in the Reno-Sparks area of Nevada. Other information includes amounts below the quantitative thresholds for separate disclosure.
Operational information of the different business segments is set forth below based on the nature of products and services offered. NVE evaluates performance based on several factors, of which the primary financial measure is business segment gross margin. Gross
margin, which the Utilities calculate as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances provides a measure of income available to support the other operating expenses of the Utilities. See Note 1, Summary of Significant Accounting Policies, of the Notes to Consolidated Financial Statements in the 2012 Form 10-K for further information regarding energy efficiency program costs.
Operating expenses are provided by segment in order to reconcile to operating income as reported in the consolidated financial statements (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | | | | | | | | |
| September 30, 2013 | | | | | | | | | | | |
| | | NVE Consolidated | | NVE Other | | NPC Electric | | SPPC Total | | SPPC Electric | | SPPC Gas |
| Operating Revenues | $ | 1,013,151 |
| | $ | 3 |
| | $ | 786,142 |
| | $ | 227,006 |
| | $ | 213,463 |
| | $ | 13,543 |
|
| | | | | | |
|
| | | | | | |
| Energy Costs: | |
| | |
| |
|
| | |
| | |
| | |
|
| Fuel for power generation | 217,954 |
| | — |
| | 163,127 |
| | 54,827 |
| | 54,827 |
| | — |
|
| Purchased power | 205,970 |
| | — |
| | 172,582 |
| | 33,388 |
| | 33,388 |
| | — |
|
| Gas purchased for resale | 7,383 |
| | — |
| | — |
| | 7,383 |
| | — |
| | 7,383 |
|
| Deferred energy | (55,270 | ) | | — |
| | (45,381 | ) | | (9,889 | ) | | (7,925 | ) | | (1,964 | ) |
| Energy efficiency program costs | 16,042 |
| | — |
| | 13,998 |
| | 2,044 |
| | 2,044 |
| | — |
|
| Regulatory disallowance | 17,335 |
| | — |
| | 11,866 |
| | 5,469 |
| | 5,469 |
| | — |
|
| Total Costs | $ | 409,414 |
| | $ | — |
| | $ | 316,192 |
| | $ | 93,222 |
| | $ | 87,803 |
| | $ | 5,419 |
|
| | | | | | | | | | | | | |
| Gross Margin | $ | 603,737 |
| | $ | 3 |
| | $ | 469,950 |
| | $ | 133,784 |
| | $ | 125,660 |
| | $ | 8,124 |
|
| | | | | | | | | | | | | |
| Merger-related costs | 7,857 |
| | 229 |
| | 5,620 |
| | 2,008 |
| | |
| | |
| Other operating expenses | 106,068 |
| | 830 |
| | 70,844 |
| | 34,394 |
| | |
| | |
| Maintenance | 17,176 |
| | — |
| | 11,208 |
| | 5,968 |
| | |
| | |
| Depreciation and amortization | 96,801 |
| | — |
| | 68,849 |
| | 27,952 |
| | |
| | |
| Taxes other than income | 14,214 |
| | 57 |
| | 8,213 |
| | 5,944 |
| | |
| | |
| Operating Income (Loss) | $ | 361,621 |
| | $ | (1,113 | ) | | $ | 305,216 |
| | $ | 57,518 |
| | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended | | | | | | | | | | | |
| September 30, 2013 | | | | | | | | | | | |
| | | NVE Consolidated | | NVE Other | | NPC Electric | | SPPC Total | | SPPC Electric | | SPPC Gas |
| Operating Revenues | $ | 2,329,011 |
| | $ | 10 |
| | $ | 1,695,129 |
| | $ | 633,872 |
| | $ | 560,392 |
| | $ | 73,480 |
|
| | | | | | | | | | | | | |
| Energy Costs: | |
| | |
| | | | |
| | |
| | |
|
| Fuel for power generation | 554,181 |
| | — |
| | 412,904 |
| | 141,277 |
| | 141,277 |
| | — |
|
| Purchased power | 498,141 |
| | — |
| | 383,386 |
| | 114,755 |
| | 114,755 |
| | — |
|
| Gas purchased for resale | 62,277 |
| | — |
| | — |
| | 62,277 |
| | — |
| | 62,277 |
|
| Deferred energy | (221,022 | ) | | — |
| | (154,484 | ) | | (66,538 | ) | | (44,223 | ) | | (22,315 | ) |
| Energy efficiency program costs | 38,486 |
| | — |
| | 32,807 |
| | 5,679 |
| | 5,679 |
| | — |
|
| Regulatory disallowance | 17,335 |
| | — |
| | 11,866 |
| | 5,469 |
| | 5,469 |
| | — |
|
| Total Costs | $ | 949,398 |
| | $ | — |
| | $ | 686,479 |
| | $ | 262,919 |
| | $ | 222,957 |
| | $ | 39,962 |
|
| | | | | | | | | | | | | |
| Gross Margin | $ | 1,379,613 |
| | $ | 10 |
| | $ | 1,008,650 |
| | $ | 370,953 |
| | $ | 337,435 |
| | $ | 33,518 |
|
| | | | | | | | | | | | | |
| Merger-related costs | 21,409 |
| | 1,394 |
| | 14,487 |
| | 5,528 |
| | |
| | |
| Other operating expenses | 317,538 |
| | 2,747 |
| | 208,336 |
| | 106,455 |
| | |
| | |
| Maintenance | 66,128 |
| | — |
| | 45,172 |
| | 20,956 |
| | |
| | |
| Depreciation and amortization | 291,687 |
| | — |
| | 207,915 |
| | 83,772 |
| | |
| | |
| Taxes other than income | 46,536 |
| | 318 |
| | 27,804 |
| | 18,414 |
| | |
| | |
| Operating Income (Loss) | $ | 636,315 |
| | $ | (4,449 | ) | | $ | 504,936 |
| | $ | 135,828 |
| | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | | | | | | | | |
| September 30, 2012 | | | | | | | | | | | |
| | | NVE Consolidated | | NVE Other | | NPC Electric | | SPPC Total | | SPPC Electric | | SPPC Gas |
| Operating Revenues | $ | 1,026,488 |
| | $ | 4 |
| | $ | 802,334 |
| | $ | 224,150 |
| | $ | 212,073 |
| | $ | 12,077 |
|
| | | | | | |
|
| | | | | | |
| Energy Costs: | |
| | |
| |
|
| | |
| | |
| | |
|
| Fuel for power generation | 171,316 |
| | — |
| | 123,992 |
| | 47,324 |
| | 47,324 |
| | — |
|
| Purchased power | 205,686 |
| | — |
| | 171,687 |
| | 33,999 |
| | 33,999 |
| | — |
|
| Gas purchased for resale | 5,382 |
| | — |
| | — |
| | 5,382 |
| | — |
| | 5,382 |
|
| Deferred energy | (29,036 | ) | | — |
| | (22,685 | ) | | (6,351 | ) | | (5,498 | ) | | (853 | ) |
| Energy efficiency program costs | 32,584 |
| | — |
| | 28,492 |
| | 4,092 |
| | 4,092 |
| | — |
|
| Total Costs | $ | 385,932 |
| | $ | — |
| | $ | 301,486 |
| | $ | 84,446 |
| | $ | 79,917 |
| | $ | 4,529 |
|
| | | | | | | | | | | | | |
| Gross Margin | $ | 640,556 |
| | $ | 4 |
| | $ | 500,848 |
| | $ | 139,704 |
| | $ | 132,156 |
| | $ | 7,548 |
|
| | | | | | | | | | | | | |
| Other operating expenses | 100,108 |
| | 608 |
| | 65,372 |
| | 34,128 |
| | |
| | |
| Maintenance | 19,014 |
| | — |
| | 12,533 |
| | 6,481 |
| | |
| | |
| Depreciation and amortization | 94,512 |
| | — |
| | 66,975 |
| | 27,537 |
| | |
| | |
| Taxes other than income | 15,682 |
| | 45 |
| | 9,743 |
| | 5,894 |
| | |
| | |
| Operating Income (Loss) | $ | 411,240 |
| | $ | (649 | ) | | $ | 346,225 |
| | $ | 65,664 |
| | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended | | | | | | | | | | | |
| September 30, 2012 | | | | | | | | | | | |
| | | NVE Consolidated | | NVE Other | | NPC Electric | | SPPC Total | | SPPC Electric | | SPPC Gas |
| Operating Revenues | $ | 2,378,606 |
| | $ | 12 |
| | $ | 1,751,165 |
| | $ | 627,429 |
| | $ | 549,886 |
| | $ | 77,543 |
|
| | | | | | |
|
| | | | | | |
| Energy Costs: | |
| | |
| |
|
| | |
| | |
| | |
|
| Fuel for power generation | 400,936 |
| | — |
| | 285,799 |
| | 115,137 |
| | 115,137 |
| | — |
|
| Purchased power | 486,894 |
| | — |
| | 388,494 |
| | 98,400 |
| | 98,400 |
| | — |
|
| Gas purchased for resale | 46,491 |
| | — |
| | — |
| | 46,491 |
| | — |
| | 46,491 |
|
| Deferred Energy | (30,285 | ) | | — |
| | (15,461 | ) | | (14,824 | ) | | (13,854 | ) | | (970 | ) |
| Energy efficiency program costs | 76,609 |
| | — |
| | 65,466 |
| | 11,143 |
| | 11,143 |
| | — |
|
| Total Costs | $ | 980,645 |
| | $ | — |
| | $ | 724,298 |
| | $ | 256,347 |
| | $ | 210,826 |
| | $ | 45,521 |
|
| | | | | | | | | | | | | |
| Gross Margin | $ | 1,397,961 |
| | $ | 12 |
| | $ | 1,026,867 |
| | $ | 371,082 |
| | $ | 339,060 |
| | $ | 32,022 |
|
| | | | | | | | | | | | | |
| Other operating expenses | 307,080 |
| | 2,382 |
| | 200,484 |
| | 104,214 |
| | | | |
| Maintenance | 76,190 |
| | — |
| | 52,594 |
| | 23,596 |
| | | | |
| Depreciation and amortization | 281,690 |
| | — |
| | 201,096 |
| | 80,594 |
| | | | |
| Taxes other than income | 44,457 |
| | 282 |
| | 26,793 |
| | 17,382 |
| | | | |
| Operating Income (Loss) | $ | 688,544 |
| | $ | (2,652 | ) | | $ | 545,900 |
| | $ | 145,296 |
| | | | |
(3) Property, Plant and Equipment, Net
NOTE 4. REGULATORY ACTIONS
NPCProperty, plant and SPPC follow deferred energy accounting. See Note 3, Regulatory Actions,equipment, net consists of the Notes to Financial Statements in the 2012 Form 10-K for additional information regarding deferred energy accounting by the Utilities.
The following deferred energy amounts were included in the consolidated balance sheets as of September 30, 2013 (dollars in thousands)(in millions):
|
| | | | | | | | | | | | | | | |
| | September 30, 2013 |
| | NVE Total | | NPC Electric | | SPPC Electric | | SPPC Gas |
| Deferred Energy | | | | | | | |
| Cumulative Deferred Balance authorized in 2013 DEAA | $ | (152,990 | ) | | $ | (102,227 | ) | | $ | (32,693 | ) | | $ | (18,070 | ) |
| 2013 Amortization | 111,977 |
| | 69,288 |
| | 23,695 |
| | 18,994 |
|
2013 Deferred Energy Under Collections (1) | 118,397 |
| | 95,465 |
| | 19,697 |
| | 3,235 |
|
| Deferred Energy Balance at September 30, 2013 - Subtotal | $ | 77,384 |
| | $ | 62,526 |
| | $ | 10,699 |
| | $ | 4,159 |
|
| Reinstatement of deferred energy (effective 6/07, 10 years) | 89,906 |
| | 89,906 |
| | — |
| | — |
|
| Total Deferred Energy | $ | 167,290 |
| | $ | 152,432 |
| | $ | 10,699 |
| | $ | 4,159 |
|
| | | | | | | | |
| Current Assets | | | | | | | |
| Deferred energy | $ | 82,235 |
| | $ | 68,391 |
| | $ | 10,322 |
| | $ | 3,522 |
|
| Non-current Assets | | | | | | | |
| Deferred energy | 85,055 |
| | 84,041 |
| | 377 |
| | 637 |
|
| Total Net Deferred Energy | $ | 167,290 |
| | $ | 152,432 |
| | $ | 10,699 |
| | $ | 4,159 |
|
|
| | | | | | | |
| | As of |
| | June 30, | | December 31, |
| | 2014 | | 2013 |
| Utility plant in-service: | | | |
| Generation | $ | 3,823 |
| | $ | 3,789 |
|
| Distribution | 2,982 |
| | 2,936 |
|
| Transmission | 1,769 |
| | 1,743 |
|
| General and intangible plant | 684 |
| | 645 |
|
| Utility plant in-service | 9,258 |
| | 9,113 |
|
| Accumulated depreciation and amortization | (2,329 | ) | | (2,217 | ) |
| Utility plant in-service, net | 6,929 |
| | 6,896 |
|
| Other non-regulated, net of accumulated depreciation and amortization | 4 |
| | 3 |
|
| | 6,933 |
| | 6,899 |
|
| Construction work-in-progress | 33 |
| | 93 |
|
| Property, plant and equipment, net | $ | 6,966 |
| | $ | 6,992 |
|
| |
(1)
| These deferred energy under collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting, of the Notes to the Financial Statements in the 2012 Form 10-K. |
(4) Regulatory Matters
Pending Regulatory Actions
Energy Efficiency Implementation Rates
Nevada Power Company and Sierra Pacific Power Company
Joint Application forThe PUCN's final order approving the merger between NVEBHE and MEHC (MidAmerican Merger)
In July 2013, NVE and MEHC filed a joint application withNV Energy stipulated that the PUCN seeking the authorizationCompany will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 50% of the MidAmerican Merger. Under Nevada law, the PUCN may not authorize the MidAmerican Merger unless it finds, among other things,lost revenue that the transaction is “inCompany could otherwise request. In February 2014, the public interest”. If the PUCN does not issue a final order regarding the MidAmerican Merger within 180 days of the application filing date, the transaction will be deemed to be authorized. Based on the date of filing, the expected authorization date for the joint application between NVE and MEHC is January 2014. Hearings are scheduled for November 2013.
Joint Application of NPC and SPPC (One Company Merger Filing)
In May 2013, NPC and SPPC filed a jointan application with the PUCN to consolidatereset the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:
Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility NVEOC;
Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and
Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.
The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.” The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in Februaryenergy efficiency implementation rate. In June 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014.
Financing Application
Concurrent with the One Company Merger filing, NPC and SPPC filed a joint financing application with the PUCN. The application requested the PUCN to restate and review the Utilities’ existing unused authority and to assign and consolidate the unused authority under NVEOC. In addition, the application requests new authority of $705.0 million. The consolidated authority would give NVEOC authority to issue new debt of $1.1 billion and authority to refinance or redeem debt of $1.5 billion. The application does not seek a change to NPC’s and SPPC’s existing revolving credit facility authority of $1.3 billion and $600 million, respectively. The Utilities have requested that the financing application be consolidated with the One Company Merger filing. However, as the One Company Merger will not be approved prior to the December 31, 2013 expiration of NPC’s current financing authority, NPC requested that its current authority be extended, as well as additional authority to refinance debt of $255 million. In September 2013, the PUCN accepted a stipulation extending NPC’s existing financing authority until an order is issued into adjust the Oneenergy efficiency implementation rate, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company Merger filing.
Nevada Power Company
NPC 2013 DEAA, REPR, TRED, EEIR and EEPR Rate Filings
In March 2013, NPC filed an applicationwould otherwise be allowed to recover for the PUCN2014 calendar year. The energy efficiency implementation rate will be effective from July through December 2014 and will reset on January 1, 2015 and remain in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to review fuel and purchased power transactions forset base general rates, the 12-month period ended December 31, 2012, andCompany is required to reset the REPR, TRED, EEIR and EEPRrefund to customers energy efficiency implementation rate elements. In September 2013, the PUCN issued an order disallowing approximately $1.1 million (pre-tax) in deferred energy costs, which NPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, the PUCN indicated in their order that EEIR revenue should not contribute to the Utilities earning more than their authorized ROR.collected. As NPC earned in excess of its authorized ROR in 2012, the PUCN disallowed approximately $10.8 million in pre-tax EEIR revenues (including carrying charges) which was expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013. Furthermore, as a result, the Company has deferred recognition of this orderenergy efficiency implementation rate revenue collected and NPC’s estimated 2013 ROR calculated to be in excess of its authorized ROR, NPC has recorded a provision for refundliability of $11.2$7 million pre-tax against operating revenues, representing all EEIR revenues recorded duringon the nine months ended SeptemberConsolidated Balance Sheets as of June 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):
|
| | | | | | | | | | | | | |
| | Effective Date | | Authorized Revenue Requirement | | Present Revenue Requirement | | $ Change in Revenue Requirement |
| Revenue Requirement Subject To Change: | | | | | | | |
REPR (1) | Oct. 2013 | | $ | 28.4 |
| | $ | 38.7 |
| | $ | (10.3 | ) |
TRED (1) | Oct. 2013 | | 15.7 |
| | 15.9 |
| | (0.2 | ) |
EEPR Base (1) | Oct. 2013 | | 45.9 |
| | 32.6 |
| | 13.3 |
|
EEPR Amortization (1) | Oct. 2013 | | (29.9 | ) | | 9.0 |
| | (38.9 | ) |
EEIR Base (2) | Oct. 2013 | | 15.1 |
| | 10.6 |
| | 4.5 |
|
EEIR Amortization (3) | Oct. 2013 | | (17.2 | ) | | 10.7 |
| | (27.9 | ) |
| Total Revenue Requirement | | | $ | 58.0 |
| | $ | 117.5 |
| | $ | (59.5 | ) |
| |
(1)
| Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income. |
| |
(2)
| The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if NPC earns in excess of its authorized ROR. In future periods, NPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR. |
| |
(3)
| Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013. |
Sierra Pacific Power Company
SPPC Electric General Rate Case
In June 2013, SPPC filed its statutorily required GRC for its Nevada electric operations and updated the filing in August 2013. In the updated filing, SPPC is requesting the following:
Decrease in general rates by $4.7 million, approximately a 0.7% decrease; and
ROE and ROR of 10.4% and 7.74%, respectively.
Hearings are scheduled for October 2013In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requests incremental annual revenue relief in the amount of $38 million, or an average price increase of 2%. An order is expected by the end of 2014 and, if approved, the new rates would be effective January 1, 2014.
SPPC Gas General Rate Case
In June 2013, SPPC filed a GRC for its gas operations and updated the filing in August 2013. In the updated filing, SPPC is requesting the following:
Increase in general rates by $6.0 million, approximately a 6.1% increase; and
ROE and ROR of 10.35% and 7.72%, respectively.2015.
Hearings are scheduled for October 2013 and, if approved, the new rates would be effective January 1, 2014.
SPPC 2013 Electric DEAA, REPR, TRED, EEIR and EEPR Rate Filings
In March 2013, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ended December 31, 2012, and to reset the REPR, TRED, EEPR and EEIR rate elements. In September 2013, the PUCN issued an order disallowing approximately $0.1 million (pre-tax) in deferred energy costs, which SPPC expensed as a regulatory disallowance for the three and nine month periods ended September 30, 2013 and correspondingly adjusted the deferred energy balance as reflected in the table above. In addition, with respect to the EEIR disallowance discussed above under NPC, the PUCN disallowed $5.5 million (pre-tax) of SPPC's 2012 EEIR revenues, (including carrying charges) as a result of earning in excess of its authorized ROR. As a result $5.5 million was expensed as a regulatory disallowance for the three and nine months ended September 30, 2013. Also, similar to NPC, SPPC’s estimated 2013 ROR is calculated to be in excess of its authorized ROR, as such, SPPC has recorded a provision for refund of $4.0 million pre-tax against operating revenues, representing all EEIR revenues recorded during the nine months ended September 30, 2013. The September PUCN order includes the following changes in revenue requirement (dollars in millions):
|
| | | | | | | | | | | | | |
| |
Effective Date | | Authorized Revenue Requirement | | Present Revenue Requirement | | $ Change in Revenue Requirement |
| Revenue Requirement Subject To Change: | | | | | | | |
REPR (1) | Oct. 2013 | | $ | 42.3 |
| | $ | 44.4 |
| | $ | (2.1 | ) |
TRED (1) | Oct. 2013 | | 7.4 |
| | 6.3 |
| | 1.1 |
|
EEPR Base (1) | Oct. 2013 | | 6.0 |
| | 5.6 |
| | 0.4 |
|
EEPR Amortization (1) | Oct. 2013 | | (2.1 | ) | | 1.8 |
| | (3.9 | ) |
EEIR Base (2) | Oct. 2013 | | 5.5 |
| | 4.7 |
| | 0.8 |
|
EEIR Amortization (3) | Oct. 2013 | | (3.7 | ) | | 1.9 |
| | (5.6 | ) |
| Total Revenue Requirement | | | $ | 55.4 |
| | $ | 64.7 |
| | $ | (9.3 | ) |
| |
(1)
| Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues collected. As a result, such programs have no effect on Operating or Net Income. |
| |
(2)
| The authorized revenue requirement for EEIR Base may be subject to refund based on the PUCN order discussed above if SPPC earns in excess of its authorized ROR. In future periods, SPPC may record a provision against revenues to the extent its estimated ROR exceeds its authorized ROR. |
| |
(3)
| Amounts related to the EEIR revenue disallowance, discussed above, are required to be refunded back to ratepayers through negative EEIR amortization; however, while these amounts will affect cash flow, they will not have a future impact on revenues, as the disallowance was recognized as of September 30, 2013. |
SPPC 2013 Nevada Gas DEAA and REPR Rate Filings
In March 2013, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ended December 31, 2012 and to reset the REPR. DEAA amounts subject to prudency review for cumulative balances as of December 31, 2012 are included in the deferred energy table above. In September 2013, the PUCN issued an order resulting in an overall decrease in revenue requirement of $0.2 million.
FERC Matters
NPC
NPC 2012 FERC Transmission Rate Case
In October 2012, NPCMay 2013, the Company, along with Sierra Pacific, filed an application with the FERC to resetestablish single system transmission and ancillary service rates that were last set in 2003. In December 2012, FERC issued an order which suspended the proposedrates. The combined filing requested incremental rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreasesrelief of $17 million annually to be effective January 1, 2013. All rates are currently2014. On August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to refund, and final approval byset the FERC. However, at this time management is unable to determine the final revenue impact of the case.
SPPC
SPPC 2012 FERC Transmission Rate Case
In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013.case for hearing or settlement discussions. On June 17, 2013, SPPC filed an unopposed settlement agreement resolving all issues with the FERC, for approval for rates effective June 1, 2013. FERC approved the settlement on August 29, 2013. The rate changes under the terms of the settlement agreement are expected to result in an overall annual revenue increase of $1.5 million.
NVE, NPC and SPPC
2013 FERC Transmission Rate Case
In May 2013, NPC and SPPC filed an application with the FERC to reset transmission and ancillary service rates effective on the later of January 1, 2014, or the ON Line in-service date. The rate changes reflectCompany implemented the addition of the ON Linefiled rates in the transmission revenue requirement. Various intervenors filed protests and NPC and SPPC filed a response to those protests on July 16, 2013. On August 5, 2013, FERC issued an order which suspended the rate changes until January 1, 2014 or the in-service date for ON Line,this case subject to refund. On August 12, 2013refund as set forth in FERC's order. As of June 30, 2014, the FERC designated a Settlement JudgeCompany accrued $7 million for amounts subject to rate refund, which is included in customer deposits and other on the matter is now in settlement proceedings.Consolidated Balance Sheets. At this time management is unable to determine the final revenue impact of the case.
FERC One Company Merger Request
In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization. In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and the surviving entity will be renamed NVEOC. On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.
FERC MidAmerican Merger Request
On July 12, 2013, an application was filed with the FERC under Section 203 of the Federal Power Act, to approve the MidAmerican Merger. The MidAmerican Merger is discussed in more detail in Note 2, Merger-Related Activities. Under Section 203 of the Federal Power Act, the FERC may not authorize the MidAmerican Merger unless it finds, among other things, that the transaction is “consistent with the public interest”. If the FERC does not grant or deny the application within 180 days after the application was filed, the application is deemed granted unless the FERC finds that further consideration, for a period not to exceed an additional 180 days, is required to determine whether the transaction meets the specified standards. The application requests authorization of the proposed transaction by December 19, 2013; however, NVE is unable to determine the timing of a decision in the filing.
NOTE 5. LONG-TERM DEBT
NVE’s, NPC’s and SPPC’s long-term debt consists of the following (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | September 30, | | December 31, |
| | | | | | 2013 | | 2012 |
| Long-Term Debt: | Stated Rate | | Maturity Date | | Consolidated | | NVE Holding Co. | | NPC | | SPPC | | Consolidated | | NVE Holding Co. | | NPC | | SPPC |
| Secured Debt | | | | | | | | | | | | | | | | | | | |
| General and Refunding Mortgage Securities |
| NPC Series L | 5.875 | % | | 2015 | | $ | 250,000 |
| | $ | — |
| | $ | 250,000 |
| | $ | — |
| | $ | 250,000 |
| | $ | — |
| | $ | 250,000 |
| | $ | — |
|
| NPC Series M | 5.950 | % | | 2016 | | 210,000 |
| | — |
| | 210,000 |
| | — |
| | 210,000 |
| | — |
| | 210,000 |
| | — |
|
| NPC Series N | 6.650 | % | | 2036 | | 370,000 |
| | — |
| | 370,000 |
| | — |
| | 370,000 |
| | — |
| | 370,000 |
| | — |
|
| NPC Series O | 6.500 | % | | 2018 | | 325,000 |
| | — |
| | 325,000 |
| | — |
| | 325,000 |
| | — |
| | 325,000 |
| | — |
|
| NPC Series R | 6.750 | % | | 2037 | | 350,000 |
| | — |
| | 350,000 |
| | — |
| | 350,000 |
| | — |
| | 350,000 |
| | — |
|
| NPC Series S | 6.500 | % | | 2018 | | 500,000 |
| | — |
| | 500,000 |
| | — |
| | 500,000 |
| | — |
| | 500,000 |
| | — |
|
| NPC Series U | 7.375 | % | | 2014 | | 125,000 |
| | — |
| | 125,000 |
| | — |
| | 125,000 |
| | — |
| | 125,000 |
| | — |
|
| NPC Series V | 7.125 | % | | 2019 | | 500,000 |
| | — |
| | 500,000 |
| | — |
| | 500,000 |
| | — |
| | 500,000 |
| | — |
|
| NPC Series X | 5.375 | % | | 2040 | | 250,000 |
| | — |
| | 250,000 |
| | — |
| | 250,000 |
| | — |
| | 250,000 |
| | — |
|
| NPC Series Y | 5.450 | % | | 2041 | | 250,000 |
| | — |
| | 250,000 |
| | — |
| | 250,000 |
| | — |
| | 250,000 |
| | — |
|
| SPPC Series M | 6.000 | % | | 2016 | | 450,000 |
| | — |
| | — |
| | 450,000 |
| | 450,000 |
| | — |
| | — |
| | 450,000 |
|
| SPPC Series P | 6.750 | % | | 2037 | | 251,742 |
| | — |
| | — |
| | 251,742 |
| | 251,742 |
| | — |
| | — |
| | 251,742 |
|
| SPPC Series Q | 5.450 | % | | 2013 | | — |
| | — |
| | — |
| | — |
| | 250,000 |
| | — |
| | — |
| | 250,000 |
|
| SPPC Series T | 3.375 | % | | 2023 | | 250,000 |
| | — |
| | — |
| | 250,000 |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | |
| Variable Rate Debt (Secured by General and Refunding Mortgage Securities) |
| NPC IDRB Series 2000A | | 2020 | | — |
| | — |
| | — |
| | — |
| | 98,100 |
| | — |
| | 98,100 |
| | — |
|
| NPC PCRB Series 2006 | | 2036 | | 37,700 |
| | — |
| | 37,700 |
| | — |
| | 37,700 |
| | — |
| | 37,700 |
| | — |
|
| NPC PCRB Series 2006A | | 2032 | | 37,975 |
| | — |
| | 37,975 |
| | — |
| | 37,975 |
| | — |
| | 37,975 |
| | — |
|
| SPPC PCRB Series 2006A | | 2031 | | 58,200 |
| | — |
| | — |
| | 58,200 |
| | 58,200 |
| | — |
| | — |
| | 58,200 |
|
| SPPC PCRB Series 2006B | | 2036 | | 75,000 |
| | — |
| | — |
| | 75,000 |
| | 75,000 |
| | — |
| | — |
| | 75,000 |
|
| SPPC PCRB Series 2006C | | 2036 | | 81,475 |
| | — |
| | — |
| | 81,475 |
| | 81,475 |
| | — |
| | — |
| | 81,475 |
|
| | | | | | | | | | | | | | | | | | | | |
| Senior Notes | | | | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| NVE Senior Notes | 6.250 | % | | 2020 | | 315,000 |
| | 315,000 |
| | — |
| | — |
| | 315,000 |
| | 315,000 |
| | — |
| | — |
|
| NVE Term Loan | 2.560 | % | | 2014 | | 195,000 |
| | 195,000 |
| | — |
| | — |
| | 195,000 |
| | 195,000 |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | |
| Obligations under capital leases | 38,415 |
| | — |
| | 36,571 |
| | 1,844 |
| | 44,258 |
| | — |
| | 42,908 |
| | 1,350 |
|
| Unamortized bond premium and discount (net) | 759 |
| | — |
| | (9,080 | ) | | 9,839 |
| | 1,631 |
| | — |
| | (9,827 | ) | | 11,458 |
|
| Current maturities | (129,457 | ) | | — |
| | (129,186 | ) | | (271 | ) | | (356,283 | ) | | — |
| | (106,048 | ) | | (250,235 | ) |
| Total Long-Term Debt | $ | 4,791,809 |
| | $ | 510,000 |
| | $ | 3,103,980 |
| | $ | 1,177,829 |
| | $ | 4,669,798 |
| | $ | 510,000 |
| | $ | 3,230,808 |
| | $ | 928,990 |
|
Substantially all utility plant is subject to the liens of the NPC Indenture and the SPPC Indenture under which their respective General and Refunding Mortgage Securities are issued.
(5) Recent Financing Transactions
Nevada Power Company
In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
Sierra Pacific Power CompanyCredit Facility
In August 2013, SPPC issuedJune 2014, the Company amended its $500 million secured credit facility expiring in March 2017, reducing the amount available to $400 million and sold $250 millionextending the maturity date to March 2018. The amended facility has a variable interest rate based on the London Interbank Offered Rate or a base rate, at the Company's option, plus a spread that varies based upon the Company's secured debt credit rating. The amended facility requires that the Company's ratio of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand,consolidated debt, including current maturities, to pay at maturitytotal capitalization not exceed 0.68 to 1.0 as of the $250 million principal amountlast day of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013. each quarter.
NOTE 6. FAIR VALUE OF FINANCIAL INSTRUMENTS
The September 30, 2013 carrying amount of cash and cash equivalents, current assets, accounts receivable, accounts payable and current liabilities approximate fair value due to the short-term nature of these instruments. As reported in Note 4, Investments in Subsidiaries & Other Property, of the Notes to Financial Statements in the 2012 Form 10-K, investments held in Rabbi Trust continues to be considered Level 1 in the fair value hierarchy.(6) Employee Benefit Plans
The total fair value of NVE’s consolidated long-term debt at September 30, 2013,Company is estimated to be $5.6 billion baseda 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 quoted market prices for the same or similar issues or on the current rates offered to NVE for debtbehalf of the same remaining maturities. The total fair value was estimatedCompany. Amounts attributable to be $5.9 billion as of December 31, 2012.
The total fair value of NPC’s consolidated long-term debt at September 30, 2013, is estimated to be $3.7 billion based on quoted market prices for the same or similar issues or on the current rates offered to NPC for debt of the same remaining maturities. The total fair value was estimated to be $4.1 billion at December 31, 2012.
The total fair value of SPPC’s consolidated long-term debt at September 30, 2013, is estimated to be $1.3 billion based on quoted market prices for the same or similar issues or on the current rates offered to SPPC for debt of the same remaining maturities. The total fair value was estimated to be $1.3 billion as of December 31, 2012.
NOTE 7. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS
NVE has a single employer defined benefit pension plan covering substantially all employees of NVE and the Utilities. NVE allocates the unfunded liability and the net periodic benefit costs for its pension benefit and other post-retirement benefit plans to NPC and SPPCCompany were allocated from NV Energy based upon the current, or in the case of the retirees, previous, employment location. Certain grandfatheredOffsetting regulatory assets and union employees are covered underliabilities have been recorded related to the amounts not yet recognized as a benefit formula based on years of service and the employee's highest compensation for a period prior to retirement, while most employees are covered under a cash balance formula with vesting after three years of service. NVE also has other post-retirement plans, including a defined contribution plan which provides medical and life insurance benefits for certain retired employees. A summary of the componentscomponent of net periodic pensionbenefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive income.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and other post-retirement costs forconsist of the three and nine months ended September 30 follows. This summary is based on a December 31, measurement date (dollars in thousands)following (in millions):
|
| | | | | | | | | | | | | | | |
| NVE | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Three Months Ended September 30 | | For the Three Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 5,132 |
| | $ | 4,406 |
| | $ | 660 |
| | $ | 595 |
|
| Interest cost | 9,303 |
| | 10,228 |
| | 1,677 |
| | 1,905 |
|
| Expected return on plan assets | (12,708 | ) | | (12,447 | ) | | (1,687 | ) | | (1,563 | ) |
| Amortization of prior service cost | (720 | ) | | (724 | ) | | (952 | ) | | (987 | ) |
| Amortization of net loss | 4,797 |
| | 3,473 |
| | 890 |
| | 731 |
|
| Net periodic benefit cost | $ | 5,804 |
| | $ | 4,936 |
| | $ | 588 |
| | $ | 681 |
|
|
| | | | | | | |
| | As of |
| | June 30, | | December 31, |
| | 2014 | | 2013 |
| Qualified Pension Plan: | | | |
| Other assets | $ | 10 |
| | $ | 13 |
|
| | | | |
| Non-Qualified Pension Plans: | | | |
| Customer deposits and other | (4 | ) | | (4 | ) |
| Other long-term liabilities | (5 | ) | | (8 | ) |
| | | | |
| Other Postretirement Plans: | | | |
| Other long-term liabilities | (8 | ) | | (7 | ) |
|
| | | | | | | | | | | | | | | |
| | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Nine Months Ended September 30 | | For the Nine Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 15,396 |
| | $ | 13,220 |
| | $ | 1,980 |
| | $ | 1,787 |
|
| Interest cost | 27,911 |
| | 30,684 |
| | 5,030 |
| | 5,715 |
|
| Expected return on plan assets | (38,124 | ) | | (37,341 | ) | | (5,060 | ) | | (4,690 | ) |
| Amortization of prior service cost | (2,162 | ) | | (2,173 | ) | | (2,857 | ) | | (2,961 | ) |
| Amortization of net loss | 14,391 |
| | 10,418 |
| | 2,671 |
| | 2,193 |
|
| Net periodic benefit cost | $ | 17,412 |
| | $ | 14,808 |
| | $ | 1,764 |
| | $ | 2,044 |
|
The average percentageCompany is exposed to the impact of NVE net periodic costs capitalized during 2013market fluctuations in commodity prices and 2012 was 34.5%interest rates. The Company is principally exposed to electricity, natural gas, coal, and 35.0% respectively.
|
| | | | | | | | | | | | | | | |
| NPC | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Three Months Ended September 30 | | For the Three Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 2,761 |
| | $ | 2,358 |
| | $ | 389 |
| | $ | 350 |
|
| Interest cost | 4,453 |
| | 4,881 |
| | 556 |
| | 602 |
|
| Expected return on plan assets | (6,270 | ) | | (6,237 | ) | | (631 | ) | | (592 | ) |
| Amortization of prior service cost | (453 | ) | | (456 | ) | | (23 | ) | | 229 |
|
| Amortization of net loss | 2,117 |
| | 1,363 |
| | 289 |
| | 221 |
|
| Net periodic benefit cost | $ | 2,608 |
| | $ | 1,909 |
| | $ | 580 |
| | $ | 810 |
|
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Nine Months Ended September 30 | | For the Nine Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 8,283 |
| | $ | 7,072 |
| | $ | 1,167 |
| | $ | 1,050 |
|
| Interest cost | 13,358 |
| | 14,643 |
| | 1,667 |
| | 1,807 |
|
| Expected return on plan assets | (18,810 | ) | | (18,711 | ) | | (1,892 | ) | | (1,775 | ) |
| Amortization of prior service cost | (1,358 | ) | | (1,367 | ) | | (69 | ) | | 687 |
|
| Amortization of net loss | 6,351 |
| | 4,089 |
| | 867 |
| | 662 |
|
| Net periodic benefit cost | $ | 7,824 |
| | $ | 5,726 |
| | $ | 1,740 |
| | $ | 2,431 |
|
The average percentage of NPC net periodic costs capitalized during 2013Company has established a risk management process that is designed to identify, assess, monitor, report, manage and 2012 was 35.9% and 36.9% respectively.
|
| | | | | | | | | | | | | | | |
| SPPC | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Three Months Ended September 30 | | For the Three Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 1,926 |
| | $ | 1,695 |
| | $ | 251 |
| | $ | 227 |
|
| Interest cost | 4,558 |
| | 5,043 |
| | 1,104 |
| | 1,283 |
|
| Expected return on plan assets | (6,162 | ) | | (5,937 | ) | | (1,022 | ) | | (941 | ) |
| Amortization of prior service cost | (277 | ) | | (277 | ) | | (933 | ) | | (1,220 | ) |
| Amortization of net loss | 2,501 |
| | 2,026 |
| | 592 |
| | 504 |
|
| Net periodic benefit cost | $ | 2,546 |
| | $ | 2,550 |
| | $ | (8 | ) | | $ | (147 | ) |
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Post-Retirement Benefits |
| | For the Nine Months Ended September 30 | | For the Nine Months Ended September 30 |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Service cost | $ | 5,778 |
| | $ | 5,086 |
| | $ | 752 |
| | $ | 682 |
|
| Interest cost | 13,676 |
| | 15,130 |
| | 3,310 |
| | 3,848 |
|
| Expected return on plan assets | (18,486 | ) | | (17,813 | ) | | (3,065 | ) | | (2,823 | ) |
| Amortization of prior service cost | (831 | ) | | (831 | ) | | (2,798 | ) | | (3,658 | ) |
| Amortization of net loss | 7,502 |
| | 6,078 |
| | 1,777 |
| | 1,511 |
|
| Net periodic benefit cost | $ | 7,639 |
| | $ | 7,650 |
| | $ | (24 | ) | | $ | (440 | ) |
The average percentage of SPPC net periodic costs capitalized during 2013 and 2012 and was 35.6% and 35.1%, respectively.
As discussed in Note 10, Retirement Plan and Post-Retirement Benefits,mitigate each of the Notesvarious 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, options, swaps and other agreements, to Financial Statementseffectively 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 2012 Form 10-K, NVE offered a voluntary lump sum pension pay outCompany may from time to former employees not currently of retirement age but eligible for future benefits and certain retiree participants already receiving benefits under NVE’s pension plan in an efforttime enter into interest rate derivative contracts, such as interest rate swaps or locks, to reduce NVE’s future pension obligation. Duringmitigate the nine months ended September 30, 2013, NVE paid $21.5 million in lump sum pension pay outs from the pension assets.Company's exposure to interest rate risk. The companyCompany does not expect any further material amountshedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to be paidchanges in 2013.
During the nine months ended September 30, 2013 and 2012, the company made contributions to the pension plan in the amount of $20.0 million and $15.0 million, respectively and $5.0 million and $7.1 million, respectively in contributions to the other post-retirement benefits plan. At the present time, it is not anticipated that additional funding will be required for either plan in 2013 in order to meet the minimum funding level requirements defined by the Pension Protection Act of 2006. However, NVE and the Utilities have included in their 2013 assumptions funding levels similar to the 2012 funding. The amounts to be contributed in 2013 may change subject to market conditions.prices.
NOTE 8. COMMITMENTS AND CONTINGENCIES
Environmental
NPC
NEICO
NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $4 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. The site is under contract for sale to a third party and the sale is expected to close in the fourth quarter of 2013. The sale will not be material to NPC.
Reid Gardner Generating Station
On October 4, 2011, NPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for NPC’s Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-4, with the interest of CDWR in Unit 4 having been terminated in October 2013. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant. NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, NPC cannot predict the impact, if any, associated with this information request.
SPPC
Valmy Generating Station
On June 22, 2009, SPPC received a request for information from the EPA-Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and thereThere have been no other new enforcement-related proceedingssignificant changes in the Company'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 initiateddesignated as normal under the normal purchases or normal sales exception afforded by GAAP, summarizes the EPA relatingfair value of the Company's derivative contracts, on a gross basis, and reconciles those amounts to the plant. SPPC completedamounts presented on a net basis on the Consolidated Balance Sheets (in millions):
|
| | | | | | | | | | | | |
| | | Customer | | Other | | |
| | | Deposits and | | Long-term | | |
| | | Other | | Liabilities | | Total |
| As of June 30, 2014 | | | | | | |
Commodity liabilities(1) | | $ | (9 | ) | | $ | (24 | ) | | $ | (33 | ) |
| | | | | | | |
| As of December 31, 2013 | | | | | | |
Commodity liabilities(1) | | $ | (9 | ) | | $ | (38 | ) | | $ | (47 | ) |
| |
| (1) | The Company's commodity derivatives not designated as hedging contracts are included in regulated rates and as of June 30, 2014 and December 31, 2013, a regulatory asset of $33 million and $47 million, respectively, was recorded related to the derivative liability of $33 million and $47 million, respectively. |
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 as of (in millions):
|
| | | | | | | |
| | Unit of | | June 30, | | December 31, |
| | Measure | | 2014 | | 2013 |
| Electricity sales | Megawatt hours | | (4 | ) | | (4 | ) |
| Natural gas purchases | Decatherms | | 108 |
| | 118 |
|
Credit Risk
The Company extends unsecured credit to other utilities, energy marketing companies, financial institutions and other market participants in conjunction with its responsewholesale energy supply and marketing activities. Credit risk relates to the EPArisk of loss that might occur as a result of nonperformance by counterparties on their contractual obligations to make or take delivery of electricity, natural gas or other commodities and to make financial settlements of these obligations. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in December 2009market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances involving other market participants that have a direct or indirect relationship with the counterparty.
The Company analyzes the financial condition of each significant wholesale counterparty before entering into any transactions, establishes limits on the amount of unsecured credit to be extended to each counterparty and will continueevaluates the appropriateness of unsecured credit limits on an ongoing basis. To mitigate exposure to monitor developments relatingthe financial risks of wholesale counterparties, the Company 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. Counterparties may be assessed fees for delayed payments. If required, the Company 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 this Section 114 request. At this time, SPPC cannot predictdemand 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 June 30, 2014, 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 was $4 million, 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. 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.
| |
| (8) | Fair Value Measurements |
The carrying value of the Company's cash, certain cash equivalents, receivables, investments held in Rabbi trusts, 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.
The Company's commodity derivative contracts are valued using a market approach that uses quoted forward commodity prices for similar assets and liabilities, which 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. Interest rate swaps are valued using a financial model which utilizes observable inputs for similar instruments based primarily on market price curves. The determination of the fair value for derivative instruments not only includes counterparty risk, but also the impact if any, associated with this information request.of the Company's nonperformance risk on its liabilities, which as of June 30, 2014 and December 31, 2013, had an immaterial impact to the fair value of its derivative instruments. As such, the Company considers its commodity derivative contracts to be valued using Level 3 inputs.
NPCThe following table reconciles the beginning and SPPCending balances of the Company's commodity liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):
NVision and SB 123 |
| | | | | | | |
| | Three-Month Period | | Six-Month Period |
| | Ended June 30, 2014 | | Ended June 30, 2014 |
| Beginning balance | $ | (35 | ) | | $ | (47 | ) |
| Changes in fair value recognized in regulatory assets | — |
| | 12 |
|
| Purchases | — |
| | (1 | ) |
| Settlements | 2 |
| | 3 |
|
| Ending balance | $ | (33 | ) | | $ | (33 | ) |
The Company's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of the Company's long-term debt is a comprehensive planLevel 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of NVE for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacementfuture cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the generation capacityCompany's variable-rate long-term debt approximates fair value because of such plants with increased capacity fromthe 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 June 30, 2014 | | As of December 31, 2013 |
| | Carrying | | Fair | | Carrying | | Fair |
| | Value | | Value | | Value | | Value |
| | | | | | | | |
| Long-term debt | $ | 3,066 |
| | $ | 3,699 |
| | $ | 3,071 |
| | $ | 3,596 |
|
| |
| (9) | Commitments and Contingencies |
Environmental Laws and Regulations
The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable energy facilitiesportfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other electric generating plants. NVision includesenvironmental matters that have the followingpotential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
In June 2013, the Nevada State Legislature passed Senate Bill No. 123, which included, in significant details:part:
Accelerating the plan to retire 800 MWs of coal plants, starting as soon as December 31, 2014;
Replacement of such coal plants withby issuing requests for proposals for the procurement of 300 MWs from renewable facilities;
Construction or acquisition and ownership of 50 MWs of electric generating capacity from renewable facilities;
Construction or acquisition and ownership of 550 MWs of additional electric generating capacity from other electric generating plants;capacity; and
Assuring regulatory procedures that protect reliability and supply and address financial impacts on customer and utility.
In June 2013,February 2014, the PUCN issued a final order approving draft regulations, subject to review by a Nevada Legislative commission and which must be filed with the Secretary of State, Legislature passed SB 123, which was supportedand the regulations became effective March 2014. In May 2014, the Company filed its Emission Reduction Capacity Replacement Plan proposing, among other items, the retirement of Reid Gardner Generating Station units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a plan to replace the generation capacity being retired, as required by NVE as part of its NVision initiativeSenate Bill No. 123. The Emissions Reduction and Capacity Replacement Plan includes the requirements as outlinedissuance of requests for proposals for 300 MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 274-MW natural gas co-generating facility in 2014; the acquisition of a 222-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed Emissions Reduction and Capacity Replacement Plan, which are subject to PUCN approval. The PUCN has scheduled a hearing on the application beginning in September 2014 and an order is expected in the bullets above.fourth quarter of 2014.
Reid Gardner Generation Station
In October 2011, the Company received a request for information from the Environmental Protection Agency Region 9 under Section 114 of the Clean Air Act requesting current and historical operations and capital project information for the Company's Reid Gardner Generating Station located near Moapa, Nevada. The Utilities, along withEnvironmental Protection Agency's Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other interested parties, are currently working withnew enforcement-related proceedings that have been initiated by the PUCNEnvironmental Protection Agency relating to finalize the rulemakingplant. The Company completed its responses to the Environmental Protection Agency during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, the Company cannot predict the impact, if any, associated with this bill and expect to file an emissions reduction plan in 2014 to specifically address the plan details as outlined above.information request.
Greenhouse Gas/Carbon Regulations
In conjunction with the release of President Obama’s Climate Action Plan on June 25, 2013, the President issued a memorandum directing the EPA to take several actions on carbon emissions standards for power plants. As discussed above, NVision and the passage of SB 123, will yield substantial reductions in carbon as NVE and the Utilities retire their existing coal-fired generating facilities on an accelerated schedule. While the Utilities currently cannot predict the financial impact or final mandates by President Obama’s Climate Action Plan or the EPA’s final rules, NVE and the Utilities remain committed to taking progressive steps over time to limit the carbon emissions from its generation fleet by retiring older fossil units and replacing them with new, lower emissions and/or zero emission sources.
Regional Haze Rules
In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA’s Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.
In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. In March 2012, the EPA approved Nevada’s SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada’s SIP. For the limited portions of Nevada’s SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada’s determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline for the Reid Gardner Generating Station retrofits so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada. On March 26, 2013, the EPA granted reconsideration of the compliance date for the BART retrofits for Units 1, 2 and 3 at Reid Gardner Generating Station, proposing to extend the compliance date by 18 months, from January 1, 2015 to June 30, 2016. The EPA held a public hearing on April 29, 2013, to accept written and oral comments on this proposed action and t he comment period for this action closed on May 30, 2013. In August 2013, the EPA announced it was taking final action to extend the date by which Units 1, 2, and 3 at Reid Gardner Generating Station must meet the BART limits to reduce emissions of nitrogen oxides. The final date is now affirmed as June 30, 2016.
NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE has received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2. As previously disclosed, NVE and the Utilities intend to file with the PUCN their emissions reduction plan in 2014 detailing how they will address the phased retirement of coal fired assets as required under SB 123. While the BART requirements specify the installation of SNCR’s on Reid Gardner Generating Station Units 1, 2 and 3, the passage of SB 123 could result in the early retirement of those units prior to the required BART installation deadline, pending the final approval of the PUCN. Therefore, in 2014, NVE and the Utilities will file an emissions reduction plan. NVE and the Utilities would need to obtain either the PUCN approval to retire those units as soon as the end of 2014 or seek approval for the BART retrofit installation with an alternate retirement date. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, including Reid Gardner Generating Station Units 1, 2 and 3, but excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities’ regulatory proceedings similar to other environmental compliance requirements.
Environmental groups have challenged both of the EPA’s final determinations with respect to Nevada’s regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA’s March 2012 approval of Nevada’s SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA’s approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA’s August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation
matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned. Legal Matters
The Navajo Generating StationCompany is also an affected unit under EPA’s Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternativeparty to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, have been reviewing the EPA proposal to determine its impact on the viability of the plant’s future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC’s ownership share is 11.3%.
The original comment period on the EPA BART proposal expired on May 6, 2013, but Navajo Generating Station operator Salt River requested and was granted several extensions, citing the complexity of the plan and the need to consult with multiple tribes and the other plant co-owners.
On September 25, 2013, the EPA issued a supplemental proposal which included a BART alternative called the Technical Work Group (“TWG”) Alternative. The TWG Alternative is based upon the proposal submitted to the EPA in July 2013 by a group of Navajo Generating Station stakeholders called the TWG. At this time, the EPA is concurrently accepting comments on the BART determination and the EPA Alternative which were proposed in February 2013, as well the TWG Alternative proposed in the supplemental proposal. Comments are now due by January 6, 2014.
Given the uncertainties that remain regarding the various lease and agreement renewal terms, the timeline for BART installation, and the fact that the EPA’s overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternativelegal actions the ownership may decide to take. As a resultarising out of the passage of NVision and these uncertainties, NPC expects to file in 2014 an emissions reduction plan to specifically address its ownership participation in the Navajo Generating Station.
Mercury and Air Toxics Standards (MATS)
In December 2011, the EPA signed for publication in the Federal Register a final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule, requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the Maximum Achievable Control Technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The Court has established a schedule for the litigation; however, the Utilities cannot predict the outcome at this time.
The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE’s generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC’s Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC’s 50% ownership interest of approximately $6.4 million, excluding AFUDC. Note that the actual cost will be dependent upon final engineering design.
The three units at the Navajo Generating Station are also subject to MATS. The plant operator intends to file a one year extension request associated with the compliance date in order to allow for additional testing of various mercury control strategies. Due to the uncertainty of what control equipment will be ultimately required to control mercury from the Navajo Generating Station units, a cost estimate is unable to be determined at this time.
Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.
Other Environmental Matters
NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. In addition, NVE and the Utilities may also be subject to future state or federal regulations. Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility, which may be accelerated by any decision to retire a generating station or other facility. If remediation activities involve statutory joint and several liability provisions, strict liability or cost recovery of contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.
In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Units 1, 2 and 3 and as co-owner and operating agent of Unit 4. In October 2013, NPC purchased Unit 4 from CDWR. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs. However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.
NVE and the Utilitiesbusiness. Plaintiffs occasionally seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.
Litigation Contingencies
NVE
Litigation Related to the MidAmerican Merger
Following the announcement of the proposed acquisition of NVE by MEHC through its subsidiary Silver Merger Sub, Inc. on May 29, 2013, several complaints were filed by alleged NVE shareholders in the Eighth Judicial District Court in Clark County, Nevada, challenging the MidAmerican Merger.
On June 6, 2013, a complaint was filed on behalf of a putative class of NVE public shareholders, naming NVE, its BOD, and Silver Merger Sub, Inc., as defendants. This complaint was amended on July 16, 2013.punitive or exemplary damages. The amended complaint generally alleges that the individual defendants breached their fiduciary duties in connection with the proposed MidAmerican Merger, including by approving the transaction on allegedly unfair terms, at an allegedly unfair price and pursuant to an allegedly inadequate process; allegedly acting with conflicts and in their own personal interests rather than those of shareholders; and making inadequate disclosures in connection with requested shareholder approval of the proposed MidAmerican Merger. The amended complaint also alleges that Silver Merger Sub. Inc., NVE and MEHC aided and abetted the individual defendants in breaching their fiduciary duties.
Four additional complaints were filed in the Eighth Judicial District Court in Clark County, Nevada on June 7, 2013, June 10, 2013, July 12, 2013 and August 16, 2013. These complaints contain claims and allegations similar to the amended July 16, 2013 complaint and seek similar relief on behalf of the same putative class. Onecomplaint was voluntarily dismissed. The remaining cases were consolidated in Department XI of the Eighth Judicial District Court in Clark County, Nevada.
An agreement-in-principle has been reached between the parties to these lawsuits, which was memorialized in a memorandum of understanding executed on September 4, 2013. The memorandum of understanding called for NVE to supplement the proxy statement for the special meeting of stockholders related to the MidAmerican Merger, and the supplemental information was in fact provided via NVE’s Form 8-K dated September 9, 2013. The parties currently are preparing a final stipulation of settlement which will be submitted to the court for approval. It is not known at this time when the court will set hearings and/or issue a final order, but NVECompany does not expect the outcome of thisbelieve that such normal and routine litigation or settlement to delay the closing of the MidAmerican Merger or otherwisewill have a material impact on NVE.
NPC
Peabody Western Coalits consolidated financial results. The Company - Royalty Claim
NPC owns an 11% interestis also involved in the Navajo Generating Station,other kinds of legal actions, some of which is locatedassert or may assert claims or seek to impose fines, penalties and other costs in northern Arizonasubstantial amounts and operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.
In June 1999, the Navajo Nation filed suit against Salt River, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.
In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit. In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.
In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, Salt River and SCE. At the request of Salt River, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station.
SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. In October 2013, NPC settled with SCE on this matter. The terms of the settlement are not material to NPC.described below.
November 2005 Land Investors
In 2006, November 2005 Land Investors, LLC (“NLI”("NLI") purchased from the U.S.United States through the Bureau of Land Management (“BLM”) 2,675 acres of land located in North Las Vegas, Nevada. A small portion of the land was and is traversed by a 500kV500 kilovolt transmission line owned by NPCthe Company and sited pursuant to a pre-existing right-of-way grant (“Grant”) from the BLM.Bureau of Land Management. Subsequent to NLI’sNLI's purchase, a dispute arose as to whether NPCthe Company owed rent and, if it did, the amount owed to NLI under the Grant.right-of-way grant. NLI eventually “terminated”"terminated" the Grantright-of-way grant and brought claims against NPCthe Company for breach of contract, inverse condemnation and trespass. NPCThe Company counterclaimed for express condemnation of a perpetual easement over the right-of-way corridor. The matter proceeded to trial in the Eighth Judicial District Court, Clark County, Nevada.Nevada ("Eighth District Court"). In September 2013, the courtEighth District Court awarded NLI approximately $1.0$1 million for unpaid rent and $5.1$5 million for inverse condemnation, plus interest and attorneys’ fees.attorneys' fees, bringing the total judgment to $12 million. The courtEighth District Court also found NPCthe Company was entitled to judgment in its favor on its counterclaim for condemnation of the right-of-way corridor.
NPC The Company has posted the required bond of $6 million and has subsequently appealed to the Nevada Supreme Court, which has yet to establish a schedule for the appeal.Court. Management cannot assess or predict the outcome of the case at this time, but it is not expected to be material to NPC.time.
SPPCSierra Club and Moapa Band of Paiute Indians
Farad Dam
In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) locatedAugust 2013, the Sierra Club and Moapa Band of Paiute Indians filed a complaint in federal district court in Nevada against the Company and California Department of Water Resources, alleging that activities at the Reid Gardner Generating Station are causing imminent and substantial harm to TMWA for $8.0 million. Onethe environment and that placement of coal combustion residuals at the on-site landfill constitute "open dumping" in violation of the units,Resource Conservation and Recovery Act. The complaint also alleges that the Farad Hydro (2.8 MW), has been outReid Gardner Generating Station is engaged in the unlawful discharge of service sincepollutants in violation of the summerClean Water Act. The notice was issued pursuant to the citizen suit provisions of 1996the Resource Conservation and Recovery Act and the Clean Water Act. CDWR was named as a co-defendant in the litigation due to a collapsed flume. Underits prior co-ownership in Reid Gardner Generating Station unit 4. The complaint seeks various injunctive remedies, assessment of civil penalties, and reimbursement of plaintiffs' attorney and legal fees and costs. The Company answered the termscomplaint and intends to vigorously defend the suit. Given the stage of the contract with TMWA, SPPC is not entitledproceeding, management cannot predict the impact to receive the proceedsCompany, or estimate the range of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or, alternatively, SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim. The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.loss.
SPPC filed a claim with the Farad Dam’s insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers. The insurers contested the extent and amount of insurance coverage. Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.
In July 2012, the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC’s right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost. In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three years time to rebuild to start at the conclusion of all litigation.
The District Court has now set the briefing schedule for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.
Other Legal Matters
NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.
Other Commitments
NPC and SPPC
ON Line TUA
During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE’s future lease payments are adjusted for final capital costs, for which the Utilities expect to get regulatory recovery. For accounting purposes, NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of September 30, 2013, capitalized construction costs associated with GBT’s 75% interest of $370.8 million and $19.4 million were included in CWIP with a corresponding credit to other deferred liabilities at NPC and SPPC, respectively.
NOTE 9. EARNINGS PER SHARE (NVE)
The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan.
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| Basic EPS | | | | | | | |
| Numerator ($000) | | | | | | | |
| Net Income | $ | 187,234 |
| | $ | 223,170 |
| | $ | 271,942 |
| | $ | 304,782 |
|
| | | | | | | | |
| Denominator | | | | | | | |
| Weighted average number of common shares outstanding | 235,578,310 |
| | 235,961,402 |
| | 235,421,933 |
| | 235,986,874 |
|
| | | | | | | | |
| Per Share Amounts | | | | | | | |
| Net Income per share - basic | $ | 0.79 |
| | $ | 0.95 |
| | $ | 1.16 |
| | $ | 1.29 |
|
| | |
| | |
| | |
| | |
|
| Diluted EPS | | | | | | | |
| Numerator ($000) | | | | | | | |
| Net Income | $ | 187,234 |
| | $ | 223,170 |
| | $ | 271,942 |
| | $ | 304,782 |
|
| | | | | | | | |
Denominator(1) | | | | | | | |
| Weighted average number of shares outstanding before dilution | 235,578,310 |
| | 235,961,402 |
| | 235,421,933 |
| | 235,986,874 |
|
| Stock options | 61,927 |
| | 39,256 |
| | 46,537 |
| | 37,592 |
|
| Non-Employee Director stock plan | 190,705 |
| | 166,829 |
| | 185,337 |
| | 160,257 |
|
| Employee stock purchase plan | 4,149 |
| | 6,742 |
| | 5,831 |
| | 6,785 |
|
| Restricted Shares | 412,000 |
| | 584,750 |
| | 487,667 |
| | 533,750 |
|
| Performance Shares | 1,358,423 |
| | 1,362,753 |
| | 1,191,734 |
| | 1,125,272 |
|
| Diluted Weighted Average Number of Shares | 237,605,514 |
| | 238,121,732 |
| | 237,339,039 |
| | 237,850,530 |
|
| | | | | | | | |
| Per Share Amounts | | | | | | | |
| Net income per share - diluted | $ | 0.79 |
| | $ | 0.94 |
| | $ | 1.15 |
| | $ | 1.28 |
|
| |
(1) | The denominator does not include stock equivalents for options issued under the non-qualified stock option plan due to conversion prices being higher than market prices for the periods ending September 30, 2012. If the conditions for conversion were met under this plan, 327,503 and 329,382 shares, would be included for the three and nine months ended September 30, 2012, respectively. |
NOTE 10. COMMON STOCK AND OTHER PAID-IN CAPITAL
Dividends
The following dividend declarations were made by the BOD of NVE:
|
| | | | | | |
Declaration Date | | Amount | | Payable Date | | Shareholders of Record Date |
February 7, 2013 | | $0.19 | | March 20, 2013 | | March 5, 2013 |
May 8, 2013 | | $0.19 | | June 19, 2013 | | June 4, 2013 |
August 1, 2013 | | $0.19 | | September 18, 2013 | | September 3, 2013 |
November 6, 2013 | | $0.19 | | December 18, 2013 | | December 3, 2013 |
On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of $105.0 million and $40.0 million, respectively.
Treasury Stock
NVE periodically repurchases common stock on the open market for the purpose of meeting the requirements of its stock compensation plans; such purchases were not made pursuant to a publicly announced stock repurchase plan or program. All shares repurchased are held as treasury stock and may be reissued upon exercise or settlement of the stock compensation award. Treasury stock is accounted for using the cost method. During the nine months ended September 30, 2013, NVE repurchased 325,178 shares of common stock for approximately $6.3 million. During the nine months ended September 30, 2013, NVE re-issued 827,097 treasury shares to
satisfy employee benefit plans. In May 2013, NVE ceased the repurchase of common stock as a result of the proposed MidAmerican Merger.
ITEMItem 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Forward-Looking Statements and Risk Factors
The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.
Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:
Risks Related to the Pending MidAmerican Merger
whether NVE or MEHC will be able to satisfy the remaining closing conditions of the MidAmerican Merger Agreement, including the receipt of regulatory approvals from the PUCN and the FERC on the terms and schedules contemplated by the parties;
whether an event, effect or change will occur that gives rise to a termination of the MidAmerican Merger;
whether NVE will experience unanticipated difficulties and/or incur unanticipated expenditures relating to the MidAmerican Merger, and whether the MidAmerican Merger will disrupt current plans and operations and create difficulties in employee retention;
whether legal proceedings against NVE and others related to the MidAmerican Merger will be successful; and
the impact of delay or failure to complete the MidAmerican Merger on NVE’s common stock price.
Operational Risks
economic conditions, inflation rates, monetary policy, unemployment rates, customer bankruptcies, including major gaming customers with significant debt maturities, weaker housing markets, each of which affect customer growth, customer collections, customer demand and usage patterns;
changes in customer demand for electricity and gas resulting from variations in the rate of industrial, commercial and residential growth in the Utilities’ service territories, from energy conservation programs, and from the development and deployment of alternative energy sources such as self-generation and distributed generation technologies;
construction risks, including but not limited to those associated with ON Line, such as difficulty in securing adequate skilled labor, cost and availability of materials and equipment, third-party disputes, equipment failure, engineering and design failure, work accidents, fire or explosions, business interruptions, recovery of possible cost overruns, delay of in-service dates, and pollution and environmental damage;
security breaches of our information technology or supervisory control and data systems, or the systems of others upon which the Utilities rely, whether through cyber-attack, cyber-crime, sabotage, accident or other means, which may affect our ability to prevent system or service disruptions, generating facility shutdowns or disclosure of confidential corporate or customer information;
unseasonable or severe weather, drought, wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, affect the amount of water available for electric generating plants in the southwestern U.S., and have other adverse effects on our business;
employee workforce factors, changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, an aging workforce, and the ability to adjust the labor cost structure to changes in growth within our service territories;
whether the Utilities’ NV Energize systems continue to operate as intended, accurately and timely measure customer energy usage and generate billing information, and whether the Utilities can continue to rely on third-party vendors or contractors to support certain proprietary components of the advanced metering systems;
changes in and/or implementation of FERC and NERC mandatory reliability, security, and other requirements for system infrastructure, which could significantly affect existing and future operations;
explosions, fires, accidents, mechanical breakdowns or vandalism that may occur while operating and maintaining an electric and natural gas system in the Utilities’ service territory, including gas distribution services that the Utilities may rely upon, that can cause unplanned outages, reduce generating output, damage the Utilities’ assets or operations, subject the Utilities to third-party claims for property damage, personal injury or loss of life, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utilities;
the extent to which NVE or the Utilities incur costs in connection with third-party claims or litigation that are not recoverable through insurance, rates, or from other third parties;
changes in the business of the Utilities’ major customers engaged in mining or gaming, including availability and cost of capital or power demands, which may result in changes in the demand for the Utilities’ services, including the effect on the Nevada gaming industry from the opening of additional gaming establishments in other states and internationally;
the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general; and
unusual or unanticipated changes in normal business operations of the Utilities, including unusual maintenance or repairs.
Regulatory/Legislative Risks
unfavorable rulings, penalties and findings by the PUCN in rate or other cases, investigations or proceedings, including GRCs, the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, deferred natural gas costs recorded by SPPC for its gas distribution business, renewable energy and energy efficiency recovery programs, and unfavorable rulings, penalties or findings by the FERC in rate or other cases, investigations and proceedings with regard to wholesale power sales and transmission services;
the effect of existing or future Nevada or federal laws or regulations affecting the electric industry, including those which could allow additional customers to choose new electricity suppliers, use alternative sources of energy, generate their own electricity, or change the conditions under which they may do so;
whether the Utilities can procure, obtain, and/or maintain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada; and
changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject or which change the rate of federal or state taxes payable by our shareholders or common stock dividends.
Environmental Risks
changes in and/or implementation of environmental laws or regulations, including the imposition of limits on emissions of carbon or other pollutants from electric generating facilities, which could significantly affect the Utilities existing operations as well as our construction program.
Liquidity and Capital Resources Risks
whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs) and/or power, or a ratings downgrade;
wholesale market conditions, including availability of power on the spot market and the availability to enter into commodity financial hedges with creditworthy counterparties, including the impact as a result of the Dodd-Frank Act on counterparties who are lenders under our revolving credit facilities, which may affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;
whether provisions of the Dodd-Frank Act or rules made under the act governing derivative transaction reporting, trading, and clearing or imposing margin or collateral requirements will materially increase the cost, or limit the availability or usefulness, to the Utilities of financial transactions and techniques important in managing risks the Utilities face in the commodity, power and financial markets;
the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their capital needs, particularly in the event of: volatility in the global credit markets or other problems, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;
whether NVE's BOD will declare NVE's common stock dividends based on the BOD’s periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions contained in NVE's and the Utilities' agreements;
whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act; and
further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension and other postretirement plans, which can affect future funding obligations, costs and pension and other postretirement plan liabilities.
Other factors and assumptions not identified above may also have been involved in deriving forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.
NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS
In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties that are specific to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;
have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
may apply standards of materiality in a way that is different from what may be viewed as material to investors; and
were made only as of the date of the applicable agreement or such other date or dates as may be specified in such agreements and are subject to more recent developments.
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
EXECUTIVE OVERVIEW
Management’sManagement's Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes discussion of the following:
Critical Accounting Policies and Estimates:
Recent PronouncementsGeneral
For each of NVE, NPC and SPPC:
Results of Operations
Analysis of Cash Flows
Liquidity and Capital Resources
Regulatory Proceedings (Utilities)
NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale of natural gas. Other operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.
The Utilities are regulated by the PUCN with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.
The Utilities’Company'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. NPCThe Company is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. 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 shortshort- and long termlong-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 the Utilities.Company. Additionally, the timely recovery of purchased power, and 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 the Utilities. Company.
MidAmerican MergerThe 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 Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.
In May 2013, NVE entered into the MidAmerican Merger Agreement, which providesResults of Operations for the mergerSecond Quarter and First Six Months of Silver Merger Sub, Inc. with2014 and into NVE, with NVE continuing as the surviving corporation. Once merged, NVE will become an indirect wholly-owned subsidiary of MEHC, which in turn is a wholly-owned subsidiary of Berkshire Hathaway, Inc. Pursuant to the MidAmerican Merger Agreement, at the effective time of the MidAmerican Merger, each share of common stock of NVE issued and outstanding immediately prior to the closing will be converted into the right to receive cash in the amount of $23.75 per share, without interest. The MidAmerican Merger Agreement is subject to various conditions and is discussed in more detail in Note 2, 2013Merger-Related Activities, of the Condensed Notes to Financial Statements. In order to close in late 2013 or the first
Net income for second quarter of 2014 management intendswas $62 million, an increase of $3 million, or 5%, and for the first six months of 2014 was $68 million, an increase of $4 million, or 6%, as compared to work diligently to satisfy the conditions as outlined in Note 2, Merger-Related Activities,2013.
Operating revenue and cost of fuel, energy and capacity are key drivers of the Condensed NotesCompany's results of operations as they encompass retail and wholesale electricity revenue and the direct costs associated with providing electricity to Financial Statements,customers. The Company believes that a discussion of gross margin, representing operating revenue less cost of fuel, energy and capacity, is therefore meaningful. A comparison of the Company's key operating results is as well as transitional requirements. follows:
Overview of Major Factors Affecting Results of Operations |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Second Quarter | | | First Six Months | |
| | | 2014 | | 2013 | | Change | | 2014 | | 2013 | | Change |
| Gross margin (in millions): | | | | | | | | | | | | | | | | |
| Operating revenue | | $ | 595 |
| | $ | 536 |
| | $ | 59 |
| 11 |
| % | | $ | 1,012 |
| | $ | 906 |
| | $ | 106 |
| 12 |
| % |
| Cost of fuel, energy and capacity | | 284 |
| | 209 |
| | 75 |
| 36 |
| | | 487 |
| | 351 |
| | 136 |
| 39 |
| |
| Gross margin | | $ | 311 |
| | $ | 327 |
| | $ | (16 | ) | (5 | ) | | | $ | 525 |
| | $ | 555 |
| | $ | (30 | ) | (5 | ) | |
| | | | | | | | | | | | | | | | | |
| Sales (GWh): | | | | | | | | | | | | | | | | |
| Residential | | 2,296 |
| | 2,354 |
| | (58 | ) | (2 | ) | % | | 3,761 |
| | 3,965 |
| | (204 | ) | (5 | ) | % |
| Commercial | | 1,180 |
| | 1,179 |
| | 1 |
| — |
| | | 2,113 |
| | 2,095 |
| | 18 |
| 1 |
| |
| Industrial | | 2,013 |
| | 2,042 |
| | (29 | ) | (1 | ) | | | 3,642 |
| | 3,677 |
| | (35 | ) | (1 | ) | |
| Other | | 46 |
| | 49 |
| | (3 | ) | (6 | ) | | | 98 |
| | 97 |
| | 1 |
| 1 |
| |
| Total retail | | 5,535 |
| | 5,624 |
| | (89 | ) | (2 | ) | | | 9,614 |
| | 9,834 |
| | (220 | ) | (2 | ) | |
| Wholesale | | 1 |
| | 5 |
| | (4 | ) | (80 | ) | | | 6 |
| | 18 |
| | (12 | ) | (67 | ) | |
| Total sales | | 5,536 |
| | 5,629 |
| | (93 | ) | (2 | ) | | | 9,620 |
| | 9,852 |
| | (232 | ) | (2 | ) | |
| | | | | | | | | | | | | | | | | |
| Average number of retail customers (in thousands) | | 873 |
| | 859 |
| | 14 |
| 2 |
| % | | 871 |
| | 855 |
| | 16 |
| 2 |
| % |
| | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | | $ | 105.54 |
| | $ | 93.79 |
| | $ | 11.75 |
| 13 |
| % | | $ | 103.39 |
| | $ | 90.74 |
| | $ | 12.65 |
| 14 |
| % |
| | | | | | | | | | | | | | | | | |
| Heating degree days | | 41 |
| | 34 |
| | 7 |
| 21 |
| % | | 709 |
| | 1,084 |
| | (375 | ) | (35 | ) | % |
| Cooling degree days | | 1,365 |
| | 1,408 |
| | (43 | ) | (3 | ) | | | 1,399 |
| | 1,494 |
| | (95 | ) | (6 | ) | |
| | | | | | | | | | | | | | | | | |
| Sources of energy (GWh): | | | | | | | | | | | | | | | | |
| Coal | | 1,351 |
| | 794 |
| | 557 |
| 70 |
| % | | 2,577 |
| | 1,267 |
| | 1,310 |
| 103 |
| % |
| Natural gas | | 3,012 |
| | 3,734 |
| | (722 | ) | (19 | ) | | | 5,281 |
| | 7,128 |
| | (1,847 | ) | (26 | ) | |
| Total energy generated | | 4,363 |
| | 4,528 |
| | (165 | ) | (4 | ) | | | 7,858 |
| | 8,395 |
| | (537 | ) | (6 | ) | |
| Energy purchased | | 1,542 |
| | 1,505 |
| | 37 |
| 2 |
| | | 2,353 |
| | 2,148 |
| | 205 |
| 10 |
| |
| Total | | 5,905 |
| | 6,033 |
| | (128 | ) | (2 | ) | | | 10,211 |
| | 10,543 |
| | (332 | ) | (3 | ) | |
NVE recognized net income of $187.2 million for the three months ended September 30, 2013, compared to $223.2 million for the same period in 2012. The decrease in net income is primarily due to the following pre-tax items:
The PUCN disallowance of EEIR revenue and carrying charges of $16.2Gross margin decreased $16 million, and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4, Regulatory Actionsor 5%, of the Condensed Notes to Financial Statements;
MidAmerican merger-related costs of $7.9 million as discussed in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements;
An increase in other operating expense primarily due to an increase in meter software maintenance, and right of way leases, overall generation expenses and wage increases for the IBEW 396 collective bargaining agreement. See the Utilities’ respective Resultssecond quarter of Operations for further discussion;
A decrease in other income primarily due to the gain on sale of telecommunications towers recorded in 2012; and
A decrease in gross margin of $4.3 million not including the disallowance and provision discussed above. See the Utilities’ respective Results of Operations for further discussion of gross margin.
These decreases were partially offset by the following pre-tax items:
A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.
NVE recognized net income of $271.9 million for the nine months ended September 30, 2013,2014 compared to $304.8 million for the same period in 2012. The decrease in net income is primarily2013 due to the following pre-tax items:
The PUCN disallowance of EEIR revenue and carrying charges of $16.2 million and the additional provision recorded against 2013 EEIR revenue of $15.1 million and other regulatory disallowances of $1.1 million. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements;
MidAmerican merger-related costs of $21.4 million as discussed in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements;
An increase in other operating expense primarily due to an increase in regulatory expenses, a $3.4 million reduction in capitalized costs as a result of a decrease in construction activity, an increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, an increase in outside consulting fees, and increased meter software maintenance and right of way. See the Utilities’ respective Results of Operations for further discussion;
An increase in depreciation expense primarily due to the completion of various projects; and
A decrease in other income primarily due to income recognized in 2012 for a construction contract settlement for the Harry Allen Generating Station and the gain on sale of telecommunications towers recorded in 2012.
These increases were partially offset by the following pre-tax items:
An increase in gross margin of $14.1 million not including the disallowance and provision discussed above. See the Utilities’ respective Results of Operations for further discussion of gross margin;
A decrease in maintenance expense primarily due to a decrease in outages;
A decrease in interest expense primarily due to the redemption of NPC’s 6.5% General and Refunding Mortgage Notes, Series I in April 2012; and
A decrease in interest expense on regulatory items primarily due to lower over collected deferred energy and regulatory balances.
NVE Transformation
Beginning in 2006, NVE committed to an energy strategy to manage resources against our load by constructing/purchasing generating facilities, purchasing and developing renewable energy, encouraging energy efficiency and conservation programs, as well as expanding our transmission capability in an effort to reduce our reliance on purchased power. The implementation of this strategy required significant amounts of liquidity and capital. To meet these capital requirements during the transformation, NVE and the Utilities issued, refinanced and reduced debt which improved credit ratings and decreased interest costs. At the same time, management worked with the PUCN to communicate the necessity of investments to better serve our customers, the prudency of costs incurred and the importance of a reasonable and timely return on such investments for our shareholders.
The energy strategy and regulatory diligence discussed above created a strong foundation for NVE and the Utilities to earn their allowable return on their investments while meeting a higher percentage of their load through owned generation. Additionally, as a result of their financial policies, which focused on lowering interest rates and reducing debt, interest costs and their capital structure continue to improve. Furthermore, through employee dedication and increased use of technology we continue to improve processes to enhance performance while keeping operating and maintenance costs relatively stable. As a result, NVE expects to generate free cash flow in 2013, which will continue to provide NVE the ability to maintain its dividend.
Key Initiatives
The economy in Nevada continues to recover slowly. While a low growth environment can be challenging, the foundation established in prior years, including establishing energy independence, improving capital structure and liquidity and managing our regulatory environment, has positioned the Utilities to operate in this environment. However, NVE and the Utilities continue to implement and develop key initiatives that collectively may further strengthen our capital structure and to consider new investment opportunities. In addition, NVE management remains focused on the execution of the MidAmerican Merger. These initiatives should enable us to contain operating and maintenance costs while effectively managing our regulatory environment and continuing to promote and improve a safe and reliable work environment. These key initiatives are discussed below.
Continuous Improvement ofSafety to:
The safety of NVE’s employees and the public is a core value of NVE and the Utilities. Accordingly, NVE has worked to integrate a set of safety principles into its business operations and culture. These principles include not only complying with applicable safety, health and security regulations, but also implementing programs and processes aimed at continually improving safety and security conditions. Our initiatives in 2013 and beyond will continue modeling a safety culture in all areas of the company.
Construction of ON Line
ON Line is Phase 1 of a joint project between the Utilities and GBT-South. Completion of ON Line, expected in December 2013, will connect NVE’s southern and northern service territories. ON Line will provide:
Ability to dispatch energy jointly throughout the state;
Access for southern Nevada to renewable energy resources in parts of northern and eastern Nevada, which will enhance NVE’s ability to meet its Portfolio Standard; and
Ability to optimize its generating and transmission facilities to benefit its customers.
One Company Merger
In May 2013, NPC and SPPC filed a joint application with the PUCN to consolidate the Utilities into a single jurisdictional utility. The joint application with the PUCN requested the following:
Authority to modify the legal and regulatory structures of NPC and SPPC by merging SPPC into NPC, effectively transferring all of SPPC’s assets and obligations to NPC, and renaming the surviving utility "NV Energy Operating Company" (NVEOC);
Authority to transfer SPPC’s certificates of public convenience and necessity (CPCN) to NPC, and to modify the transferred CPCNs and NPC’s CPCN to reflect the name of the surviving utility, NVEOC; and
Authority to transfer all SPPC’s electric and gas utility assets, including electric generation assets, to NPC.
The PUCN may not authorize the One Company Merger unless it finds, among other things, that the proposed transaction is “in the public interest.” The PUCN is not bound by any statutory deadlines with respect to this application. Hearings were expected to begin in February 2014, but the Utilities are seeking to delay the proceedings to the second half of 2014.
In May 2013, NVE, NPC and SPPC filed an application with the FERC under Section 203 of the Federal Power Act for Approval of Internal Reorganization. In their request, NPC and SPPC requested FERC authorization for an internal corporate reorganization under which SPPC will merge into NPC and be renamed NVEOC. On October 21, 2013, NVE, NPC and SPPC submitted an informational filing with FERC indicating that given the status of an application pending before the PUCN, the applicants did not object to FERC deferring its consideration of the application. The application remains pending before FERC for consideration.
Empower Customers through Focused Service and Efficiency Programs
NV Energize is a NVE project that includes Advanced Meter Infrastructure, Smart Grid Technology and Meter Data Management. The NV Energize capabilities will allow NVE to help customers better manage their usage with the most cost-effective mix of pricing, service, efficiency and conservation options. Since April 30, 2013, the project was deemed to be substantially complete. SPPC has included its proportionate share of costs, in its 2013 GRC, and NPC’s proportionate share of costs will be included in a future rate case.
The NV Energize system provides more convenience for customers and is achieving operating savings through both automated meter reading and the elimination annually of approximately 1 million trips to customers’ premises to process service requests. The system also enables NVE to launch new customer programs. Recruitment of participants for a trial of a combination of time based rates, supporting technology and education options is now underway. New detailed customer usage reports have been integrated into our web self-service capability, and customers can also request alerts on their billing information. An enhanced air conditioning demand response program was launched in the fourth quarter. It is designed to provide energy market based rebates for specific event participation and also includes an energy efficiency management capability. Similar programs for commercial customers are under development.
Managing Generation Portfolio within Environmental Compliance and NVision
As discussed further in Note $8Commitments and Contingencies, of the Condensed Notes to Financial Statements, NVision is NVE’s comprehensive plan for the reduction of emissions from coal-fired generation plants through the accelerated retirement of certain coal-fired plants, the replacement of the generation capacity of such plants with increased capacity from renewable energy facilities and other electric generating plants. In June 2013, the Nevada State Legislature passed SB 123, which was supported by NVE as part of its NVision initiative. The Utilities expect to file an emissions reduction plan in 2014 to specifically address the plan details.
Also discussed in more detail in Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, certain generating stations of NVE are affected under EPA’s Regional Haze Rules and Mercury and Air Toxics Standards (MATS). The implementation costs of these rules are significant. Therefore, NVE must balance the costs of implementing the retrofit and control technology associated with the Regional Haze Rule and MATS standards with the effects of NVision, current and future load requirements, retirements of generating stations, plant outages and the ability to serve customers reliably. To that end, the PUCN has accepted the Utilities’ resource plan to install necessary controls on the Tracy Generating Station Unit 3 and Fort Churchill Generating Station Units 1 and 2 to comply with Regional Haze. Tracy Generating Station Units 1 and 2 will be retired on or before the regional haze compliance date. Reid Gardner Generating Station Units 1, 2 and 3 are also affected by the regional haze compliance date, but no decision has been made for these units at this time as NVE considers the impacts of NVision on these units. In addition, the Utilities anticipate that sulfur dioxide (SO2) and/or acid gas reduction will be required at SPPC’s Valmy Generating Station Unit 1 to achieve compliance with the MATS standards. Furthermore, NPC expects to file an emissions reduction plan in 2014 to specifically address its 11.3% ownership participation in the Navajo Generating Station, as a result of a number of uncertainties, as well as environmental compliance and the passage of NVision.
Investment Opportunities
NVE continues to explore investment opportunities that may benefit our customers and that will add to our core business of generation, transmission and distribution of energy. In addition, NVE’s geographical location affords it access to various renewable resources for potential investment opportunities.
NV ENERGY, INC.
RESULTS OF OPERATIONS
NV Energy, Inc. and Other Subsidiaries
NVE (Holding Company)
The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $18.7 million and $18.9 million of long-term debt interest costs for the nine months ended September 30, 2013 and 2012, respectively.
For the nine month period ended September 30, 2013, NPC and SPPC paid $105.0 million and $40.0 million, respectively, in dividends to NVE. On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively.
Other Subsidiaries
Subsidiaries of NVE, other than NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
NVE’s net cash flows from operating activities were $553.7 million and $644.2 million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash from operating activities was primarily due to:
Under-collection of energy costs due to higher energy costs of $306.4 million, offset by reduced refunds to customers of $121.7 million;
Reduced EEPR collections of $50.1 million;
Payments in 2013 for outages that occurred in 2012 at the Reid Gardner and Lenzie Generating Stations of $22.7 million; and
Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.
The decrease in cash from operating activities was partially offset by:
Reduced coal purchases of $34.5 million;
Reduced spending on renewable programs of $27.8 million; and
Receipt of approximately $9.0 million in insurance proceeds related to a previous claim.
Cash Used By Investing Activities
NVE’s net cash used by investing activities were $(233.3) million and $(325.2) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
Reduced capital expenditure for the NV Energize project of $95.5 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $28.0 million; and
Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.
Cash Used By Financing Activities
NVE’s net cash flows used by financing activities were $(245.6) million and $(257.0) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by financing activities was primarily due to:
Issuance of SPPC’s $250 million, 3.375% General and Refunding Mortgage Notes, Series T debt; and
Reduction in cash used by NPC to retire debt of $166.9 million.
The decrease in cash used by financing activities was partially offset by:
Redemption of SPPC’s $250 million, 5.45% General and Refunding Mortgage Notes, Series Q debt;
Reduction of draws from the NPC revolving credit facility of $135.0 million; and
Increased dividends to shareholders of $23.3 million.
NVE paid common stock dividends of $134.3 million and $110.9 million during the nine months ended September 30, 2013 and 2012, respectively.
LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)
Overall Liquidity
NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Another significant use of cash is the refunding of previously
over-collected BTER amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes and economic conditions.
|
| | | | | | | | | | | |
| Available Liquidity as of September 30, 2013 (in millions) |
| | NVE | | NPC | | SPPC |
| Cash and Cash Equivalents | $ | 33.1 |
| | $ | 255.2 |
| | $ | 84.1 |
|
Balance available on Revolving Credit Facilities(1) | N/A |
| | 500.0 |
| | 243.7 |
|
| | $ | 33.1 |
| | $ | 755.2 |
| | $ | 327.8 |
|
| |
(1)
| As of November 6, 2013, NPC and SPPC had approximately $500.0 million and $244.0 million available under their revolving credit facilities, which includes reductions in availability for letters of credit. |
NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, the Utilities may use their revolving credit facilities in order to meet their liquidity needs. Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
For the remainder of 2013, NVE and the Utilities have no other debt maturities. NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. Additionally, in October of 2014, NVE's $195.0 million Term Loan will mature. To meet these long-term maturing debt obligations, the Utilities intend to use a combination of internally generated funds, the Utilities’ revolving credit facilities, and/or the issuance of long-term debt. The Utilities’ credit ratings on their senior secured debt remains at investment grade (see Credit Ratings below). NVE and the Utilities have not recently experienced any limitations in the credit markets, nor do we expect any for the remainder of 2013. However, disruption in the banking and capital markets not specifically related to NVE and the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, NVE and the Utilities required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NVE and the Utilities have transitioned to slower growth, the amount of capital expenditures has declined. NVE’s and the Utilities’ investment in generating stations in the past several years and more stable energy markets have positioned the Utilities to better manage and optimize their resources. As a result, NVE and the Utilities anticipate that they will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of the Utilities’ revolving credit facilities. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, federal tax NOL and a decrease in capital expenditures, NVE and the Utilities expect to generate free cash flow in 2013; however, NVE’s and the Utilities’ cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to maintain our dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate, or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity under such circumstances, NVE and the Utilities may be required to delay capital expenditures or refinance debt. Additionally, if deemed prudent, the Utilities may enter into hedging transactions in an attempt to mitigate projected or actual rising energy costs. Currently, the Utilities are not operating under a PUCN approved hedging plan. Hedging transactions may have a material impact on the Utilities’ cash flows, unless recovered in rates in a timely manner.
As of November 6, 2013, NVE has approximately $10.8 million payable of debt service obligations remaining for 2013, which it intends to fund through dividends from subsidiaries. See Factors Affecting Liquidity-Dividends from Subsidiaries, below. For the nine months ended September 30, 2013, NPC and SPPC paid dividends to NVE of approximately $105.0 million and $40.0 million, respectively. On November 6, 2013, NPC and SPPC declared dividends payable to NVE of $73.0 million and $37.0 million, respectively.
NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities. As discussed in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NVE’s 2012 Form 10-K except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN. The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period. However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million.
Financing Transactions
Nevada Power Company
In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
Sierra Pacific Power Company
In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand, to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.
Factors Affecting Liquidity
Ability to Issue Debt
Certain debt of NVE (holding company) places restrictions on debt incurrence and liens, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four-quarter period on a pro forma basis is at least 1.50 to 1.00 and the ratio of consolidated total indebtedness to consolidated capitalization does not exceed 0.70 to 1.00. Under these covenant restrictions, as of September 30, 2013, NVE (consolidated) would be allowed to incur up to $3.7billion of additional indebtedness. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition. NPC’s and SPPC’s Ability to Issue Debt sections further discuss their limitations on their ability to issue debt.
Effect of Holding Company Structure
As of September 30, 2013, NVE (on a stand-alone basis) had outstanding debt and other obligations including, but not limited to: a $195 million Term Loan due October 2014; and $315 million of unsecured 6.25% Senior Notes due 2020.
Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.
As of September 30, 2013, NVE, NPC, SPPC and their subsidiaries had approximately $4.9 billion of debt and other obligations outstanding, consisting of approximately $3.2 billion of debt at NPC, approximately $1.2 billion of debt at SPPC and approximately $510.0 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.
Dividends from Subsidiaries
Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by the PUCN, which may impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay. While the PUCN has in the past imposed a dividend restriction with respect to NPC and SPPC, as of September 30, 2013, there were no dividend restrictions imposed on the Utilities by the PUCN.
In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt being rated investment grade by S&P and Moody’s, these restrictions are suspended and no longer in effect so long as such debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by the FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.
Credit Ratings
The liquidity of NVE and the Utilities, the cost and availability of borrowing by the Utilities under their respective credit facilities, the potential exposure of the Utilities to collateral calls under various contracts and the ability of the Utilities to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for the companies’ debt. On May 22, 2013, Moody’s upgraded NVE’s, NPC’s and SPPC’s ratings. On May 30, 2013, Fitch and Standard & Poor’s upgraded NPC’s and SPPC’s rating outlook from Stable to Positive. NPC’s and SPPC’s senior secured debt is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. As of September 30, 2013, the ratings are as follows:
|
| | | | | | | |
| | | Rating Agency |
| | | Fitch(1)
| | Moody’s(2)
| | S&P(3)
|
NVE | Sr. Unsecured Debt | | BB+ | | Baa3* | | BB+ |
NPC | Sr. Secured Debt | | BBB+* | | A3* | | BBB+* |
SPPC | Sr. Secured Debt | | BBB+* | | A3* | | BBB+* |
| |
(1)
| Fitch's lowest level of "investment grade" credit rating is BBB-. |
| |
(2)
| Moody's lowest level of "investment grade" credit rating is Baa3. |
| |
(3)
| S&P's lowest level of "investment grade" credit rating is BBB-. |
Fitch’s and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for NVE, NPC and SPPC.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and, accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change, which includes a credit rating downgrade of NPC and SPPC, may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of September 30, 2013 for all suppliers continuing to provide power under a WSPP agreement would approximate a $49.7 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily mean a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.
Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the
event of credit rating downgrades. As of September 30, 2013, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26.0 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings both are downgraded to below investment grade.
Financial Gas Hedges
The Utilities may enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K, NPC’s and SPPC’s Financing Transactions, the availability under the Utilities’ revolving credit facilities is reduced for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time exceed 50% of the total commitments then in effect under the credit facilities. Currently, there are no negative mark-to-market exposures that would impact borrowings of the Utilities. If deemed prudent, the Utilities may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.
Cross Default Provisions
None of the Utilities’ financing agreements contains a cross default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in an event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NVE and the Utilities. As a result, NVE, NPC and SPPC will be required to offer to purchase approximately $315.0 million, $3.1 billion, and $951.7 million, respectively, of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, NVE and the Utilities are unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these financing agreements is approximately 6.25%, 6.42% and 5.51% for NVE, NPC and SPPC, respectively. To the extent that debt securities are tendered pursuant to the required tender offers, NVE and the Utilities intend to fund the purchases using a combination of internal funds, the Utilities’ revolving credit facilities or the issuance of long-term debt. Furthermore, NVE and the Utilities were required to obtain consents from lenders under the terms of Utilities’ revolving credit facilities and NVE’s Term Loan before consummating the MidAmerican Merger. In November 2013, NVE amended its Term Loan and NPC and SPPC amended their revolving credit facilities, in each case to permit the MidAmerican Merger.
NEVADA POWER COMPANY
RESULTS OF OPERATIONS
NPC recognized net income of approximately $164.4 million during the three months ended September 30, 2013, compared to $195.2 million for the same period in 2012. During the nine months ended September 30, 2013, NPC recognized net income of approximately $228.6 million, compared to $256.2 million for the same period in 2012.
For the nine month period ended September 30, 2013, NPC paid $105.0 million in dividends to NVE. On November 6, 2013, NPC declared a dividend of $73.0 million to NVE.
Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.
NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments and regulatory disallowances (which are required by statute to be filed every three years).
The components of gross margin were (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Operating Revenues: | $ | 786,142 |
| | $ | 802,334 |
| | $ | (16,192 | ) | | (2.0)% | | $ | 1,695,129 |
| | $ | 1,751,165 |
| | $ | (56,036 | ) | | (3.2)% |
| | | | | | | | | | | | | | | | | |
| Energy Costs: | |
| | |
| | |
| | | | |
| | |
| | |
| | |
| | Fuel for power generation | 163,127 |
| | 123,992 |
| | 39,135 |
| | 31.6% | | 412,904 |
| | 285,799 |
| | 127,105 |
| | 44.5% |
| | Purchased power | 172,582 |
| | 171,687 |
| | 895 |
| | 0.5% | | 383,386 |
| | 388,494 |
| | (5,108 | ) | | (1.3)% |
| | Deferred energy | (45,381 | ) | | (22,685 | ) | | (22,696 | ) | | 100.0% | | (154,484 | ) | | (15,461 | ) | | (139,023 | ) | | 899.2% |
| Energy efficiency program costs | 13,998 |
| | 28,492 |
| | (14,494 | ) | | (50.9)% | | 32,807 |
| | 65,466 |
| | (32,659 | ) | | (49.9)% |
| Regulatory disallowance | 11,866 |
| | — |
| | 11,866 |
| | N/A | | 11,866 |
| | — |
| | 11,866 |
| | N/A |
| | Total Costs | $ | 316,192 |
| | $ | 301,486 |
| | $ | 14,706 |
| | 4.9% | | $ | 686,479 |
| | $ | 724,298 |
| | $ | (37,819 | ) | | (5.2)% |
| | | | | | | | | | | | | | | | | |
| Gross Margin | $ | 469,950 |
| | $ | 500,848 |
| | $ | (30,898 | ) | | (6.2)% | | $ | 1,008,650 |
| | $ | 1,026,867 |
| | $ | (18,217 | ) | | (1.8)% |
Gross margin decreased for the three and nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to the disallowance of EEIR revenue and carrying charge and other deferred energy disallowances of $11.9 million (pre-tax) and a provision of $11.1 million (pre-tax) recorded against 2013 EEIR revenues, as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, NPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease in margin was a decrease inlower usage primarily due to a decrease in CDDs, as showncooling degree days;
$7 million in the table below. lower energy efficiency program rate revenue, which is offset in operating and maintenance expense;
$4 million in lower volume driven demand charges to industrial customers due to lower cooling degree days; and
$3 million in lower energy efficiency implementation rate revenue.
The decrease in gross margin was partially offset by:
$4 million higher transmission rate revenue; and
$3 million due to customer growth.
Gross margin decreased $30 million, or 5%, for the first six months of 2014 compared to 2013 due to:
$20 million in lower usage primarily due to a decrease in cooling degree days during 2014;
$12 million in lower energy efficiency program rate revenue, which is offset in operating and maintenance expense;
$6 million in lower energy efficiency implementation rate revenue; and
$3 million in lower volume driven demand charges to industrial customers due to lower cooling degree days.
The decrease in gross margin was partially offset by:
$6 million in higher transmission rate revenue; and
$5 million due to customer growth.
Operating and maintenance expense decreased $17 million, or 16%, for the second quarter of 2014 compared to 2013 due to:
$7 million in lower energy efficiency program costs, which are fully recovered in operating revenue;
$3 million in decreased major outages and planned maintenance expense at the Higgins, Silverhawk and Harry Allen Generating Stations;
$3 million in lower compensation costs;
$3 million in lower investor relation, bad debt and insurance costs; and
$2 million in lower sales taxes related to a long-term service agreement settlement.
The decrease in operating and maintenance expense was partially offset by customer growth and an increase in BTGR revenue.
HDDs and CDDs
MWh usage may be affected byhigher operating costs for Reid Gardner Unit 4 of $2 million previously shared with the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.
The following table shows the HDDs and CDDs within NPC’s service territory:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| NPC | | | | | | | | | | | | | | | |
| | Heating | — |
| | — |
| | — |
| | N/A | | 1,084 |
| | 986 |
| | 98 |
| | 9.9 | % |
| | Cooling | 2,164 |
| | 2,313 |
| | (149 | ) | | (6.4 | )% | | 3,658 |
| | 3,771 |
| | (113 | ) | | (3.0 | )% |
The causes for significant changes in specific lines comprising the results of operations for NPCOperating and maintenance expense decreased $34 million, or 17%, for the respective periodsfirst six months of 2014 compared to 2013 due to:
$12 million in lower energy efficiency program costs, which are provided below (dollarsfully recovered in thousands exceptoperating revenue;
$9 million in decreased major outages and planned maintenance expense at the Higgins, Lenzie, Silverhawk and Harry Allen Generating Stations;
$8 million in lower compensation, employee benefits and stock compensation costs;
$6 million in lower investor relation, bad debt and insurance costs;
$2 million in lower costs associated with outside consulting services; and
$2 million in lower sales taxes related to a long-term service agreement settlement.
The decrease in operating and maintenance expense was partially offset by:
$3 million in higher operating costs for amounts per unit):Reid Gardner Unit 4 previously shared with the former partner; and
$2 million in ON Line lease payments.
Depreciation and amortization increased $4 million, or 6%, for the second quarter and $5 million, or 4%, for the first six months of 2014 compared to 2013 primarily due to higher plant-in-service, including ON Line being placed in-service in December 2013.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenue | | | | | | | | | | | | | | | |
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Operating Revenues: | | | | | | | | | | | | | | | |
| | Residential | $ | 420,072 |
| | $ | 436,534 |
| | $ | (16,462 | ) | | (3.8 | )% | | $ | 891,024 |
| | $ | 915,953 |
| | $ | (24,929 | ) | | (2.7 | )% |
| | Commercial | 120,407 |
| | 121,334 |
| | (927 | ) | | (0.8 | )% | | 305,876 |
| | 318,126 |
| | (12,250 | ) | | (3.9 | )% |
| | Industrial | 226,739 |
| | 227,824 |
| | (1,085 | ) | | (0.5 | )% | | 452,825 |
| | 473,548 |
| | (20,723 | ) | | (4.4 | )% |
| | | Retail revenues | 767,218 |
| | 785,692 |
| | (18,474 | ) | | (2.4 | )% | | 1,649,725 |
| | 1,707,627 |
| | (57,902 | ) | | (3.4 | )% |
| | Other | 18,924 |
| | 16,642 |
| | 2,282 |
| | 13.7 | % | | 45,404 |
| | 43,538 |
| | 1,866 |
| | 4.3 | % |
| | | Total Operating Revenues | $ | 786,142 |
| | $ | 802,334 |
| | $ | (16,192 | ) | | (2.0 | )% | | $ | 1,695,129 |
| | $ | 1,751,165 |
| | $ | (56,036 | ) | | (3.2 | )% |
| | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of MWhs | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Residential | 3,627 |
| | 3,752 |
| | (125 | ) | | (3.3 | )% | | 7,592 |
| | 7,619 |
| | (27 | ) | | (0.4 | )% |
| | Commercial | 1,329 |
| | 1,374 |
| | (45 | ) | | (3.3 | )% | | 3,423 |
| | 3,480 |
| | (57 | ) | | (1.6 | )% |
| | Industrial | 2,078 |
| | 2,145 |
| | (67 | ) | | (3.1 | )% | | 5,756 |
| | 5,836 |
| | (80 | ) | | (1.4 | )% |
| Retail sales in thousands of MWhs | 7,034 |
| | 7,271 |
| | (237 | ) | | (3.3 | )% | | 16,771 |
| | 16,935 |
| | (164 | ) | | (1.0 | )% |
| | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | $ | 109.07 |
| | $ | 108.06 |
| | $ | 1.01 |
| | 0.9 | % | | $ | 98.37 |
| | $ | 100.83 |
| | $ | (2.46 | ) | | (2.4 | )% |
NPC’s retail revenuesMerger-related expense decreased $9 million for both the second quarter and for the threefirst six months ended September 30, 2013, asof 2014 compared to the same period in 20122013 due to $25.8 million in decreased usage primarily resulting from a decrease in CDDs, as shown in the table above, and an additional $14.4 million due to decreased EEPR rates, effective January 1, 2013. Also contributingcosts incurred related to the decrease was a provisionmerger of $11.1BHE and NV Energy in 2013.
Interest expense, net of allowance for debt funds decreased $1 million, recorded againstor 2%, for the second quarter and $3 million, or 3%, for the first six months of 2014 compared to 2013 EEIR revenues as a result of using cash on hand to repay existing debt in July and December 2013 and lower amortization of debt expenses of $1 million for both the precedent set bysecond quarter and the PUCN’s ruling in NPC’s EEIR filing and NPC’s estimated ratefirst six months of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes2014 compared to Financial Statements for further discussion of the EEIR disallowance. These decreases were2013, partially offset by an increaselower debt AFUDC of $26.3$2 million as a resultfor the second quarter and $3 million for the first six months of NPC’s various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes2014 compared to the Financial Statements in the 2012 Form 10-K) and $6.0 million2013 due to retail customer growth.lower construction activity.
ForAllowance for equity funds decreased $2 million for the threesecond quarter and $4 million for the first six months ended September 30,of 2014 compared to 2013 the average number of retail customers increased by 1.3%, consisting of an increasedue to assets placed in-service, including ON Line being placed in-service in residential and commercial customers of 1.3% and 1.7%, respectively,December 2013, and a decrease in industrial customers of 0.6%, compared to the same period in the prior year.
Electric Operating Revenues - Other increased for the three months ended September 30, 2013, compared to the same period in 2012, due to an increase in transmission rates of $2.4 million as a result of the FERC rate case effective June 1, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion.construction activity.
NPC’s retail revenues decreasedOther, net increased $1 million, or 33%, for the ninesecond quarter and $2 million, or 25%, for the first six months ended September 30, 2013, asof 2014 compared to the same period in 20122013 due to $32.4$1 million from decreased EEPR rates effective January 1, 2013, $19.4 million due to a decrease in CDDs, as shownhigher dividend and investment income in the table above, $11.1second quarter of 2014 and $1 million provisionin higher interest earned on regulatory items for EEIR revenue recorded in 2013, as discussed above, and $8.6 million as a resultthe first six months of NPC’s various BTER and DEAA quarterly updates (see Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K). These decreases were offset by an increase of $9.2 million from residential customer growth.2014.
ForIncome tax expense increased $3 million, or 9%, for the ninesecond quarter and $4 million, or 11%, for the first six months of 2014 compared to 2013 and the effective tax rates were 36% for the second quarter and first six months of 2014 and 35% for the second quarter and first six months of 2013. The increase in income tax expense is primarily due to higher income before income tax expense.
Liquidity and Capital Resources
As of June 30, 2014, the Company's total net liquidity was $568 million consisting of $168 million in cash and cash equivalents and $400 million of revolving credit facility availability.
Operating Activities
Net cash flows from operating activities for the six-month periods ended SeptemberJune 30, 2014 and 2013 the average numberwere $148 million and $130 million, respectively. The change was primarily due to reduced refunds to customers for previously over-collected deferred energy costs, increased transmission sales and timing of short-term incentive payments, partially offset by a one-time bill credit paid to retail customers in 2014 associated with the merger between BHE and NV Energy, increased by 1.0%, consisting of an increase in residentialspending on renewable energy programs and commercial customers of 1.0% and 1.6%, respectively, and a decrease in industrial customers of 0.1%, comparedincreased rent payments related to the same period in the prior year.ON Line transmission use agreement.
Electric Operating Revenues - Other increasedInvesting Activities
Net cash flows from investing activities for the nine monthssix-month periods ended SeptemberJune 30, 2014 and 2013 compared to the same period in 2012,were $(97) million and $(107) million, respectively. The change was primarily due to an increase in transmission ratescontributions in aid of $2.1 million as a result of the FERC rate case effective June 1, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion.
Energy Costs
Energy Costs include fuel for generationconstruction and purchased power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:
weather
generation efficiency
plant outages
total system demand
resource constraints
transmission constraints
natural gas constraints
long-term contracts
mandated power purchases; and
volatility of commodity prices
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Energy Costs | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Fuel for power generation | $ | 163,127 |
| | $ | 123,992 |
| | $ | 39,135 |
| | 31.6 | % | | $ | 412,904 |
| | $ | 285,799 |
| | $ | 127,105 |
| | 44.5 | % |
| | Purchased power | 172,582 |
| | 171,687 |
| | 895 |
| | 0.5 | % | | 383,386 |
| | 388,494 |
| | (5,108 | ) | | (1.3 | )% |
| Energy Costs | $ | 335,709 |
| | $ | 295,679 |
| | $ | 40,030 |
| | 13.5 | % | | $ | 796,290 |
| | $ | 674,293 |
| | $ | 121,997 |
| | 18.1 | % |
| | | | | | | | | | | | | | | | | |
| MWhs | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | MWhs Generated (in thousands) | 5,242 |
| | 5,105 |
| | 137 |
| | 2.7 | % | | 13,310 |
| | 12,264 |
| | 1,046 |
| | 8.5 | % |
| | Purchased Power (in thousands) | 2,077 |
| | 2,392 |
| | (315 | ) | | (13.2 | )% | | 4,225 |
| | 5,415 |
| | (1,190 | ) | | (22.0 | )% |
| Total MWhs | 7,319 |
| | 7,497 |
| | (178 | ) | | (2.4 | )% | | 17,535 |
| | 17,679 |
| | (144 | ) | | (0.8 | )% |
| | | | | | | | | | | | | | | | | |
| Average cost per MWh | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Average fuel cost per MWh of Generated Power | $ | 31.12 |
| | $ | 24.29 |
| | $ | 6.83 |
| | 28.1 | % | | $ | 31.02 |
| | $ | 23.30 |
| | $ | 7.72 |
| | 33.1 | % |
| | Average cost per MWh of Purchased Power | $ | 83.09 |
| | $ | 71.78 |
| | $ | 11.32 |
| | 15.8 | % | | $ | 90.74 |
| | $ | 71.74 |
| | $ | 19.00 |
| | 26.5 | % |
| | Average total cost per MWh | $ | 45.87 |
| | $ | 39.44 |
| | $ | 6.43 |
| | 16.3 | % | | $ | 45.41 |
| | $ | 38.14 |
| | $ | 7.27 |
| | 19.1 | % |
Energy Costs and the average total cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to an increase in costs associated with higher natural gas pricescustomer advances, partially offset by a decrease in the volume of purchased power which is typically more expensive than generated power. Overall volume decreased slightly primarily due to a decrease in CDDs, as shown in the table above.
Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012. Contributing to the increase was approximately $34.1 million due to higher natural gas prices, partially offset by a decrease in the volume of natural gas of $8.4 million. The increase in the volume of coal and the price of coal prices also contributed approximately $12.2 million and $1.2 million, respectively, to the increase in fuel for generation costs.
Fuel for generation costs increased for the nine months ended September 30, 2013, compared to the same periods in 2012. Contributing to the increase was approximately $96.4 million and $8.2 million due to higher natural gas prices and the volume of natural gas used, respectively. The increase in the volume of coal used and a slight increase in coal prices also contributed approximately $21.6 million and $0.9 million, to the increase in fuel for generation costs.
Purchased power costs increased for the three months ended September 30, 2013, compared to the same period in 2012. The increase in purchased power costs for the three month period was primarily due to a $23.6 million and a $3.7 million increase in the price of non-renewable purchases and renewable purchases, respectively. The increase in cost was largely offset by a decrease in the volume of non-renewable power purchases and renewable power purchases of approximately $16.4 million and $10.0 million, respectively.
Purchased power costs decreased for the nine months ended September 30, 2013, compared to the same period in 2012. The decrease is primarily due to $72.2 million and $35.6 million attributable to decreased volume of non-renewable power purchases and renewable purchases, respectively. The decrease was largely offset by an increase in the price of non-renewable purchases of approximately $70.8 million, primarily due to higher natural gas prices, and an increase in the price of renewable purchases of $31.9 million.capital expenditures.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred Energy |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Deferred energy | $ | (45,381 | ) | | $ | (22,685 | ) | | $ | (22,696 | ) | | 100.0% | | $ | (154,484 | ) | | $ | (15,461 | ) | | $ | (139,023 | ) | | 899.2% |
Deferred EnergyNet cash flows for the three monthssix-month periods ended SeptemberJune 30, 2014 and 2013 and 2012 include amortization of deferred energy of $(6.2)were $(9) million and $(58.3)$(82) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further
contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(39.2) million in 2013 and over-collections of $35.6 million in 2012.
Amounts for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(57.1) million and $(136.5) million, respectively which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy balance are under-collections of amounts recoverable in rates of $(97.4) million in 2013, and over-collections of $121.0 million in 2012.
Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Operating Expenses | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Energy efficiency program costs | $ | 13,998 |
| | $ | 28,492 |
| | $ | (14,494 | ) | | (50.9)% | | $ | 32,807 |
| | $ | 65,466 |
| | $ | (32,659 | ) | | (49.9)% |
| Regulatory disallowance | $ | 11,866 |
| | $ | — |
| | $ | 11,866 |
| | N/A | | $ | 11,866 |
| | $ | — |
| | $ | 11,866 |
| | N/A |
| Merger-related costs | $ | 5,620 |
| | $ | — |
| | $ | 5,620 |
| | N/A | | $ | 14,487 |
| | $ | — |
| | $ | 14,487 |
| | N/A |
| Other operating expenses | $ | 70,844 |
| | $ | 65,372 |
| | $ | 5,472 |
| | 8.4% | | $ | 208,336 |
| | $ | 200,484 |
| | $ | 7,852 |
| | 3.9% |
| Maintenance | $ | 11,208 |
| | $ | 12,533 |
| | $ | (1,325 | ) | | (10.6)% | | $ | 45,172 |
| | $ | 52,594 |
| | $ | (7,422 | ) | | (14.1)% |
| Depreciation and amortization | $ | 68,849 |
| | $ | 66,975 |
| | $ | 1,874 |
| | 2.8% | | $ | 207,915 |
| | $ | 201,096 |
| | $ | 6,819 |
| | 3.4% |
For the three and nine months ended September 30, 2013 energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.
respectively. The regulatory disallowance consists of $10.8 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of NPC’s authorized ROR. The amount also includes a disallowance of approximately $1.1 million in deferred energy. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements.
As discussed further in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement. As a result of the MidAmerican Merger, NPC incurred $5.6 million and $14.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger. NPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.
Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.2 million in increased meter software maintenance and right of way leases, $1.2 million increase in overall generation operating expenses, $1.0 million increase due to IBEW 396 collective bargaining agreement ratification bonus and wage increase, and $0.4 million increase in regulatory expenses.
Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $2.5 million reduction in capitalized costs as a result of a decrease in construction activity, a $2.5 million increase in chemical and operating expenses at the Reid Gardner and Clark Generating Stations, a $2.3 million increase in outside consulting fees, $1.7 million increase in regulatory expenses and $1.6 million in increased meter software maintenance and right of way leases.
Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $1.2 million of major planned maintenance outages in 2012 at the Silverhawk and Harry Allen Generating Stations and lower expenses at Higgins Generating Station.
Maintenance expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $10.0 million of major maintenance outages in 2012 at the Silverhawk, Lenzie, Harry Allen and Reid Gardner Generating Stations, offset by $2.8 million of planned maintenance outages in 2013 at the Higgins and Clark Generating Stations.
Depreciation and amortization increased for the three and nine months ended September 30, 2013 compared to the same period in 2012, primarily due to general increases in plant-in-service.
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| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest Expense | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Interest expense | | | | | | | | | | | | | | | |
| (net of AFUDC-debt: $1,520, $1,528, $4,763 and $4,021) | $ | 52,856 |
| | $ | 51,784 |
| | $ | 1,072 |
| | 2.1% | | $ | 155,758 |
| | $ | 158,791 |
| | (3,033 | ) | | (1.9)% |
Interest expense increased for the three months ended September 30, 2013, compared to the same period in 2012 due to interest charges of $1.7 million for an assessment on a right of way lease, offset by a $0.3 million decrease in debt amortization expense and a $0.3 million decrease in interest for debt. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.
Interest expense decreased for the nine months ended September 30, 2013, compared to the same period in 2012 due to a $2.5 million decrease in interest costs primarily due to the redemption of the 6.5% General and Refunding Mortgage Notes, Series I in April 2012, an increase in AFUDC-debt of $0.7 million,a $0.7 million decrease in interest for debt, and a $0.6 million decrease in debt amortization expense. Offsetting these decreases was interest charges of $1.7 million for an assessment on a right of way lease. See Note 6, Long-Term Debt, of the Notes to Financial Statements in the 2012 Form 10-K and Note 5, Long-Term Debt, in the Condensed Notes to Financial Statements, for additional information regarding long-term debt.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| | | | | | | | | | | | | | | | |
| Interest income (expense) on regulatory items | $ | (194 | ) | | $ | (1,623 | ) | | $ | 1,429 |
| | (88.0 | )% | | $ | (1,177 | ) | | $ | (5,488 | ) | | $ | 4,311 |
| | (78.6 | )% |
| AFUDC-equity | $ | 1,959 |
| | $ | 1,833 |
| | $ | 126 |
| | 6.9 | % | | $ | 6,151 |
| | $ | 4,823 |
| | $ | 1,328 |
| | 27.5 | % |
| Other income | $ | 1,948 |
| | $ | 7,096 |
| | $ | (5,148 | ) | | (72.5 | )% | | $ | 5,330 |
| | $ | 14,197 |
| | $ | (8,867 | ) | | (62.5 | )% |
| Other expense | $ | (1,966 | ) | | $ | (2,823 | ) | | $ | 857 |
| | (30.4 | )% | | $ | (6,200 | ) | | $ | (7,162 | ) | | $ | 962 |
| | (13.4 | )% |
Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012. The decreasechange was primarily due to a decrease in interest on deferred energy of $2.9 million and $7.1 million for the three and nine month periods, respectively,dividends, partially offset by debt tendered in 2014 as a result of lower over-collected balances in 2013. The decrease in interest income (expense) on regulatory items was partially offset by $1.0 millionthe merger between BHE and $3.6 million for the threeNV Energy and nine month periods, respectively, as a result of decreased interest income due to lower regulatory asset balances. See Note 3, Regulatory Actions, of the Notes to Financial Statements in the 2012 Form 10-K. capital lease payments.
AFUDC-equity increased for the three and nine months ended September 30, 2013, comparedAbility to the same periods in 2012, primarily due to various construction projects.
Other income decreased for the three months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, offset slightly by higher gains on investments in 2013.
Other income decreased for the nine months ended September 30, 2013, compared to the same periods in 2012, due to a $5.5 million gain on the sale of telecommunication towers in 2012, a $4.9 million Harry Allen Generating Station construction project settlement recorded in 2012, offset slightly by several items, none of which were individually material.
Other expense decreased for the three and nine months ended September 30, 2013 compared to the same period in 2012, by several items, none of which were individually material.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
NPC’s net cash flows from operating activities were $399.2 million and $514 million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash from operating activities was primarily due to:
Under-collection of energy costs due to higher energy costs of $214 million, offset by reduced refunds to customers of $79.7 million;
Reduced EEPR collections of $44.3 million;
Payments in 2013 for outages that occurred in 2012 at Reid Gardner and Lenzie Generating Stations of $22.7 million;
Timing of payments for energy costs of $4.9 million; and
Reduced revenues due to decreased BTER and EEPR rates combined with reduced customer energy usage due to cooler summer weather in 2013 compared to the same period in 2012.Issue Debt
The decrease in cash from operating activities was partially offset by:
Reduced coal purchases of $11.1 million; and
Reduced spend on renewable programs of $7.4 million.
Cash Used By Investing Activities
NPC’s net cash used by investing activities were $(136.2) million and $(197.4) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
Reduced capital maintenance at Reid Gardner, Lenzie and Silverhawk Generating Stations of $54.2 million.
The decrease in cash used by investing activities was partially offset by:
Reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $10.6 million.
Cash Used By Financing Activities
NPC’s net cash flows used by financing activities were $(209) million and $(258) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by financing activities was primarily due to:
A reduction in cash used to retire debt of $166.9 million; and
Decreased dividends to NVE of $14 million.
The decrease in cash used by financing activities was partially offset by:
Reduced draws from the NPC revolving credit facility of $135 million.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.
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| | | |
| Available Liquidity as of September 30, 2013 (in millions) |
| | NPC |
| Cash and Cash Equivalents | $ | 255.2 |
|
Balance available on Revolving Credit Facility(1) | 500.0 |
|
| | $ | 755.2 |
|
| |
(1)
| As of November 6, 2013, NPC had approximately $500 million available under its revolving credit facility. |
NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, NPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facility, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
NPC has no further debt maturities for the remainder of 2013; however, NPC’s $125 million 7.375% General and Refunding Notes, Series U, will mature in January 2014. To meet these maturing debt obligations, NPC intends to use a combination of internally generated funds, its revolving credit facility, and/or the issuance of long-term debt. As of November 6, 2013, NPC has no borrowings on its revolving credit facility. NPC’s credit ratings on its senior secured debt remains at investment grade (see Credit Ratings below). NPC has not recently experienced any limitations in the credit markets, nor does NPC expect any significant limitations for the remainder of 2013. However, disruptions in the banking and capital markets not specifically related to NPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, NPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As NPC has transitioned to slower growth, the amount of capital expenditures required has declined. NPC’s investment in generating stations in the past several years and more stable energy markets have positioned NPC to better manage and optimize its resources. As a result, NPC anticipates that it will be able to meet short-term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility. Furthermore, with new investments now in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL and a decrease in capital expenditures, NPC expects to generate free cash flow in 2013; however, NPC’s cash flow may vary significantly from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities.
However, if energy costs rise at a rapid rate or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity under such circumstances, NPC may be required to delay capital expenditures, re-finance debt or receive capital contributions from NVE.
During the nine months ended September 30, 2013, NPC paid dividends to NVE of $105.0 million. On November 6, 2013, NPC declared a dividend to NVE of $73 million.
NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement and maintenance of facilities. As discussed, in Note 12, Commitments and Contingencies, of the 2012 Form 10-K, capital projects include NPC’s payment of Reid Gardner Generating Station Unit 4 from CDWR, which was completed in October 2013 for approximately $47.6 million.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in NPC’s 2012 Form 10-K.
Financing Transactions
In July 2013, NPC issued a notice of redemption to the bondholders for its $100 million Clark County Industrial Development Refunding Revenue Bonds, Series 2000A. In August 2013, NPC redeemed the aggregate principal amount outstanding of $98.1 million at 100% of the principal amount plus accrued interest with the use of cash on hand.
Ability to Issue Debt
NPC’sCompany's ability to issue debt is primarily impacted by certain factors such asits financing authority from the PUCN. As of June 30, 2014, the Company has financing authority from the PUCN financial covenants in its financing agreements, itsconsisting of authority to: (1) issue additional long-term debt securities of up to $725 million; (2) refinance up to $423 million of long-term debt securities; and (3) maintain a revolving credit facility agreement, and the terms of certain NVE debt. As of September 30, 2013, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $725.0 million in long-term debt, in addition to the use of its existing credit facility. However, depending on NVE’s or SPPC’s issuance of long-term debt or the use of the Utilities’$1.3 billion. The Company's revolving credit facilities,facility contains a financial maintenance covenant which the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:
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a. | Financing authority from the PUCN - As of September 30, 2013, NPC has financing authority from the PUCN for the period ending December 31, 2013, consisting of authority (1) to issue additional long-term debt securities of up to $725.0 million; (2) to refinance up to approximately $422.5 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $1.3 billion. In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details;
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| |
b. | Financial covenants within NPC’s financing agreements - Under the NPC Credit Agreement, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00. Based on financial statements for the period ended September 30, 2013, NPCCompany was in compliance with this covenant and could incur up to $3.2billion of additional indebtedness
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All other financial covenants contained in NPC’scompliance with as of June 30, 2014. In addition, certain financing agreements contain covenants which are currently suspended as NPC’sthe Company's senior secured debt is currently rated investment grade. However, if NPC’sthe Company's senior secured debt ratings fall below investment grade by either Moody’sMoody's Investor Service or S&P, NPCStandard & Poor's, the Company would again be subject to the limitations under these additional covenants; andcovenants.
Future Uses of Cash
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c. | Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.7billion.
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AbilityThe 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to Issue Generalprovide funds required for current operations, capital expenditures, debt retirements and Refunding Mortgage Securities
Toother capital requirements. The availability and terms under which the extent that NPCCompany has access to external financing depends on a variety of factors, including the ability to issue debt underCompany's credit ratings, investors' judgment of risk and conditions in the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so fromoverall capital markets, including the PUCN, NPC’s ability to issue secured debt is still limited bycondition of the amount of bondable property or retired bonds that can be used to issue debt under the NPC Indenture.
The NPC Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of September 30, 2013, $3.7 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $1.8 billionof General and Refunding Mortgage Securities as of September 30, 2013. That amount is determined on the basis of:utility industry.
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1. | 70% of net utility property additions; and/or |
| |
2. | the principal amount of retired General and Refunding Mortgage Securities. |
Capital Expenditures
Property additions include plant in service. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.
NPC also has the ability to release property from the lien of the NPC Indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of the NPC Indenture, it will reduce the amount of securities issuable under the NPC Indenture.
Credit Ratings
The liquidityCompany has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of NPC,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 borrowingcapital. Prudently incurred expenditures for compliance-related items, such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into the Company's regulated retail rates. Expenditures for certain assets may ultimately include acquisitions of existing assets.
Forecasted capital expenditures, which exclude amounts for non-cash equity AFUDC and other non-cash items, are approximately $383 million for the year ended December 31, 2014 and are as follows (in millions):
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| | | | |
| | | 2014 |
| | | |
| Generation development | | $ | 208 |
|
| Distribution | | 112 |
|
| Transmission system investment | | 10 |
|
| Other | | 53 |
|
| Total | | $ | 383 |
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Contractual Obligations
As of June 30, 2014, 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, 2013.
Regulatory Matters
The Company is subject to comprehensive regulation. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013, and new regulatory matters occurring in 2014.
The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company will not seek recovery of any lost revenue for calendar year 2014 in an amount that exceeds 50% of the lost revenue that the Company could otherwise request. In February 2014, the Company filed an application with the PUCN to reset the energy efficiency implementation rate. In June 2014, the PUCN accepted a stipulation to adjust the energy efficiency implementation rate, as of July 1, 2014, to collect 50% of the estimated lost revenue that the Company would otherwise be allowed to recover for the 2014 calendar year. The energy efficiency implementation rate will be effective from July through December 2014 and will reset on January 1, 2015 and remain in effect through September 2015. To the extent the Company's earned rate of return exceeds the rate of return used to set base general rates, the Company is required to refund to customers energy efficiency implementation rate revenue collected. As a result, the Company has deferred recognition of energy efficiency implementation rate revenue collected and has recorded a liability of $7 million on the Consolidated Balance Sheets as of June 30, 2014.
In May 2014, the Company filed the Emissions Reduction Capacity Replacement Plan in compliance with Senate Bill No. 123 ("SB 123") enacted by NPCthe 2013 Nevada Legislature. The filing proposed, among other items, the retirement of Reid Gardner Generating Station units 1, 2 and 3 in 2014 and unit 4 in 2017; the elimination of the Company's ownership interest in Navajo Generating Station in 2019; and a plan to replace the generation capacity being retired, as required by SB 123. The Emissions Reduction and Capacity Replacement Plan includes the issuance of requests for proposals for 300 MW of renewable energy to be issued between 2014 and 2016; the acquisition of a 274-MW natural gas co-generating facility in 2014; the acquisition of a 222-MW natural gas peaking facility in 2014; the construction of a 15-MW solar photovoltaic facility expected to be placed in-service in 2015; and the construction of a 200-MW solar photovoltaic facility expected to be placed in-service in 2016. In the second quarter of 2014, the Company executed various contractual agreements to fulfill the proposed Emissions Reduction and Capacity Replacement Plan, which are subject to PUCN approval. The impacts of the Emissions Reduction Capacity Replacement Plan to the Company's 2014 forecasted capital expenditures are included in the Future Uses of Cash previously discussed. The PUCN has scheduled a hearing on the application beginning in September 2014 and an order is expected in the fourth quarter of 2014.
In May 2014, the Company filed a general rate case with the PUCN. In July 2014, the Company made its certification filing, which requests incremental annual revenue relief in the amount of $38 million or an average price increase of 2%. An order is expected by the end of 2014 and, if approved, the new rates would be effective January 1, 2015.
NV Energy has announced plans to join the energy imbalance market ("EIM") in October 2015. The EIM is expected to reduce costs to serve customers through more efficient dispatch of a larger and more diverse pool of resources, more effectively integrate renewables and enhance reliability through improved situational awareness and responsiveness. In today's environment, utilities in the west outside the California Independent System Operator ("California ISO") rely upon a combination of automated and manual dispatch within the hour to balance generation and load to maintain reliable supply and have limited capability to transact within the hour outside their own borders. In contrast, the EIM will optimize and automate five-minute dispatch of generation to serve load across the state and the California ISO footprint. The EIM is voluntary and available to all balancing authorities in the Western United States. Benefits to customers are expected to increase as more entities join and the footprint grows bringing incremental generation and load diversity. In April 2014, the Company filed an application to amend its portfolio optimization procedures contained in the PUCN-approved energy supply plan for the remaining action period of 2015. The PUCN's final order approving the merger between BHE and NV Energy stipulated that the Company would obtain PUCN authorization prior to participating in an EIM. The amendment reflects the Company's participation in the EIM that is being established by the California ISO.
The filing requests the PUCN to determine that the amended energy supply plan balances the objectives of minimizing the cost of supply and retail price volatility, maximizes the reliability of supply over the remaining term of the plan, optimizes the value of the overall supply portfolio of the Company for the benefit of bundled retail customers and does not contain any features or mechanisms that the PUCN finds would impair the restoration or the creditworthiness of the Company. A hearing on the application was held in July 2014, and an order is expected in August 2014. In April 2014 the California ISO filed the Implementation Agreement entered into by the Company and the California ISO. The Implementation Agreement provides the mechanism by which the Company will compensate the California ISO for its share of the costs to upgrade systems, software licenses and other configuration activities. The Implementation Agreement was approved by the FERC in June 2014.
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. 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. The Company 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. Refer to "Liquidity and Capital Resources" for discussion of the Company's forecasted environmental-related capital expenditures. The discussion below contains material developments to those matters disclosed in Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.
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 State Implementation Plans ("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.
Mercury and Air Toxics Standards
The Clean Air Mercury Rule ("CAMR"), issued by the EPA in March 2005, was the United States' first attempt to regulate mercury emissions from coal-fueled generating facilities through the use of a market-based cap-and-trade system. The CAMR, which mandated emissions reductions of approximately 70% by 2018, was overturned by the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") in February 2008. In March 2011, the EPA proposed a new rule that would require coal-fueled generating facilities to reduce mercury emissions and other hazardous air pollutants through the establishment of "Maximum Achievable Control Technology" standards rather than a cap-and-trade system. The final rule, Mercury and Air Toxics Standards ("MATS"), was published in the Federal Register in February 2012, with an effective date of April 16, 2012, and requires that new and existing coal-fueled generating facilities achieve emission standards for mercury, acid gases and other non-mercury hazardous air pollutants. Existing sources are required to comply with the new standards by April 16, 2015. Individual sources may be granted up to one additional year, at the discretion of the Title V permitting authority, to complete installation of controls or for transmission system reliability reasons. The Company believes that its emissions reduction projects completed to date or currently permitted or planned for installation, including scrubbers, baghouses and electrostatic precipitators, are consistent with the EPA's MATS and will support the Company's ability to comply with the final rule's standards for acid gases and non-mercury metallic hazardous air pollutants. The Company will be required to take additional actions to reduce mercury emissions through the installation of controls or use of sorbent injection at certain of its coal-fueled generating facilities and otherwise comply with the final rule's standards, which may include retiring certain units.
Incremental costs to install and maintain emissions control equipment at the Company's coal-fueled generating facilities and any requirement to shut down what have traditionally been low cost coal-fueled generating facilities will likely increase the cost of providing service to customers. In addition, numerous lawsuits were filed against the MATS in the D.C. Circuit. In April 2014, the D.C. Circuit upheld the MATS requirements.
Climate Change
In June 2014, the EPA released proposed regulations to address greenhouse gas 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 four building blocks that it determined were the "Best System of Emission Reduction." The four building blocks include: (a) a 6% heat rate improvement from coal-fueled generating facilities; (b) increased utilization of existing combined-cycle natural gas-fueled generating facilities to 70%; (c) increased deployment of renewable and non-carbon generating resources; and, (d) increased energy efficiency. Under the EPA's proposal, Nevada may utilize any measure to achieve the specified emission reduction goals, with an initial implementation period of 2020-2029 and the final goal to be achieved by 2030. When fully implemented, the proposal is expected to reduce carbon dioxide emissions in the power sector to 30% below 2005 levels by 2030. The EPA is taking comment on its proposal until October 16, 2014 and is scheduled to issue final rules in June 2015. States are required to submit implementation plans by June 2016, but they may request an extension to June 2017, or June 2018 if they plan to participate in a regional compliance program. The impacts of the proposal on the Company cannot be determined until the EPA finalizes the proposal and Nevada develops its implementation plan. The Company has historically pursued cost-effective projects, including plant efficiency improvements, increased diversification of its generating fleet to include deployment of renewable and lower carbon generating resources, and advancement of customer energy efficiency programs.
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. In July 2004, the EPA established significant new technology-based performance standards for existing electricity generating facilities that take in more than 50 million gallons of water per day. These rules were aimed at minimizing the adverse environmental impacts of cooling water intake structures by reducing the number of aquatic organisms lost as a result of water withdrawals. In response to a legal challenge to the rule, in January 2007, the United States Court of Appeals for the Second Circuit ("Second Circuit") remanded almost all aspects of the rule to the EPA, without addressing whether companies with cooling water intake structures were required to comply with these requirements. On appeal from the Second Circuit, in April 2009, the United States Supreme Court ruled that the EPA permissibly relied on a cost-benefit analysis in setting the national performance standards regarding "best technology available for minimizing adverse environmental impact" at cooling water intake structures and in providing for cost-benefit variances from those standards as part of the §316(b) Clean Water Act Phase II regulations. The United States Supreme Court remanded the case back to the Second Circuit to conduct further proceedings consistent with its opinion.
In June 2013, the EPA published proposed effluent limitation guidelines and standards for the steam electric power generating sector. 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 have changed the effluent discharged from coal- and natural gas-fueled generating facilities. While the EPA expected the final rule to be published in May 2014, the final rule is now scheduled for release by September 30, 2015. It is likely that the new guidelines will impose more stringent limits on wastewater discharges from coal-fueled generating facilities and ash and scrubber ponds. However, until the revised guidelines are finalized, the Company cannot predict the impact on its generating facilities.
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 NPC Credit Agreement,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. As currently proposed, a variety of projects that otherwise would have qualified for streamlined permitting processes under nationwide or regional general permits will be required to undergo more lengthy and costly individual permit procedures based on an extension of waters that will be deemed jurisdictional. The public comment period has been extended on the potential exposureproposal to October 20, 2014. Until the rule is finalized, the Company cannot determine whether projects that include construction and demolition will face more complex permitting issues, higher costs, or increased requirements for compensatory mitigation.
Collateral and Contingent Features
Debt of NPC to collateral calls under various contracts and the ability of NPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for NPC’s debt. On May 22, 2013, Moody’s upgraded NPC’s ratings. On May 30, 2013, Fitch and S&P upgraded NPC’s rating outlook from Stable to Positive. NPC’s senior secured debtCompany is rated investment grade by three NRSRO’s: Fitch, Moody’s and S&P. The senior secured debtcredit rating agencies. Assigned credit ratings are as follows:
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| | | | | | | |
| | | Rating Agency |
| | | Fitch(1)
| | Moody’s(2)
| | S&P(3)
|
NPC | Sr. Secured Debt | | BBB+* | | A3* | | BBB+* |
| |
(1)
| Fitch’s lowest level of “investment grade” credit rating is BBB-. |
| |
(2)
| Moody’s lowest level of “investment grade” credit rating is Baa3. |
| |
(3)
| S&P’s lowest level of “investment grade” credit rating is BBB-. |
Fitch’s and S&P’sbased on each rating outlooksagency's assessment of the Company's ability to, in general, meet the obligations of its issued debt. The credit ratings are Positive, while Moody’s rating outlook is Stable for NPC.
A security rating is not a recommendation to buy, sell or hold securities. Securitysecurities, and there is no assurance that a particular credit rating will continue for any given period of time.
The Company has no credit rating downgrade triggers that would accelerate the maturity dates of outstanding debt, and a change in ratings is not an event of default under the applicable debt instruments. The Company's secured revolving credit facility does not require the maintenance of a minimum credit rating level in order to draw upon its availability. However, commitment fees and interest rates under the credit facility are subjecttied to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigningcredit ratings and accordingly, eachincrease or decrease when the ratings change. A ratings downgrade could also increase the future cost of commercial paper, short- and long-term debt issuances or new credit facilities.
In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for unsecured debt as reported by one or more of the three recognized credit rating should be evaluatedagencies. These agreements may either specifically provide rights to demand cash or other security in the contextevent of a credit rating downgrade ("credit-risk-related contingent features") or provide the applicable methodology, independentlyright for counterparties to demand "adequate assurance," in the event of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP agreement is posted on the WSPP website.
Under these contracts, a material adverse change which includes ain creditworthiness. These rights can vary by contract and by counterparty. As of June 30, 2014, credit ratings from the three recognized credit rating downgrade, in NPC may allow the counterparty to requestagencies were investment grade. If all credit-risk-related contingent features or adequate financial assurance which, if not provided within three business days, could cause a default. Most contracts and confirmationsprovisions for purchased power havethese agreements had been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market valuetriggered as of SeptemberJune 30, 2013 for all suppliers continuing to provide power under a WSPP agreement2014, the Company would approximate a $49.7 million payment or obligation to NPC. These contracts qualify for the normal purchases and normal sales scope exception under the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms, and as such, do not carry forward mark-to-market exposure.
Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has a transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of September 30, 2013, the maximum amount$69 million of additional collateral. The Company's collateral NPC would be requiredrequirements could fluctuate considerably due to post under these contractsmarket price volatility, changes in the eventcredit ratings, changes in legislation or regulation, or other factors. Refer to Note 7 of credit rating downgrades was approximately $87.2 million. Of this amount, approximately $26 million would be required if NPC’s Senior Unsecured ratings are rated below BB (S&P) or Ba3 (Moody’s) and an additional amount of approximately $61.2 million would be required if NPC’s Senior Unsecured and Senior Secured ratings, both are downgraded to below investment grade.
Financial Gas Hedges
NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt, of the Notes to Consolidated Financial Statements in the 2012Item 1 of this Form 10-K, NPC’s Financing Transactions, the availability under the NPC’s revolving credit facility is reduced10-Q for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowings of NPC. If deemed prudent, NPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.
Cross Default Provisions
None of the financing agreements of NPC contains a cross default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of their respective financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of
control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of NPC. As a result, NPC will be required to offer to purchase approximately $3.1 billion of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, NPC is unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under NPC’s debt securities is approximately 6.42%. To the extent that debt securities are tendered pursuant to the required tender offers, NPC intends to fund the purchases using a combination of internal funds, its revolving credit facility or the issuance of long-term debt. Furthermore, NPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, NPC amended its revolving credit facility to permit the MidAmerican Merger.
SIERRA PACIFIC POWER COMPANY
RESULTS OF OPERATIONS
SPPC recognized net income of $29.3 million for the three months ended September 30, 2013, compared to net income of $34.4 million for the same period in 2012. During the nine months ended September 30, 2013, SPPC recognized net income of approximately $61.9 million compared to $65.8 million for the same period in 2012.
During the nine months ended September 30, 2013, SPPC paid dividends to NVE of $40.0 million. On November 6, 2013, SPPC declared a dividend of $37.0 million to NVE.
Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.
SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less energy costs, energy efficiency program costs and regulatory disallowances, provides a measure of income available to support the other operating expenses of SPPC. For reconciliation to operating income, see Note 3, Segment Information, of the Condensed Notes to Financial Statements. Gross margin changes are primarily due to general base rate adjustments (which are required by statute to be filed every three years).
The components of gross margin were (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Operating Revenues: | | | | | |
| | | | | | | | |
| | |
| | Electric | $ | 213,463 |
| | $ | 212,073 |
| | $ | 1,390 |
| | 0.7 | % | | $ | 560,392 |
| | $ | 549,886 |
| | $ | 10,506 |
| | 1.9 | % |
| | Gas | 13,543 |
| | 12,077 |
| | 1,466 |
| | 12.1 | % | | 73,480 |
| | 77,543 |
| | (4,063 | ) | | (5.2 | )% |
| | | $ | 227,006 |
| | $ | 224,150 |
| | $ | 2,856 |
| | 1.3 | % | | $ | 633,872 |
| | $ | 627,429 |
| | $ | 6,443 |
| | 1.0 | % |
| Energy Costs: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | Fuel for power generation | 54,827 |
| | 47,324 |
| | 7,503 |
| | 15.9 | % | | 141,277 |
| | 115,137 |
| | 26,140 |
| | 22.7 | % |
| | Purchased power | 33,388 |
| | 33,999 |
| | (611 | ) | | (1.8 | )% | | 114,755 |
| | 98,400 |
| | 16,355 |
| | 16.6 | % |
| | Gas purchased for resale | 7,383 |
| | 5,382 |
| | 2,001 |
| | 37.2 | % | | 62,277 |
| | 46,491 |
| | 15,786 |
| | 34.0 | % |
| | Deferred energy - electric - net | (7,925 | ) | | (5,498 | ) | | (2,427 | ) | | 44.1 | % | | (44,223 | ) | | (13,854 | ) | | (30,369 | ) | | 219.2 | % |
| | Deferred energy - gas - net | (1,964 | ) | | (853 | ) | | (1,111 | ) | | 130.2 | % | | (22,315 | ) | | (970 | ) | | (21,345 | ) | | 2,201 | % |
| Energy efficiency program costs | 2,044 |
| | 4,092 |
| | (2,048 | ) | | (50.0 | )% | | 5,679 |
| | 11,143 |
| | (5,464 | ) | | (49.0 | )% |
| Regulatory disallowance | 5,469 |
| | — |
| | 5,469 |
| | N/A |
| | 5,469 |
| | — |
| | 5,469 |
| | N/A |
|
| | Total Costs | $ | 93,222 |
| | $ | 84,446 |
| | $ | 8,776 |
| | 10.4 | % | | $ | 262,919 |
| | $ | 256,347 |
| | $ | 6,572 |
| | 2.6 | % |
| | | | | | | | | | | | | | | | | |
| | Cost by Segment: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | Electric | $ | 87,803 |
| | $ | 79,917 |
| | $ | 7,886 |
| | 9.9 | % | | $ | 222,957 |
| | $ | 210,826 |
| | $ | 12,131 |
| | 5.8 | % |
| | Gas | 5,419 |
| | 4,529 |
| | 890 |
| | 19.7 | % | | 39,962 |
| | 45,521 |
| | (5,559 | ) | | (12.2 | )% |
| | | $ | 93,222 |
| | $ | 84,446 |
| | $ | 8,776 |
| | 10.4 | % | | $ | 262,919 |
| | $ | 256,347 |
| | $ | 6,572 |
| | 2.6 | % |
| | | | | | | | | | | | | | | | | |
| | Gross Margin by Segment: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | Electric | $ | 125,660 |
| | $ | 132,156 |
| | $ | (6,496 | ) | | (4.9 | )% | | $ | 337,435 |
| | $ | 339,060 |
| | $ | (1,625 | ) | | (0.5 | )% |
| | Gas | 8,124 |
| | 7,548 |
| | 576 |
| | 7.6 | % | | 33,518 |
| | 32,022 |
| | 1,496 |
| | 4.7 | % |
| | Gross Margin | $ | 133,784 |
| | $ | 139,704 |
| | $ | (5,920 | ) | | (4.2 | )% | | $ | 370,953 |
| | $ | 371,082 |
| | $ | (129 | ) | | — | % |
Electric gross margin decreased for the nine months ended September 30, 2013 compared to the same period in 2012. The decrease is primarily due to the disallowance of EEIR revenue and carrying charge of $5.5 million (pre-tax) and a provision of $4.0 million (pre-tax) recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in NPC’s EEIR filing, as well as, SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributingCompany's collateral requirements specific to the increase was customer growth and usage. The decrease was largely offset by an increase in customer usage, customer growth and an increase in sales of $3.8 million to Cal Peco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).
Gas gross margin for the three and nine months ended September 30, 2013, compared to the same periods in 2012 increased slightly primarily due to weather.
HDDs and CDDs
MWh usage may be affected by the change in HDDs or CDDs in a given period. A degree day indicates how far that day's average temperature departed from 65° F. HDDs measure heating energy demand and indicate how far the average temperature fell below 65° F. CDDs measure cooling energy demand and indicate how far the temperature averaged above 65° F. For example, if a location had a mean temperature of 60° F on day 1 and 80° F on day 2, there would be 5 HDDs (65 minus 60) and 0 CDDs for day 1. In contrast, there would be 0 HDDs and 15 CDDs (80 minus 65) for day 2.
The following table shows the HDDs and CDDs within SPPC’s service territory:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| SPPC | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Heating | 85 |
| | 1 |
| | 84 |
| | N/A | | 2,859 |
| | 2,677 |
| | 182 |
| | 6.8 | % |
| Cooling | 914 |
| | 1,020 |
| | (106 | ) | | (10.4 | )% | | 1,177 |
| | 1,255 |
| | (78 | ) | | (6.2 | )% |
Company's derivative contracts.
The causes for significant changes in specific lines comprising the results of operations for SPPC for the respective periods are provided below (dollars in thousands except for amounts per unit):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenue | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| Operating Revenues: | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| | Residential | $ | 68,808 |
| | $ | 68,677 |
| | $ | 131 |
| | 0.2 | % | | $ | 184,309 |
| | $ | 180,953 |
| | $ | 3,356 |
| | 1.9 | % |
| | Commercial | 78,080 |
| | 78,409 |
| | (329 | ) | | (0.4 | )% | | 201,761 |
| | 200,912 |
| | 849 |
| | 0.4 | % |
| | Industrial | 48,722 |
| | 48,541 |
| | 181 |
| | 0.4 | % | | 122,082 |
| | 120,234 |
| | 1,848 |
| | 1.5 | % |
| | | Retail Revenues | 195,610 |
| | 195,627 |
| | (17 | ) | | — | % | | 508,152 |
| | 502,099 |
| | 6,053 |
| | 1.2 | % |
| | Other | 17,853 |
| | 16,446 |
| | 1,407 |
| | 8.6 | % | | 52,240 |
| | 47,787 |
| | 4,453 |
| | 9.3 | % |
| | | Total Operating Revenues | $ | 213,463 |
| | $ | 212,073 |
| | $ | 1,390 |
| | 0.7 | % | | $ | 560,392 |
| | $ | 549,886 |
| | $ | 10,506 |
| | 1.9 | % |
| | | | | | | | | | | | | | | | | | |
| Retail sales in thousands of MWhs | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Residential | 671 |
| | 667 |
| | 4 |
| | 0.6 | % | | 1,794 |
| | 1,737 |
| | 57 |
| | 3.3 | % |
| | Commercial | 851 |
| | 849 |
| | 2 |
| | 0.2 | % | | 2,268 |
| | 2,233 |
| | 35 |
| | 1.6 | % |
| | Industrial | 701 |
| | 686 |
| | 15 |
| | 2.2 | % | | 2,092 |
| | 2,005 |
| | 87 |
| | 4.3 | % |
| Retail sales in thousands of MWhs | 2,223 |
| | 2,202 |
| | 21 |
| | 1.0 | % | | 6,154 |
| | 5,975 |
| | 179 |
| | 3.0 | % |
| | | | | | | | | | | | | | | | | | |
| Average retail revenue per MWh | $ | 87.99 |
| | $ | 88.84 |
| | $ | (0.85 | ) | | (1.0 | )% | | $ | 82.57 |
| | $ | 84.03 |
| | $ | (1.46 | ) | | (1.7 | )% |
Retail revenue decreased for the three months ended September 30, 2013, as compared to the same period in 2012, primarily due to a provision of $4.0 million recorded against 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements for further discussion of the EEIR disallowance. Also contributing to the decrease was $2.0 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013. These decreases were largely offset by $5.2 million of rate increases as a result of various BTER and DEAA quarterly and a $1.1 million increase from customer growth. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K.
For the three months ended September 30, 2013, the average number of residential and commercial customers increased 0.7% and 2.5%, respectively, while industrial customers remained the same compared to the same period in 2012.
Electric operating revenues - Other increased for the three months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in energy sales of $1.5 million to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K).
Retail revenue increased for the nine months ended September 30, 2013, as compared to the same period in 2012, due to a $7.6 million increase in customer usage primarily due to an unusually cold January and unusually hot June and July, $4.8 million in rate increases due to various BTER and DEAA quarterly updates (see Note 4, Regulatory Actions of the Notes to Financial Statements) and a $1.8 million increase from customer growth. These increases were partially offset by $5.4 million of rate decreases in EEPR due to SPPC’s annual Deferred Energy cases effective January 1, 2013 and a provision of $4.0 million for 2013 EEIR revenues as a result of the precedent set by the PUCN’s ruling in SPPC’s EEIR filing and SPPC’s estimated rate of return in excess of its allowed rate of return as of September 30, 2013. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements).
For the nine months ended September 30, 2013, the average number of residential, commercial, and industrial customers increased 0.7%, 2.1%, and 1.8%, respectively, compared to the same period in 2012.
Electric operating revenues - Other increased for the nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to a $3.8 million increase in energy sales to CalPeco under a five year agreement as a condition to the sale of SPPC’s California Assets which occurred on January 1, 2011 (see Note 15, Assets Held for Sale, of the Notes to Financial Statements in the 2012 Form 10-K) and $0.7 million increase in miscellaneous revenues.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Operating Revenue | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Gas Operating Revenues: | | | | | | | | | | | | | | | |
| | Residential | $ | 7,750 |
| | $ | 7,306 |
| | $ | 444 |
| | 6.1 | % | | $ | 39,781 |
| | $ | 45,104 |
| | $ | (5,323 | ) | | (11.8 | )% |
| | Commercial | 2,680 |
| | 2,583 |
| | 97 |
| | 3.8 | % | | 14,657 |
| | 17,961 |
| | (3,304 | ) | | (18.4 | )% |
| | Industrial | 1,041 |
| | 906 |
| | 135 |
| | 14.9 | % | | 4,591 |
| | 5,115 |
| | (524 | ) | | (10.2 | )% |
| | Retail Revenues | 11,471 |
| | 10,795 |
| | 676 |
| | 6.3 | % | | 59,029 |
| | 68,180 |
| | (9,151 | ) | | (13.4 | )% |
| | Wholesale Revenues | 1,359 |
| | 563 |
| | 796 |
| | 141.4 | % | | 12,149 |
| | 7,033 |
| | 5,116 |
| | 72.7 | % |
| | Miscellaneous | 713 |
| | 719 |
| | (6 | ) | | (0.8 | )% | | 2,302 |
| | 2,330 |
| | (28 | ) | | (1.2 | )% |
| | Total Gas Revenues | $ | 13,543 |
| | $ | 12,077 |
| | $ | 1,466 |
| | 12.1 | % | | $ | 73,480 |
| | $ | 77,543 |
| | $ | (4,063 | ) | | (5.2 | )% |
| | | | | | | | | | | | | | | | | |
| Retail sales in thousands of Dths | |
| | |
| | |
| | | | |
| | |
| | | | |
| | Residential | 698 |
| | 642 |
| | 56 |
| | 8.7 | % | | 6,039 |
| | 5,613 |
| | 426 |
| | 7.6 | % |
| | Commercial | 400 |
| | 374 |
| | 26 |
| | 7.0 | % | | 3,086 |
| | 2,939 |
| | 147 |
| | 5.0 | % |
| | Industrial | 190 |
| | 153 |
| | 37 |
| | 24.2 | % | | 986 |
| | 876 |
| | 110 |
| | 12.6 | % |
| Retail sales in thousands of Dths | 1,288 |
| | 1,169 |
| | 119 |
| | 10.2 | % | | 10,111 |
| | 9,428 |
| | 683 |
| | 7.2 | % |
| | | | | | | | | | | | | | | | | |
| Average retail revenue per Dth | $ | 8.91 |
| | $ | 9.23 |
| | $ | (0.32 | ) | | (3.5 | )% | | $ | 5.84 |
| | $ | 7.23 |
| | $ | (1.39 | ) | | (19.2 | )% |
SPPC’s retail gas revenues increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to a $565 thousand increase in usage, due to an increase in HDDs as shown in the table above.
SPPC’s retail gas revenues decreased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $12.4 million decrease in retail rates as a result of SPPC’s annual Deferred Energy cases, effective October 1, 2012, and various BTER and DEAA quarterly updates (see Note 4, Regulatory Actions of the Notes to Financial Statements in the 2012 Form 10-K). The decrease was partially offset by a $2.8 million increase in customer usage, due to an increase in HDDs as shown in the table above.
Wholesale revenues increased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to an increase in natural gas prices.
Energy Costs
Energy Costs include purchased power and fuel for generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of purchased power versus fuel for generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:
weather
plant outages
total system demand
resource constraints
transmission constraints
gas transportation constraints
natural gas constraints
long-term contracts
mandated power purchases
generation efficiency; and
volatility of commodity prices
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Energy Costs: | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Fuel for power generation | $ | 54,828 |
| | $ | 47,324 |
| | $ | 7,504 |
| | 15.9 | % | | $ | 141,277 |
| | $ | 115,137 |
| | $ | 26,140 |
| | 22.7 | % |
| | Purchased power | 33,388 |
| | 33,999 |
| | (611 | ) | | (1.8 | )% | | 114,755 |
| | 98,400 |
| | 16,355 |
| | 16.6 | % |
| Total Energy Costs | $ | 88,216 |
| | $ | 81,323 |
| | $ | 6,893 |
| | 8.5 | % | | $ | 256,032 |
| | $ | 213,537 |
| | $ | 42,495 |
| | 19.9 | % |
| | | | | | | | | | | | | | | | | |
| MWhs | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | MWhs Generated (in thousands) | 1,580 |
| | 1,512 |
| | 68 |
| | 4.5 | % | | 3,829 |
| | 3,829 |
| | — |
| | — | % |
| | Purchased Power (in thousands) | 916 |
| | 971 |
| | (55 | ) | | (5.7 | )% | | 3,169 |
| | 3,031 |
| | 138 |
| | 4.6 | % |
| Total MWhs | 2,496 |
| | 2,483 |
| | 13 |
| | 0.5 | % | | 6,998 |
| | 6,860 |
| | 138 |
| | 2.0 | % |
| | | | | | | | | | | | | | | | | |
| Average cost per MWh | |
| | |
| | |
| | |
| | |
| | |
| | | | |
|
| | Average fuel cost per MWh of Generated Power | $ | 34.70 |
| | $ | 31.30 |
| | $ | 3.40 |
| | 10.9 | % | | $ | 36.90 |
| | $ | 30.07 |
| | $ | 6.83 |
| | 22.7 | % |
| | Average cost per MWh of Purchased Power | $ | 36.45 |
| | $ | 35.01 |
| | $ | 1.44 |
| | 4.1 | % | | $ | 36.21 |
| | $ | 32.46 |
| | $ | 3.75 |
| | 11.5 | % |
| | Average total cost per MWh | $ | 35.34 |
| | $ | 32.75 |
| | $ | 2.59 |
| | 7.9 | % | | $ | 36.59 |
| | $ | 31.13 |
| | $ | 5.46 |
| | 17.5 | % |
Energy costs and average cost per MWh increased for the three and nine months ended September 30, 2013, compared to the same period in 2012 primarily due to higher natural gas prices.
Fuel for generation costs increased for the three months ended September 30, 2013, compared to the same period in 2012. Contributing to the increase was $5.2 million due to higher natural gas and coal prices. Also contributing to the increase was $1.2 million and $1.1 million in volume increases of coal and natural gas used for generation, respectively.
Fuel for generation costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was $26.8 million in higher natural gas prices. Higher costs were partially offset by a decrease in natural gas volume of approximately $13.0 million and an increase of $12.0 million in coal volume, respectively.
Purchased power costs decreased for the three months ended September 30, 2013 compared to the same period in 2012. Approximately $1.8 million of the decrease is primarily due to decreased volume. The decrease was partially offset by an increase in the price of purchased power of $1.2 million.
Purchased power costs increased for the nine months ended September 30, 2013 compared to the same period in 2012. Contributing to the increase was an increase in price of $10.9 million and $1.5 million for non-renewable and renewable energy, respectively. Approximately $4.0 million of the increase was due to an increase in volume of power purchased.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Purchased for Resale |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Gas purchased for resale | $ | 7,383 |
| | $ | 5,382 |
| | $ | 2,001 |
| | 37.2 | % | | $ | 62,277 |
| | $ | 46,491 |
| | $ | 15,786 |
| | 34.0 | % |
| Gas purchased for resale (in thousands of Dths) | 1,688 |
| | 1,349 |
| | 339 |
| | 25.1 | % | | 13,614 |
| | 12,636 |
| | 978 |
| | 7.7 | % |
| Average cost per Dth | $ | 4.37 |
| | $ | 3.99 |
| | $ | 0.38 |
| | 9.5 | % | | $ | 4.57 |
| | $ | 3.68 |
| | $ | 0.89 |
| | 24.2 | % |
Gas purchased for resale increased for the three months ended September 30, 2013, compared to the same period in 2012. Approximately $1.5 million of the increase is due to an increase in volume and approximately $0.5 million is due to higher natural gas prices. Volume increased primarily due to an increase in HDDs as shown in the table above.
Gas purchased for resale increased for the nine months ended September 30, 2013, compared to the same period in 2012. Approximately $11.3 million of the increase is due higher natural gas prices and approximately $4.5 million is due to an increase in volume. Volume increased primarily due to an increase in HDDs as shown in the table above.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred Energy |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Deferred energy - electric - net | $ | (7,925 | ) | | $ | (5,498 | ) | | $ | (2,427 | ) | | 44.1% | | $ | (44,223 | ) | | $ | (13,854 | ) | | $ | (30,369 | ) | | 219.2% |
| Deferred energy - gas - net | $ | (1,964 | ) | | $ | (853 | ) | | $ | (1,111 | ) | | 130.2% | | $ | (22,315 | ) | | $ | (970 | ) | | $ | (21,345 | ) | | 2,200.5% |
| | $ | (9,889 | ) | | $ | (6,351 | ) | | $ | (3,538 | ) | | 55.7% | | $ | (66,538 | ) | | $ | (14,824 | ) | | $ | (51,714 | ) | | 348.9% |
Deferred energy - electric for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(4.5) million and $(19.3) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(3.4) million in 2013 and over-collections of $13.8 million in 2012.
Deferred energy - electric for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(23.7) million and $(65.0) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - electric balance are under-collections of amounts recoverable in rates of $(20.5) million in 2013 and over-collections of $51.2 million in 2012.
Deferred energy - gas for the three months ended September 30, 2013 and 2012 include amortization of deferred energy of $(1.9) million and $(2.2) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - gas balance for 2012 were over-collections recoverable in rates of $1.3 million. Under collections for the three months ended September 30, 2013 are immaterial.
Deferred energy - gas for the nine months ended September 30, 2013 and 2012 include amortization of deferred energy of $(19.0) million and $(19.9) million, respectively, which primarily represents cash refunds to our customers for previous over-collections. Further contributing to the deferred energy - gas balance are under-collections of amounts recoverable in rates of $(3.3) million in 2013 and over-collections of $18.9 million in 2012.
Deferred energy represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely, to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further detail of deferred energy balances.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Operating Expenses | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Energy efficiency program costs | $ | 2,044 |
| | $ | 4,092 |
| | $ | (2,048 | ) | | (50.0)% | | $ | 5,679 |
| | $ | 11,143 |
| | $ | (5,464 | ) | | (49.0)% |
| Regulatory disallowance | $ | 5,469 |
| | $ | — |
| | $ | 5,469 |
| | N/A | | $ | 5,469 |
| | $ | — |
| | $ | 5,469 |
| | N/A |
| Merger-related costs | $ | 2,008 |
| | $ | — |
| | $ | 2,008 |
| | N/A | | $ | 5,528 |
| | $ | — |
| | $ | 5,528 |
| | N/A |
| Other operating expenses | $ | 34,394 |
| | $ | 34,128 |
| | $ | 266 |
| | 0.8% | | $ | 106,455 |
| | $ | 104,214 |
| | $ | 2,241 |
| | 2.2% |
| Maintenance | $ | 5,968 |
| | $ | 6,481 |
| | $ | (513 | ) | | (7.9)% | | $ | 20,956 |
| | $ | 23,596 |
| | $ | (2,640 | ) | | (11.2)% |
| Depreciation and amortization | $ | 27,952 |
| | $ | 27,537 |
| | $ | 415 |
| | 1.5% | | $ | 83,772 |
| | $ | 80,594 |
| | $ | 3,178 |
| | 3.9% |
For the three and nine months ended September 30, 2013, energy efficiency program costs decreased compared to the same periods in 2012, primarily due to lower EEPR base and amortization rates effective January 1, 2013. Reference Note 3, Regulatory Actions, of the Notes to the Financial Statements in the 2012 Form 10-K for more information on EEPR base and amortizations rate filings. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further information on EEPR rates effective October 2013.
The regulatory disallowance consists of $5.5 million related to EEIR revenues earned in 2012 (including carrying charges) in excess of SPPC’s authorized ROR. See Note 4, Regulatory Actions, of the Condensed Notes to Financial Statements.
As discussed further in Note 2, Merger-Related Activities, of the Condensed Notes to Financial Statements, in May 2013, NVE and the Utilities entered into the MidAmerican Merger Agreement. As a result of the MidAmerican Merger, SPPC incurred $2.0 million and $5.5 million in merger-related fees and stock compensation costs for the three and nine months ended September 30, 2013, respectively. Stock compensation costs increased primarily due to the increase in the average price per share of NVE common stock used to value the liability for stock compensation upon announcement of the MidAmerican Merger. SPPC expects to incur additional merger-related fees upon consummation of the MidAmerican Merger.
Other operating expense increased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.7 million increase in regulatory expenses. The increase was offset by a $0.7 million decrease due to a 2012 claim settlement.
Other operating expense increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to $2.6 million increase in regulatory expenses, $0.9 million reduction in capitalized costs as a result of a decrease in construction activity. The increase was partially offset by a $0.9 million decrease in pension and benefit costs.
Maintenance expense decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to $0.2 million of 2012 major outage at the Tracy Generating Station and $0.2 million in 2012 maintenance at the Ft. Churchill Generating Station.New Accounting Pronouncements
Maintenance expense decreased forFor a discussion of new accounting pronouncements affecting the nine months ended September 30, 2013, comparedCompany, refer to the same period in 2012, primarily dueNote 2 of Notes to $3.7 million of planned major outages in 2012 at the Tracy, Valmy and Ft. Churchill Generating Stations, and $0.3 million of 2012 transmission poles maintenance expenses, offset by $1.5 million of 2013 turbine maintenance at the Tracy Generating Station.
Depreciation and amortization increased for the three and nine months ended September 30, 2013, compared to the same period in 2012, primarily due to general increases in plant-in-service.
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| | | | | | | | | | | | | | | | | | | | | |
| Interest Expense | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| Interest expense | | | | | | | | | | | | | | | |
| (net of AFUDC-debt: $437, $448, $1,007 and $1,458) | (15,122 | ) | | (15,298 | ) | | 176 |
| | (1.2)% | | (46,020 | ) | | (47,650 | ) | | 1,630 |
| | (3.4)% |
Interest expense is comparable to prior period for the three months ended September 30, 2013.
Interest expense decreased $1.6 million for the nine months ended September 30, 2013, as compared to the same period in 2012, primarily due to decreased debt amortization expense of $1.6 million. See Note 6, Long-Term Debt of the Notes toConsolidated Financial Statements in 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 2012future. 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 the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for additional informationthe year ended December 31, 2013. There have been no significant changes in the Company's assumptions regarding long-term debt.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense) |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | Variance | | % Change | | 2013 | | 2012 | | Variance | | % Change |
| | | | | | | | | | | | | | | | |
| Interest income (expense) on regulatory items | $ | (87 | ) | | $ | (401 | ) | | $ | 314 |
| | (78.3 | )% | | $ | 53 |
| | $ | (715 | ) | | $ | 768 |
| | (107.4 | )% |
| AFUDC-equity | $ | 632 |
| | $ | 582 |
| | $ | 50 |
| | 8.6 | % | | $ | 1,579 |
| | $ | 1,843 |
| | $ | (264 | ) | | (14.3 | )% |
| Other income | $ | 983 |
| | $ | 1,399 |
| | $ | (416 | ) | | (29.7 | )% | | $ | 4,641 |
| | $ | 4,181 |
| | $ | 460 |
| | 11.0 | % |
| Other expense | $ | (982 | ) | | $ | (998 | ) | | $ | 16 |
| | (1.6 | )% | | $ | (3,803 | ) | | $ | (3,609 | ) | | $ | (194 | ) | | 5.4 | % |
Interest income (expense) on regulatory items decreased for the three and nine months ended September 30, 2013, compared to the same periods in 2012, primarily due to $1.2 million and $2.9 million, respectively, of decreases in interest on deferred energy as a result of lower over-collected balances in 2013, offset by $0.7 million and $1.7 million, respectively, of decreases in carrying charges on solar conservation programs and by $0.2 million and $0.4 million, respectively, of decreases in interest income due to lower regulatory asset balances. See Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details of deferred energy balances. critical accounting estimates since December 31, 2013.
AFUDC-equity increased slightly for the three months ended September 30, 2013 compared to the same period in 2012, primarily due to an increase in base construction projects. AFUDC-equity decreased slightly for the nine months ended September 30, 2013 compared to the same period in 2012, primarily due to the completion of the NV Energize.
Other income decreased for the three months ended September 30, 2013, compared to the same period in 2012, primarily due to higher refunds in 2012, offset by several items, none of which were individually material.
Other income increased for the nine months ended September 30, 2013, compared to the same period in 2012, primarily due to a $1.9 million insurance settlement in 2013, offset by $1.1 million settlement with CA ISO in 2011 recognized in 2012, and higher refunds in 2012. See Note 3, Regulatory Actions, FERC Matters, in the Notes to Financial Statements in the 2012 Form 10-K.
Other expense decreased for the three months ended and increased for the nine months ended September 30, 2013, compared to the same period in 2012, by several items, none of which are individually material.
ANALYSIS OF CASH FLOWS
Cash From Operating Activities
SPPC’s net cash flows from operating activities were $156.9 million and $146.9 million for the nine months ended September 30, 2013 and 2012, respectively.
The increase in cash from operating activities was primarily due to:
Reduced coal purchases of $23.4 million;
Reduced spend on renewable programs of $19.6 million;
Receipt of approximately $9.0 million in insurance proceeds related to a previous claim;
Timing of payments for property taxes of $4.6 million; and
Timing of payments for energy costs of $4.5 million.
The increase in cash from operating activities was partially offset by:
Under-collection of energy costs resulting from adjustments to BTER rates and higher energy costs of $92.4 million, offset by reduced refunds to customers of $42 million;
Reduced EEPR collections of $5.8 million; and
Increased funding of the retirement plan in 2013 of $2.9 million.
Cash Used By Investing Activities
SPPC’s net cash used by investing activities were $(90.4) million and $(127.8) million for the nine months ended September 30, 2013 and 2012, respectively.
The decrease in cash used by investing activities was primarily due to:
Reduced capital expenditure for the NV Energize project of $91.0 million, partially offset by reduced CIAC received under the American Recovery and Reinvestment Act of 2009 of $17.4 million.
Cash Used By Financing Activities
SPPC’s net cash flows used by financing activities were $(43.2) million and $(22.6) million for the nine months ended September 30, 2013 and 2012, respectively.
The increase in cash used by financing was primarily due to:
Maturity of $250 million of 5.45% General and Refunding Mortgage Notes, Series Q debt ; and
Increased dividends to NVE of $20 million.
The increase in cash used by financing was partially offset by:
The issuance of $250 million of 3.375% General and Refunding Mortgage Notes, Series T debt.
SPPC paid dividends of $40 million and $20 million to NVE during the nine months ended September 30, 2013 and 2012, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Overall Liquidity
SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Another significant use of cash is the refunding of previously over-collected amounts from customers. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.
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| | | |
| Available Liquidity as of September 30, 2013 (in millions) |
| | SPPC |
| Cash and Cash Equivalents | $ | 84.1 |
|
| Balance available on Revolving Credit Facility(1) | 243.7 |
|
| | $ | 327.8 |
|
| |
(1)Item 3.
| As of November 6, 2013, SPPC had approximately $244.0 million available under its revolving credit facility which includes reductions for letters of credits.Quantitative and Qualitative Disclosures About Market Risk |
SPPC attempts to maintain its cashFor quantitative and cash equivalents in highly liquid investments, such as U.S. Treasury Bills and bank deposits. In addition to cash on hand, SPPC may use its revolving credit facility in order to meet its liquidity needs. Alternatively, depending onqualitative disclosures about market risk affecting the usageCompany, see Item 7A of the revolving credit facility, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.
SPPC has no further debt maturitiesCompany's Annual Report on Form 10-K for the remainder ofyear ended December 31, 2013. As of November 6, 2013, SPPC has no borrowings on its revolving credit facility, not including letters of credit. In 2012, SPPC’s credit ratings on its senior secured debt remained at investment grade (see Credit Ratings below). In 2012, SPPC did not experience any limitations in the credit markets, nor do we expect any significant limitations for the remainder of 2013. However, disruptions in the banking and capital markets not specifically relatedThe Company's exposure to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
In prior years, SPPC required significant amounts of liquidity due to the magnitude of capital expenditures needed to support a growing customer base and to support unstable energy markets. As SPPC has transitioned to slower growth, the amount of capital expenditures required has declined. SPPC’s investment in generating stations in the past several years and more stable energy markets have positioned SPPC to better manage and optimize its resources. As a result, SPPC anticipates that it will be able to meet short term operating costs and capital expenditures with internally generated funds and the use of its revolving credit facility. Furthermore, with significant investments in rates, the decrease of hedging costs, more current rate recovery of deferred energy costs, various rate reset mechanisms, current federal tax NOL, and a decrease in capital expenditures, SPPC expects to generate free cash flow in 2013; however, SPPC’s cash flow may vary from quarter to quarter due to the seasonality of our business. Free cash flow may be used to reduce debt, to increase dividend payout and for potential investment opportunities. To meet long term maturing debt obligations, SPPC may use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt, or capital contributions from NVE.
However, if energy costs rise at a rapid rate, or SPPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters and Financial Gas Hedges, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity under such circumstances, SPPC may be required to delay capital expenditures, refinance debt, or receive capital contributions from NVE.
The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities. Additionally, disruptions in the banking and capital markets not specifically related to SPPC may affect its ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.
During the nine months ended September 30, 2013, SPPC paid dividends to NVE of approximately $40.0 million. On November 6, 2013, SPPC declared a dividend to NVE of $37.0 million.
SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, environmental compliance, improvement, and maintenance of facilities.
During the nine months ended September 30, 2013, there were no material changes to contractual obligations as set forth in SPPC’s 2012 Form 10-K, except that in June 2013, SPPC entered into a long-term capital lease for a solar array facility, still subject to commercial operation and approval by the PUCN. The contract requires SPPC to make annual payments of approximately $3.0 million per year for a twenty year period. However, SPPC has the option to terminate the lease and purchase the facility on or after the sixth anniversary of the commercial operation date of the facility for approximately $20.0 million.
Financing Transactions
In August 2013, SPPC issued and sold $250 million of its 3.375% General and Refunding Notes, Series T due 2023. The approximately $247.9 million in net proceeds was used, together with cash on hand to pay at maturity the $250 million principal amount of its 5.45% General and Refunding Notes, Series Q, which matured in September 2013.
Factors Affecting Liquidity
Ability to Issue Debt
SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreementsmarket risk and its revolving credit facility agreement, and the termsmanagement of certain NVE debt. Assuch risk has not changed materially since December 31, 2013. Refer to Note 7 of September 30, 2013, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue upNotes to $350 million of long-term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of the Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below:
| |
a. | Financing authority from the PUCN - As of September 30, 2013, SPPC has financing authority from the PUCN for the period ending December 31, 2015, consisting of authority (1) to issue additional long-term debt securities of up to $350 million; (2) to refinance up to approximately $348.3 million of long-term debt securities; and (3) ongoing authority to maintain a revolving credit facility of up to $600 million. In May 2013, NPC and SPPC filed a joint financing application with the PUCN, see Note 4, Regulatory Actions of the Condensed Notes to Financial Statements for further details.
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| |
b. | Financial covenants within SPPC’s financing agreements - Under the SPPC Credit Agreement, the Utility must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1.00. Based on financial statements for the period ended September 30, 2013, SPPC was in compliance with this covenant and could incur up to $1.1billion of additional indebtedness.
|
All other financial covenants contained in SPPC’s financing agreements are suspended as SPPC’s senior secured debt is currently rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants.
| |
c. | Financial covenants within NVE’s Term Loan - As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $3.7 billion.
|
Ability to Issue General and Refunding Mortgage Securities
To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its and NVE’s financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under the SPPC Indenture.
The SPPC Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of September 30, 2013, $1.5 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $860 million of additional General and Refunding Mortgage Securities as of September 30, 2013. That amount is determined on the basis of:
| |
1. | 70% of net utility property additions; and/or |
| |
2. | the principal amount of retired General and Refunding Mortgage Securities. |
Property additions include plant in service. Although specific assets in CWIP can also qualify as property additions, the amount of bond capacity listed above does not reflect eligible property in CWIP.
SPPC also has the ability to release property from the lien of the SPPC Indenture on the basis of net property additions, cash, and/or retired bonds. To the extent SPPC releases property from the lien of the SPPC Indenture, it will reduce the amount of securities issuable under the SPPC Indenture.
Credit Ratings
The liquidity of SPPC, the cost and availability of borrowing by SPPC under the SPPC Credit Agreement, the potential exposure of SPPC to collateral calls under various contracts, and the ability of SPPC to acquire fuel and purchased power on favorable terms are all directly affected by the credit ratings for SPPC’s debt. On May 22, 2013, Moody’s upgraded SPPC’s ratings. On May 30, 2013, Fitch and S&P upgraded SPPC’s rating outlook from Stable to Positive. SPPC’s senior secured debt is rated investment grade by three NRSROs: Fitch, Moody’s and S&P. The senior secured debt credit ratings are as follows:
|
| | | | |
| | Rating Agency |
| | Fitch(1)
| Moody’s(2)
| S&P(3)
|
SPPC | Sr. Secured Debt | BBB+* | A3* | BBB+* |
| |
(1) | Fitch’s lowest level of “investment grade” credit rating is BBB-. |
| |
(2) | Moody’s lowest level of “investment grade” credit rating is Baa3. |
| |
(3) | S&P’s lowest level of “investment grade” credit rating is BBB-. |
Fitch’s and S&P’s rating outlooks are Positive, while Moody’s rating outlook is Stable for SPPC.
A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization. Each security rating agency has its own methodology for assigning ratings, and accordingly, each rating should be evaluated in the context of the applicable methodology, independently of all other ratings. The rating agencies provide ratings at the request of the company being rated and charge the company fees for their services.
Energy Supplier Matters
With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.
Under these contracts, a material adverse change, which includes a credit rating downgrade in SPPC may allow the counterparty to request adequate financial assurance, which if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. According to the net mark-to-market value as of September 30, 2013, no amounts would be due to or from SPPC for all suppliers continuing to provide power under a WSPP agreement. These contracts qualify for the normal purchases and normal sales scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet.
Gas Supplier Matters
With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.
Gas transmission service is secured under FERC tariffs or custom agreements. These service contracts and tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which under certain circumstances require the Utilities to provide collateral to continue receiving service.
Financial Gas Hedges
SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed in Note 6, Long Term Debt of the Notes toConsolidated Financial Statements in the 2012Item 1 of this Form 10-K, SPPC’s Financing Transactions, the availability under the SPPC’s revolving credit facility is reduced10-Q for net negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facility shall at no time exceed 50%disclosure of the total commitments then in effect under the credit facility. Currently, there are no negative mark-to-market exposures that would impact borrowingsCompany's derivative positions as of SPPC. If deemed prudent, SPPC may purchase hedging instruments in the event circumstances occur that may have the potential to increase the cost of fuel and purchased power.June 30, 2014.
Cross Default Provisions
None of the financing agreements of SPPC contains a cross default provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of their respective financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.
Change of Control Provisions; Consent of Lenders
The MidAmerican Merger will accelerate the vesting and settlement of equity compensation awards to executives and employees which will be cashed out upon consummation of the MidAmerican Merger. Certain executives are also entitled to additional change of control payments in the event of an occurrence of a qualified termination. The consummation of the MidAmerican Merger will also trigger mandatory redemption requirements under financing agreements of SPPC. As a result, SPPC will be required to offer to purchase approximately $951.7 million of debt at 101% of par within 10 days after the MidAmerican Merger closing. At this time, SPPC is unable to determine the extent to which holders of these debt securities will accept such tender offers. The average interest rate under these debt securities is approximately 5.51% for SPPC. To the extent that debt securities are tendered pursuant to the required tender offers, SPPC intends to fund the purchases using a combination of internal funds, SPPC’s revolving credit facility or the issuance of long-term debt. Furthermore, SPPC was required to obtain consents from lenders under the terms of its revolving credit facility before consummating the MidAmerican Merger. In November 2013, SPPC amended its revolving credit facility to permit the MidAmerican Merger.
RECENT PRONOUNCEMENTS
See Note 1, Summary of Significant Accounting Policies of the Condensed Notes to Financial Statements, and Note 1, Summary of Significant Accounting Policies of the Notes to Financial Statements in the 2012 Form 10-K for discussion of accounting policies and recent pronouncements.
Item 4. Controls and Procedures
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
As of September 30, 2013, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. Fair market value is determined using quoted market price forAt the same or similar issues or on the current rates offered for debtend of the same remaining maturities (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2013 | | | | |
| | Expected Maturities | | | | |
| | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | Thereafter | | Total | | Fair Value |
| Long-Term Debt | | | | | | | | | | | | | | |
| NVE | | | | | | | | | | | | | | | |
| Fixed Rate | $ | — |
| | $ | 195,000 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 315,000 |
| | $ | 510,000 |
| | $ | 561,613 |
|
| Average Interest Rate | — |
| | 2.56 | % | | — |
| | — |
| | — |
| | 6.25 | % | | 4.84 | % | | — |
|
| | | | | | | | | | | | | | | | |
| NPC | | | | | | | | | | | | | |
| | |
| Fixed Rate | $ | — |
| | $ | 125,000 |
| | $ | 250,000 |
| | $ | 210,000 |
| | $ | — |
| | $ | 2,545,000 |
| | $ | 3,130,000 |
| | $ | 3,677,189 |
|
| Average Interest Rate | — |
| | 7.38 | % | | 5.88 | % | | 5.95 | % | | — |
| | 6.47 | % | | 6.42 | % | | — |
|
| | | | | | | | | | | | | | | | |
| Variable Rate | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 75,675 |
| | $ | 75,675 |
| | $ | 72,637 |
|
| Average Interest Rate | — |
| | — |
| | — |
| | — |
| | — |
| | 0.54 | % | | 0.54 | % | | — |
|
| | | | | | | | | | | | | | | | |
| SPPC | | | | | | | | | | | | | |
| | |
| Fixed Rate | $ | — |
| | $ | — |
| | $ | — |
| | $ | 450,000 |
| | $ | — |
| | $ | 501,742 |
| | $ | 951,742 |
| | $ | 1,066,865 |
|
| Average Interest Rate | — |
| | — |
| | — |
| | 6.00 | % | | — |
| | 5.07 | % | | 5.51 | % | | — |
|
| | | | | | | | | | | | | | | | |
| Variable Rate | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 214,675 |
| | $ | 214,675 |
| | $ | 185,176 |
|
| Average Interest Rate | — |
| | — |
| | — |
| | — |
| | — |
| | 0.54 | % | | 0.54 | % | | — |
|
| TOTAL DEBT | $ | — |
| | $ | 320,000 |
| | $ | 250,000 |
| | $ | 660,000 |
| | $ | — |
| | $ | 3,652,092 |
| | $ | 4,882,092 |
| | $ | 5,563,480 |
|
Commodity Price Risk
Seeperiod covered by this Quarterly Report on Form 10-Q, the 2012 Form 10-K, Item 7A, QuantitativeCompany carried out an evaluation, under the supervision and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2012.
Credit Risk
The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that a counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities becauseparticipation of the counterparty’sCompany's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $50 million as of September 30, 2013, which compares to balances of $98.6 million at March 30, 2013 and $116.6 million at June 30, 2013. The decrease from March 30, 2013 and June 30, 2013 is primarily due to expiring contracts.
ITEM 4. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures.
NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluationofficer), of the registrants’effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in RulesRule 13a-15(e) and 15d-15(e) ofpromulgated under the Securities and Exchange Act of 1934) have1934, as amended). Based upon that evaluation, the Company's management, including the President (principal executive officer) and the Chief Financial Officer (principal financial officer), concluded that as of September 30, 2013, the registrants’Company's disclosure controls and procedures were effective.
(b) Change in internal controls over financial reporting.
There were no changeseffective to ensure that information required to be disclosed by the Company in the registrants’reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to management, including the Company's President (principal executive officer) and Chief Financial Officer (principal financial officer), or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There has been no change in the Company's internal controlscontrol over financial reporting induring the third quarter of 2013ended June 30, 2014 that havehas materially affected, or areis reasonably likely to materially affect, the registrants’Company's internal controlscontrol over financial reporting.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Other Legal Matters
NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had, or in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 8, Commitments and Contingencies of the Condensed Notes to Financial Statements for further discussion of other legal matters.
ITEM 1A. RISK FACTORS
For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2012 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.
As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2012 Form 10-K, and quarterly reports for NVE, NPC and SPPC on Form 10-Q for the quarters ended March 31, 2013 and June 30, 2013.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
None.
ITEM 6. EXHIBITS
(a) Exhibits filed with this Form 10-Q:
(10) Nevada Power Company:
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| |
10.1 | Collective Bargaining Agreement effective September 24, 2013 through August 31, 2017, between Nevada Power Company and the International Brotherhood of Electrical Workers Local Union No. 396. |
(12) NV Energy, Inc.:
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12.1 | Statement regarding computation of Ratios of Earnings to Fixed Charges. |
Nevada Power Company:
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12.2 | Statement regarding computation of Ratios of Earnings to Fixed Charges. |
Sierra Pacific Power Company:
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12.3 | Statement regarding computation of Ratios of Earnings to Fixed Charges. |
(21) NV Energy, Inc.:
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| |
| Lands of Sierra Inc., a Nevada corporation |
| Nevada Power Company d/b/a NV Energy, a Nevada corporation |
| NVE Insurance Company, Inc., a Nevada corporation |
| Sierra Gas Holdings Company, a Nevada corporation |
| Sierra Pacific Power Company d/b/a NV Energy, a Nevada corporation |
Nevada Power Company:
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| |
| Commonsite, Inc., a Nevada corporation |
| Nevada Electric Investment Company, a Nevada corporation |
Sierra Pacific Power Company:
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| | |
| GPSF-B Inc. , a Delaware corporation |
| Piñon Pine Corporation, a Nevada corporation |
| Piñon Pine Investment Company, a Nevada corporation |
| | Piñon Pine Company, L.L.C., a Nevada limited liability company |
(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company
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31.1 | Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2 | Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.3 | Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.4 | Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
31.5 | Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
31.6 | Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company
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32.1 | Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2 | Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.3 | Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.4 | Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.5 | Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.6 | Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(101) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company
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101.INS | XBRL Instance Document |
101.SCH | XBRL Taxonomy Schema |
101.CAL | XBRL Calculation Linkbase |
101.LAB | XBRL Label Linkbase |
101.PRE | XBRL Presentation Linkbase |
101.DEF | XBRL Definition Linkbase |
PART II
None.
There has been no material change to the Company's risk factors from those disclosed in Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2013.
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Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
Not applicable.
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Item 3. | Defaults Upon Senior Securities |
Not applicable.
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Item 4. | Mine Safety Disclosures |
None.
Not applicable.
The exhibits listed on the accompanying Exhibit Index are filed as part of this Quarterly Report.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants haveregistrant has duly caused this report to be signed on theirits behalf by the undersigned thereunto duly authorized.
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| | | | |
| | | NV Energy, Inc.NEVADA POWER COMPANY |
| | | (Registrant) |
| | | | | |
| | | | |
Date: | November 6, 2013 | By: | | /s/ Michael W. Yackira |
| | | | Michael W. Yackira |
| | | | President and Chief Executive Officer |
| | | | (Principal Executive Officer) |
| | | | |
| | | | | |
| Date: | November 6, 2013 | By: | August 1, 2014 | /s/ E. Kevin Bethel |
| | | | E. Kevin Bethel |
| | | | | Senior Vice President and Chief Financial Officer |
| | | | | (Principal Financial Officer) |
| | | | |
| | | | |
| | Nevada Power Company d/b/a NV Energy |
| | (Registrant) |
| | | | |
| | | | |
Date: | November 6, 2013 | By | | /s/ Michael W. Yackira |
| | | | Michael W. Yackira |
| | | | Presidentprincipal financial and Chief Executive Officer |
| | | | (Principal Executive Officer) |
| | | | |
| | | | |
Date: | November 6, 2013 | By: | | /s/ E. Kevin Bethel |
| | | | E. Kevin Bethel |
| | | | Vice President and Chief Financial Officer |
| | | | (Principal Financial Officer) |
| | | | |
| | Sierra Pacific Power Company d/b/a NV Energy |
| | (Registrant) |
| | | | |
| | | | |
Date: | November 6, 2013 | | | /s/ Michael W. Yackira |
| | | | Michael W. Yackira |
| | | | President and Chief Executive Officer |
| | | | (Principal Executive Officer) |
| | | | |
| | | | |
Date: | November 6, 2013 | By: | | /s/ E. Kevin Bethel |
| | | | E. Kevin Bethel |
| | | | Vice President and Chief Financial Officer |
| | | | (Principal Financial Officer) |
| | | | accounting officer) |
EXHIBIT INDEX
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| 10.1 | $400,000,000 Amended and Restated Credit Agreement, dated as of June 27, 2014, among Nevada Power Company, as borrower, the Initial Lenders, Wells Fargo Bank, National Association, as administrative agent and swingline lender and the LC Issuing Banks (incorporated by reference to Exhibit 10.1 to the Nevada Power Company Current Report on Form 8-K dated June 27, 2014). |
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| 15 | Awareness Letter of Independent Registered Public Accounting Firm. |
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| 31.1 | Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| 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. |
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| 32.2 | Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| 101 | The following financial information from Nevada Power Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, 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 Changes in Shareholder's Equity, (iv) the Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements, tagged in summary and detail. |