NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Operations
Sierra Pacific Power Company ("Sierra Pacific"), together with its subsidiaries (collectively, the "Company"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company ("Nevada Power") and certain other subsidiaries. The Company is a United States regulated electric utility company serving retail customers, including residential, commercial and industrial customers primarily in northern Nevada and regulated retail natural gas customers in Nevada. NV Energy is an indirect wholly owned subsidiary of MidAmerican Energy Holdings Company ("MEHC"). MEHC is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. MEHC is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").
On December 19, 2013, the merger contemplated by the Agreement and Plan of Merger dated May 29, 2013, among MEHC, Silver Merger Sub, Inc. ("Merger Sub"), MEHC's wholly owned subsidiary, and NV Energy, whereby Merger Sub was merged into NV Energy and NV Energy became an indirect wholly owned subsidiary of MEHC ("MEHC Merger")was completed.
The transaction was approved by the boards of directors of both NV Energy and MEHC and the shareholders of NV Energy. MEHC received unconditional approval of the MEHC Merger from the Federal Energy Regulatory Commission ("FERC") on December 19, 2013 and the Federal Communications Commission on September 27, 2013. The United States Department of Justice and the Federal Trade Commission granted early termination of the mandatory waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976 on July 22, 2013. On December 17, 2013, the Public Utilities Commission of Nevada ("PUCN") approved the Joint Application filed by MEHC and NV Energy, subject to certain stipulations. The stipulations included, among others:
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•
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A one-time bill credit to retail customers of the Company of
$5 million
credited to retail customers over one billing cycle beginning within
30 days
of the close of the MEHC Merger.
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•
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MEHC and NV Energy agreed to not seek recovery of the acquisition premium, transaction and transition costs associated with the MEHC Merger from customers.
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•
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The Company will not seek to collect lost revenues as described in section 704.9524 of the Nevada Administrative Code for calendar year 2013 in 2014 rates, and will not seek collection of lost revenues in excess of
50%
of what the Company could otherwise request for calendar year 2014 in 2015 rates. NV Energy also agreed to work cooperatively with PUCN staff and the Nevada Bureau of Consumer Protection ("BCP") to develop a legislative or administrative alternative to the current mechanism that would retain the objective of encouraging investment in energy efficiency and that is acceptable to NV Energy, PUCN staff and the BCP. NV Energy and the BCP also agree to work in good faith to have a legislative or administrative alternative adopted.
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•
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Normal rate case rules and procedures apply to costs and revenues, and any under or over earnings will accrue to the Company until the next rate case filing after 2014, subject to specified adjustments for intercompany charges from MEHC and its other subsidiaries as described in the PUCN Joint Application. The commitment does not preclude parties from proposing any other adjustments to test year or certification period results.
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(2) Summary of Significant Accounting Policies
Basis of Consolidation and Presentation
The Consolidated Financial Statements include the accounts of the Company and its subsidiaries in which it holds a controlling financial interest as of the financial statement date. Intercompany accounts and transactions have been eliminated.
The impacts of acquisition accounting from the MEHC Merger were not reflected on the Consolidated Financial Statements of the Company.
As a result of the MEHC Merger, the Company has elected to present its Consolidated Financial Statements and Notes to Consolidated Financial Statements for the current year and prior years similar to MEHC. Certain amounts from prior years have been reclassed to conform to the current period presentation. The change in format did not have an effect on net income, total assets, total shareholder's equity or cash flows from operations.
Use of Estimates in Preparation of Financial Statements
The preparation of the Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the period. These estimates include, but are not limited to, the effects of regulation; recovery of long-lived assets; certain assumptions made in accounting for pension and other postretirement benefits; asset retirement obligations ("AROs"); income taxes; unbilled revenue; valuation of certain financial assets and liabilities, including derivative contracts; and accounting for contingencies. Actual results may differ from the estimates used in preparing the Consolidated Financial Statements.
Accounting for the Effects of Certain Types of Regulation
The Company prepares its Consolidated Financial Statements in accordance with authoritative guidance for regulated operations, which recognizes the economic effects of regulation. Accordingly, the Company defers the recognition of certain costs or income if it is probable that, through the ratemaking process, there will be a corresponding increase or decrease in future regulated rates. Regulatory assets and liabilities are established to reflect the impacts of these deferrals, which will be recognized in earnings in the periods the corresponding changes in regulated rates occur.
The Company continually evaluates the applicability of the guidance for regulated operations and whether its regulatory assets and liabilities are probable of inclusion in future regulated rates by considering factors such as a change in the regulator's approach to setting rates from cost-based ratemaking to another form of regulation, other regulatory actions or the impact of competition that could limit the Company's ability to recover its costs. The Company believes the application of the guidance for regulated operations is appropriate and its existing regulatory assets and liabilities are probable of inclusion in future regulated rates. The evaluation reflects the current political and regulatory climate at both the federal and state levels. If it becomes no longer probable that the deferred costs or income will be included in future regulated rates, the related regulatory assets and liabilities will be written off to net income, returned to customers or re-established as accumulated other comprehensive income (loss) ("AOCI").
Fair Value Measurements
As defined under GAAP, fair value is the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market or in the most advantageous market when no principal market exists. Adjustments to transaction prices or quoted market prices may be required in illiquid or disorderly markets in order to estimate fair value. Different valuation techniques may be appropriate under the circumstances to determine the value that would be received to sell an asset or paid to transfer a liability in an orderly transaction. Market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress. Nonperformance or credit risk is considered in determining fair value. Considerable judgment may be required in interpreting market data used to develop the estimates of fair value. Accordingly, estimates of fair value presented herein are not necessarily indicative of the amounts that could be realized in a current or future market exchange.
Cash Equivalents and Restricted Cash and Investments
Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted amounts are included in other current assets on the Consolidated Balance Sheets.
Allowance for Doubtful Accounts
Accounts receivable are stated at the outstanding principal amount, net of an estimated allowance for doubtful accounts. The allowance for doubtful accounts is based on the Company's assessment of the collectability of amounts owed to the Company by its customers. This assessment requires judgment regarding the ability of customers to pay or the outcome of any pending disputes. The Company also has the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. As of December 31,
2013
and
2012
, the allowance for doubtful accounts totaled
$1 million
and is included in accounts receivable, net on the Consolidated Balance Sheets.
Derivatives
The Company employs a number of different derivative contracts, including forwards, futures, options, swaps and other agreements, to manage price risk for electricity, natural gas and other commodities; and interest rate risk. Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP.
Commodity derivatives used in normal business operations that are settled by physical delivery, among other criteria, are eligible for and may be designated as normal purchases or normal sales. Normal purchases or normal sales contracts are not marked-to-market and settled amounts are recognized as cost of fuel, energy and capacity or natural gas purchased for resale on the Consolidated Statements of Operations.
For the Company's derivatives not designated as hedging contracts, the settled amount is generally included in regulated rates. Accordingly, the net unrealized gains and losses associated with interim price movements on contracts that are accounted for as derivatives and probable of inclusion in regulated rates are recorded as regulatory assets and liabilities.
For the Company's derivatives designated as hedging contracts, the Company formally assesses, at inception and thereafter, whether the hedging contract is highly effective in offsetting changes in the hedged item. The Company formally documents hedging activity by transaction type and risk management strategy.
Inventories
Inventories consist mainly of materials and supplies totaling
$30 million
and
$29 million
as of December 31,
2013
and
2012
, respectively, and fuel, which includes coal stocks, stored gas and fuel oil totaling
$13 million
and
$31 million
as of December 31,
2013
and
2012
, respectively. The cost is determined using the average cost method. Materials are charged to inventory when purchased and are expensed or capitalized to construction work in process, as appropriate, when used. Fuel costs are recovered from retail customers through the base tariff energy rates and deferred energy accounting adjustment charges approved by the PUCN.
Property, Plant and Equipment, Net
General
Additions to property, plant and equipment are recorded at cost. The Company capitalizes all construction-related material, direct labor and contract services, as well as indirect construction costs. Indirect construction costs include debt allowance for funds used during construction ("AFUDC"), and equity AFUDC, as applicable. The cost of additions and betterments are capitalized, while costs incurred that do not improve or extend the useful lives of the related assets are generally expensed. The cost of repairs and minor replacements are charged to expense when incurred with the exception of costs for generation plant maintenance under certain long-term service agreements. Costs under these agreements are expensed straight-line over the term of the agreements as approved by the PUCN.
Depreciation and amortization are generally computed by applying the composite or straight-line method based on either estimated useful lives or mandated recovery periods as prescribed by the Company's various regulatory authorities. Depreciation studies are completed by the Company to determine the appropriate group lives, net salvage and group depreciation rates. These studies are reviewed and rates are ultimately approved by the applicable regulatory commission. Net salvage includes the estimated future residual values of the assets and any estimated removal costs recovered through approved depreciation rates. Estimated removal costs are recorded as either a cost of removal regulatory liability or an ARO liability on the Consolidated Balance Sheets, depending on whether the obligation meets the requirements of an ARO. As actual removal costs are incurred, the associated liability is reduced.
Generally when the Company retires or sells a component of regulated property, plant and equipment, it charges the original cost, net of any proceeds from the disposition, to accumulated depreciation. Any gain or loss on disposals of all other assets is recorded through earnings.
Debt and equity AFUDC, which represents the estimated costs of debt and equity funds necessary to finance the construction of regulated facilities, are capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations. AFUDC is computed based on guidelines set forth by the FERC. After construction is completed, the Company is permitted to earn a return on these costs as a component of the related assets, as well as recover these costs through depreciation expense over the useful lives of the related assets. The Company's AFUDC rate used during both
2013
and
2012
was
7.86%
for electric,
5.15%
for natural gas and
7.59%
for common facilities. As specified by the PUCN, certain projects may be assigned a lower or higher AFUDC rate due to specific interest-rate financings directly associated with those projects.
Asset Retirement Obligations
The Company recognizes AROs when it has a legal obligation to perform decommissioning, reclamation or removal activities upon retirement of an asset. The Company's AROs are primarily associated with its generating facilities. The fair value of an ARO liability is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made, and is added to the carrying amount of the associated asset, which is then depreciated over the remaining useful life of the asset. Subsequent to the initial recognition, the ARO liability is adjusted for any revisions to the original estimate of undiscounted cash flows (with corresponding adjustments to property, plant and equipment) and for accretion of the ARO liability due to the passage of time. The difference between the ARO liability, the corresponding ARO asset included in property, plant and equipment, net and amounts recovered in rates to satisfy such liabilities is recorded as a regulatory asset or liability on the Consolidated Balance Sheets.
Management's methodology to assess its legal obligation includes an inventory of assets by the Company's system and components and a review of rights of way and easements, regulatory orders, leases and federal, state and local environmental laws. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl have met the requirements for an ARO.
Impairment
The Company evaluates long-lived assets for impairment, including property, plant and equipment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable or the assets are being held for sale. Upon the occurrence of a triggering event, the asset is reviewed to assess whether the estimated undiscounted cash flows expected from the use of the asset plus the residual value from the ultimate disposal exceeds the carrying value of the asset. If the carrying value exceeds the estimated recoverable amounts, the asset is written down to the estimated fair value. The impacts of regulation are considered when evaluating the carrying value of regulated assets. For all other assets, any resulting impairment loss is reflected on the Consolidated Statements of Operations.
Income Taxes
Berkshire Hathaway commenced including the Company in its United States federal income tax return on December 20, 2013 in connection with the MEHC Merger. Prior to December 20, 2013, the Company filed a consolidated United States federal income tax return with NV Energy. Consistent with established regulatory practice, the Company's provision for income taxes has been computed on a separate return basis.
Deferred income tax assets and liabilities are based on differences between the financial statement and income tax basis of assets and liabilities using estimated income tax rates expected to be in effect for the year in which the differences are expected to reverse. Changes in deferred income tax assets and liabilities that are associated with components of other comprehensive income ("OCI") are charged or credited directly to OCI. Changes in deferred income tax assets and liabilities that are associated with income tax benefits and expense for certain property-related basis differences and other various differences that the Company is required to pass on to its customers in Nevada are charged or credited directly to a regulatory asset or liability. As of December 31,
2013
and
2012
, these amounts were recognized as regulatory assets of
$96 million
and
$100 million
, respectively, and regulatory liabilities of
$9 million
and
$10 million
, respectively, and will be included in regulated rates when the temporary differences reverse. Other changes in deferred income tax assets and liabilities are included as a component of income tax expense. Changes in deferred income tax assets and liabilities attributable to changes in enacted income tax rates are charged or credited to income tax expense or a regulatory asset or liability in the period of enactment. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount that is more-likely-than-not to be realized. Investment tax credits are generally deferred and amortized over the estimated useful lives of the related properties.
In determining the Company's income taxes, management is required to interpret complex income tax laws and regulations, which includes consideration of regulatory implications imposed by the Company's various regulatory jurisdictions. The Company's income tax returns are subject to continuous examinations by federal and local income tax authorities that may give rise to different interpretations of these complex laws and regulations. Due to the nature of the examination process, it generally takes years before these examinations are completed and these matters are resolved. The Company recognizes the tax benefit from an uncertain tax position only if it is more-likely-than-not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the Consolidated Financial Statements from such a position are measured based on the largest benefit that is more-likely-than-not of being realized upon ultimate settlement. Although the ultimate resolution of the Company's federal, state, local and foreign income tax examinations is uncertain, the Company believes it has made adequate provisions for these income tax positions. The aggregate amount of any additional income tax liabilities that may result from these examinations, if any, is not expected to have a material impact on the Company's consolidated financial results. The Company's unrecognized tax benefits are primarily included in accrued property, income and other taxes and other long-term liabilities on the Consolidated Balance Sheets. Estimated interest and penalties, if any, related to uncertain tax positions are included as a component of income tax expense on the Consolidated Statements of Operations.
Revenue Recognition
Revenue is recognized as electricity or natural gas is delivered or services are provided. Revenue recognized includes billed and unbilled amounts. As of December 31,
2013
and
2012
, unbilled revenue was
$65 million
and
$50 million
, respectively, and is included in accounts receivable, net on the Consolidated Balance Sheets. Rates are established by regulators or contractual arrangements. When preliminary rates are permitted to be billed prior to final approval by the applicable regulator, certain revenue collected may be subject to refund and a liability for estimated refunds is accrued. The Company records sales, franchise and excise taxes collected directly from customers and remitted directly to the taxing authorities on a net basis on the Consolidated Statements of Operations.
The Company primarily buys energy and natural gas to satisfy its customer load requirements. Due to changes in retail customer load requirements, the Company may not take physical delivery of the energy or natural gas. The Company may sell the excess energy or natural gas to the wholesale market. In such instances, it is the Company's policy to record such sales net in cost of fuel, energy and capacity.
Unamortized Debt Premiums, Discounts and Financing Costs
Premiums, discounts and financing costs incurred for the issuance of long-term debt are amortized over the term of the related financing using the effective interest method.
New Accounting Pronouncements
In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2013-04, which amends FASB Accounting Standards Codification ("ASC") Topic 405, "Liabilities." The amendments in this guidance require an entity to measure obligations resulting from joint and several liability arrangements for which 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 obligation, 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 guidance on January 1, 2014. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.
In February 2013, the FASB issued ASU No. 2013-02, which amends FASB ASC Topic 220, "Comprehensive Income." The amendments in this guidance require an entity to provide information about the amounts reclassified out of AOCI by component. In addition, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of AOCI by the respective line items of net income if the amount reclassified is required under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required by GAAP that provide additional detail about those amounts. The Company adopted this guidance on January 1, 2013. The adoption of this guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.
In December 2011, the FASB issued ASU No. 2011-11, which amends FASB ASC Topic 210, "Balance Sheet." The amendments in this guidance require an entity to provide quantitative disclosures about offsetting financial instruments and derivative instruments. Additionally, this guidance requires qualitative and quantitative disclosures about master netting agreements or similar agreements when the financial instruments and derivative instruments are not offset. In January 2013, the FASB issued ASU No. 2013-01, which also amends FASB ASC Topic 210 to clarify that the scope of ASU No. 2011-11 only applies to derivative instruments, repurchase agreements, reverse purchase agreements and securities borrowing and securities lending transactions that are either being offset or are subject to an enforceable master netting arrangement or similar agreement. The Company adopted the guidance on January 1, 2013. The adoption of the guidance did not have a material impact on the Company's disclosures included within Notes to Consolidated Financial Statements.
(3) Merger-Related Activities
On December 17, 2013, the PUCN approved the Joint Application related to the MEHC Merger filed by MEHC and NV Energy, subject to certain stipulations. The stipulations included, among others, a one-time bill credit to retail customers of the Company of
$5 million
credited to retail customers over one billing cycle beginning within 30 days of the close of the MEHC Merger. The bill credit was included as a reduction to operating revenue on the Consolidated Statements of Operations for the year ended December 31, 2013.
The Company incurred costs totaling
$20 million
related to the MEHC Merger, consisting of: (i)
$6 million
for amounts payable under NV Energy's change in control policy; (ii)
$7 million
for accelerated vesting and stock compensation under NV Energy's long-term incentive plan; (iii)
$6 million
for investment banker fees paid by NV Energy and (iv)
$1 million
for legal and other expenses. The costs were included in merger-related expenses on the Consolidated Statements of Operations for the year ended December 31, 2013.
(4) Property, Plant and Equipment, Net
Property, plant and equipment, net consists of the following as of December 31 (in millions):
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|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
Utility plant in-service:
|
|
|
|
|
Electric generation
|
$
|
1,070
|
|
|
$
|
1,060
|
|
|
Electric distribution
|
1,289
|
|
|
1,256
|
|
|
Electric transmission
|
685
|
|
|
678
|
|
|
Electric intangible plant
|
138
|
|
|
102
|
|
|
Natural gas distribution
|
357
|
|
|
341
|
|
|
Natural gas intangible plant
|
13
|
|
|
13
|
|
|
Common general
|
212
|
|
|
218
|
|
|
Utility plant in-service
|
3,764
|
|
|
3,668
|
|
|
Accumulated depreciation and amortization
|
(1,301
|
)
|
|
(1,278
|
)
|
|
Utility plant in-service, net
|
2,463
|
|
|
2,390
|
|
|
Construction work-in-progress
|
89
|
|
|
140
|
|
|
Property, plant and equipment, net
|
$
|
2,552
|
|
|
$
|
2,530
|
|
All of the Company's plant is subject to the ratemaking jurisdiction of the PUCN and the FERC. The Company's depreciation and amortization expense, as authorized by the PUCN, stated as a percentage of the average depreciable property balances was
3.02%
,
2.94%
and
2.89%
during
2013
,
2012
and 2011, respectively. The Company is required to file a utility plant depreciation study every six years as a companion filing with the triennial general rate case filings.
Construction work-in-progress is related to the construction of regulated assets.
Impairment of Regulated Assets Not In Rates
The Company recorded an impairment charge of
$4 million
in operating and maintenance expense on the Consolidated Statements of Operations for the year ended December 31, 2013 related to the recovery of certain assets not currently in rates.
Sale of California Electric Distribution and Generation Assets
In January 2011, the Company sold its California electric distribution and generation assets to California Pacific Electric Company. Cash proceeds from the sale were
$132 million
, plus additional closing adjustments. Final accounting was approved by the FERC in September 2011. In connection with the sale of the assets, the Company entered into a separate five year purchase power agreement to sell energy to California Pacific Electric Company.
(5) Jointly Owned Utility Facilities
Under joint facility ownership agreements, the Company, as tenants in common, has undivided interests in jointly owned generation, and transmission facilities. The Company accounts for its proportionate share of each facility, and each joint owner has provided financing for its share of each facility. Operating costs of each facility are assigned to joint owners based on their percentage of ownership or energy production, depending on the nature of the cost. Operating costs and expenses on the Consolidated Statements of Operations include the Company's share of the expenses of these facilities. The amounts shown in the table below represent the Company's share in each jointly owned facility as of December 31,
2013
(dollars in millions):
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|
|
|
|
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|
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|
|
Construction
|
|
|
Company
|
|
Facility In
|
|
Accumulated
|
|
Work-in-
|
|
|
Share
|
|
Service
|
|
Depreciation
|
|
Progress
|
|
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|
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Valmy Generating Station
|
50%
|
|
$
|
338
|
|
|
$
|
211
|
|
|
$
|
18
|
|
|
ON Line Transmission Line
(1)
|
1
|
|
7
|
|
|
—
|
|
|
4
|
|
|
Valmy Transmission
|
50
|
|
4
|
|
|
2
|
|
|
—
|
|
|
Total
|
|
|
$
|
349
|
|
|
$
|
213
|
|
|
$
|
22
|
|
|
|
|
|
(1)
|
ON Line was placed in-service December 2013. The Company and Nevada Power entered into a long-term transmission use agreement with Great Basin Transmission South, LLC's
75%
interest in ON Line. Refer to Note 8 for additional information.
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(6) Regulatory Matters
Regulatory assets represent costs that are expected to be recovered in future rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
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|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Remaining Life
|
|
2013
|
|
2012
|
|
|
|
|
|
|
|
|
Deferred income taxes
(1)
|
29 years
|
|
$
|
96
|
|
|
$
|
100
|
|
|
Employee benefit plans
(2)
|
13 years
|
|
90
|
|
|
140
|
|
|
Merger costs from 1999 merger
|
32 years
|
|
90
|
|
|
95
|
|
|
Abandoned projects
|
10 years
|
|
59
|
|
|
42
|
|
|
Legacy meters
|
6 years
|
|
24
|
|
|
3
|
|
|
Deferred excess energy costs
|
1 year
|
|
17
|
|
|
—
|
|
|
Unrealized loss on regulated derivative contracts
|
14 years
|
|
13
|
|
|
—
|
|
|
Asset retirement obligations
|
11 years
|
|
10
|
|
|
9
|
|
|
Other
|
Various
|
|
43
|
|
|
80
|
|
|
Total regulatory assets
|
|
|
$
|
442
|
|
|
$
|
469
|
|
|
|
|
|
|
|
|
|
Reflected as:
|
|
|
|
|
|
|
Current assets
|
|
|
$
|
15
|
|
|
$
|
—
|
|
|
Noncurrent assets
|
|
|
427
|
|
|
469
|
|
|
Total regulatory assets
|
|
|
$
|
442
|
|
|
$
|
469
|
|
|
|
|
|
(1)
|
Amounts primarily represent income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously flowed through to customers and will be included in regulated rates when the temporary differences reverse.
|
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(2)
|
Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.
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The Company had regulatory assets not earning a return on investment of
$232 million
and
$203 million
as of December 31,
2013
and
2012
, respectively, that primarily related to deferred income taxes, 1999 merger costs, a portion of deferred excess energy costs and unrealized loss on regulated derivative contracts.
Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):
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|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Remaining Life
|
|
2013
|
|
2012
|
|
|
|
|
|
|
|
|
Cost of removal
(1)
|
42 years
|
|
$
|
219
|
|
|
$
|
203
|
|
|
Renewable energy program
|
1 year
|
|
24
|
|
|
—
|
|
|
Energy efficiency program
|
1 year
|
|
12
|
|
|
5
|
|
|
Deferred income taxes
|
18 years
|
|
9
|
|
|
10
|
|
|
Deferred energy over collected
|
—
|
|
—
|
|
|
51
|
|
|
Other
|
Various
|
|
16
|
|
|
8
|
|
|
Total regulatory liabilities
|
|
|
$
|
280
|
|
|
$
|
277
|
|
|
|
|
|
|
|
|
|
Reflected as:
|
|
|
|
|
|
|
Current liabilities
|
|
|
$
|
37
|
|
|
$
|
51
|
|
|
Noncurrent liabilities
|
|
|
243
|
|
|
226
|
|
|
Total regulatory liabilities
|
|
|
$
|
280
|
|
|
$
|
277
|
|
|
|
|
|
(1)
|
Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.
|
Deferred Energy
Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN.
Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and is included in the table above as deferred excess energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy over collected. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.
Energy Efficiency Implementation Rates and Energy Efficiency Program Rates
In July 2010, regulations were adopted by the PUCN that authorizes an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN through energy efficiency implementation rates ("EEIR"). As a result, the Company files annually in March to adjust energy efficiency program rates and EEIR for over- or under-collected balances, which are effective in October of the same year.
In March 2013, the Company filed applications with the PUCN for the twelve-month period ended December 31, 2012 to reset EEIR elements. In September 2013, the PUCN issued an order indicating that EEIR revenue should not contribute to the Company earning more than its authorized rate of return. As the Company earned in excess of its authorized rate of return in 2012, the PUCN disallowed approximately
$5 million
in EEIR revenue (including carrying charges) and the Company recorded a charge to operating and maintenance expense on the Consolidated Statements of Operations for the year ended December 31, 2013.
The PUCN's final order approving the MEHC Merger stipulated that the Company, will not seek recovery of any lost revenue for calendar year 2013 and, for calendar year 2014, in an amount that exceeds
50%
of the lost revenue that the Company could otherwise request. As a result, for the year ended December 31, 2013, the Company has not recorded revenue for EEIR and has recorded a regulatory liability of
$5 million
, which is included in current regulatory liabilities on the Consolidated Balance Sheets. On February 28, 2014, the Company filed an application with the PUCN to reset EEIR and energy efficiency program rates. Pursuant to the stipulation, the Company established credits to return EEIR revenue collected in the 2013 calendar year. To effect the merger stipulation, the Company proposed to suspend collection of the EEIR on October 1, 2014, and defer implementation of a new EEIR until January 1, 2015.
FERC Matters
2012 FERC Transmission Rate Case
In October 2012, the Company filed an application with the FERC to revise transmission and ancillary service rates that were last set in 2007 and 2003, respectively. In December 2012, the FERC issued an order which suspended the proposed rate increases until June 1, 2013. Furthermore, as requested in the filing, the FERC accepted two proposed rate decreases effective January 1, 2013. On June 17, 2013, the Company filed an unopposed settlement agreement resolving all issues with the FERC, for approval of rates effective June 1, 2013. The FERC approved the settlement on August 29, 2013. The rate changes under the terms of the settlement agreement result in an overall annual revenue increase of
$2 million
.
2013 FERC Transmission Rate Case
In May 2013, the Company, along with Nevada Power, filed an application with the FERC to establish single system transmission and ancillary service rates. The combined filing requested incremental rate relief of
$17 million
annually to be effective January 1, 2014. On August 5, 2013, the FERC granted the companies' request for a rate effective date of January 1, 2014 subject to refund, and set the case for hearing or settlement discussions. On January 1, 2014, the Company implemented the filed rates in this case subject to refund as set forth in FERC's order. At this time management is unable to determine the final revenue impact of the case.
(7)
Credit Facility
The Company's
$250 million
revolving credit facility expires in 2017, is for general corporate purposes and provides for the issuances of letters of credits. As of December 31, 2013 and 2012, the Company had
no
drawings outstanding and
$6 million
in letters of credit issued on its revolving credit facility. Amounts due under the Company's credit facility are collateralized by the Company's general and refunding mortgage bonds. The rate for outstanding loans under the Company's credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus
0.5%
and the London Interbank Offered Rate ("LIBOR") Base Rate plus
1.0%
) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon the Company's credit rating by Standard & Poor's and Moody's Investors Services. As of December 31, 2013, the Company's applicable base rate margin is
0.125%
and the LIBOR rate margin is
1.125%
. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.
(8) Long-Term Debt
The Company's long-term debt consists of the following, including unamortized premiums and discounts, as of December 31 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Par Value
|
|
2013
|
|
2012
|
|
General and Refunding Mortgage Securities:
|
|
|
|
|
|
|
5.45% Series Q, due 2013
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250
|
|
|
6.000% Series M, due 2016
|
450
|
|
|
453
|
|
|
455
|
|
|
3.375% Series T, due 2023
|
250
|
|
|
250
|
|
|
—
|
|
|
6.750% Series P, due 2037
|
252
|
|
|
259
|
|
|
259
|
|
|
Variable-rate series (2013-0.459% to 0.463%, 2012-0.572 to 0.579%):
|
|
|
|
|
|
|
Pollution Control Revenue Bonds Series 2006A, due 2031
|
58
|
|
|
58
|
|
|
58
|
|
|
Pollution Control Revenue Bonds Series 2006B, due 2036
|
75
|
|
|
75
|
|
|
75
|
|
|
Pollution Control Revenue Bonds Series 2006C, due 2036
|
81
|
|
|
81
|
|
|
81
|
|
|
Capital and financial lease obligations - 3.01% to 8.52%, due through 2054
|
24
|
|
|
24
|
|
|
1
|
|
|
Total long-term debt
|
$
|
1,190
|
|
|
$
|
1,200
|
|
|
$
|
1,179
|
|
|
|
|
|
|
|
|
|
Reflected as:
|
|
|
|
|
|
|
Current liabilities
|
|
|
$
|
1
|
|
|
$
|
250
|
|
|
Noncurrent liabilities
|
|
|
1,199
|
|
|
929
|
|
|
Total long-term debt
|
|
|
$
|
1,200
|
|
|
$
|
1,179
|
|
The consummation of the MEHC Merger also triggered mandatory redemption requirements under financing agreements of the
Company. As a result, the Company offered to purchase
$702 million
of debt at
101%
of par. The tender offer expired in January 2014 with
no
amounts tendered.
In August 2013, the Company issued and sold
$250 million
of its
3.375%
Series T General and Refunding Securities, due 2023. The
$248 million
in net proceeds was used, together with cash on hand, to pay at maturity the
$250 million
principal amount of its
5.45%
Series Q General and Refunding Securities, which matured in September 2013.
Annual Payment on Long-Term Debt
The annual repayments of long-term debt and capital and financial leases for the years beginning January 1, 2014 and thereafter, excluding unamortized premiums and discounts, are as follows (in millions):
|
|
|
|
|
|
|
|
|
2014
|
|
$
|
1
|
|
|
2015
|
|
1
|
|
|
2016
|
|
451
|
|
|
2017
|
|
1
|
|
|
2018
|
|
1
|
|
|
2019 and thereafter
|
|
735
|
|
|
Total
|
|
$
|
1,190
|
|
Utility plant of
$1.5 billion
is subject to the liens of the Company's indentures under which its respective General and Refunding Mortgage Securities are issued.
Capital and Financial Lease Commitments
|
|
|
|
•
|
The Company has master leasing agreements of which various pieces of equipment qualify as capital leases. The remaining equipment is treated as operating leases. Lease terms average
seven
years under the master lease agreement.
|
|
|
|
|
•
|
The ON Line transmission line was placed in-service on December 31, 2013. The Company and Nevada Power have entered into a transmission use agreement with Great Basin Transmission South, LLC's
75%
interest in ON Line. The Company and Nevada Power own the remaining
25%
interest. Refer to Note 5 for additional information. The Company's and Nevada Power's share of the long-term transmission use agreement and ownership interest is split at
5%
and
95%
, respectively. The term is for
41
years with the agreement ending December 31, 2054. Payments began on January 31, 2014.
|
Future cash payments for capital and financial leases as of December 31,
2013
, were as follows (in millions):
|
|
|
|
|
|
|
|
|
2014
|
|
$
|
3
|
|
|
2015
|
|
2
|
|
|
2016
|
|
3
|
|
|
2017
|
|
2
|
|
|
2018
|
|
3
|
|
|
2019 and thereafter
|
|
46
|
|
|
Total minimum lease payments
|
|
59
|
|
|
Less amounts representing interest
|
|
(35
|
)
|
|
Present value of net minimum lease payments
|
|
$
|
24
|
|
|
|
|
|
(9)
|
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, principally related to derivative contracts, that are measured at fair value on the Consolidated Balance Sheets using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:
|
|
|
|
•
|
Level 1 - Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that 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 long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt as of December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
|
Carrying
|
|
Fair
|
|
Carrying
|
|
Fair
|
|
|
Value
|
|
Value
|
|
Value
|
|
Value
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
$
|
1,176
|
|
|
$
|
1,270
|
|
|
$
|
1,178
|
|
|
$
|
1,302
|
|
(10) Other, Net
Other, net as shown on the Consolidated Statements of Operations for the years ended December 31 consists of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Interest and dividend income
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Donations
|
—
|
|
|
(1
|
)
|
|
(2
|
)
|
|
Interest expense on regulatory items
|
(1
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|
Other
|
6
|
|
|
(3
|
)
|
|
(10
|
)
|
|
Total other, net
|
$
|
6
|
|
|
$
|
(4
|
)
|
|
$
|
(16
|
)
|
Income tax expense (benefit) consists of the following for the years ended December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Current – Federal
|
$
|
(2
|
)
|
|
$
|
(7
|
)
|
|
$
|
—
|
|
|
Deferred:
|
|
|
|
|
|
|
Federal
|
38
|
|
|
48
|
|
|
33
|
|
|
State
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
Total deferred
|
36
|
|
|
48
|
|
|
33
|
|
|
|
|
|
|
|
|
|
Investment tax credits
|
(1
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|
Total income tax expense
|
$
|
33
|
|
|
$
|
40
|
|
|
$
|
31
|
|
A reconciliation of the federal statutory income rate to the effective income tax rate applicable to income before income tax expense is as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Federal statutory income tax rate
|
35
|
%
|
|
35
|
%
|
|
35
|
%
|
|
Effects of ratemaking
|
1
|
|
|
(1
|
)
|
|
—
|
|
|
Non-deductible MEHC Merger related expenses
|
1
|
|
|
—
|
|
|
—
|
|
|
Other
|
—
|
|
|
(2
|
)
|
|
(1
|
)
|
|
Effective income tax rate
|
37
|
%
|
|
32
|
%
|
|
34
|
%
|
The net deferred income tax liability consists of the following as of December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
Deferred income tax assets:
|
|
|
|
|
Federal net operating loss and credit carryforwards
|
$
|
61
|
|
|
$
|
61
|
|
|
Employee benefits
|
12
|
|
|
39
|
|
|
Regulatory liabilities
|
9
|
|
|
27
|
|
|
Capital and financial leases
|
8
|
|
|
1
|
|
|
Other
|
40
|
|
|
20
|
|
|
Total deferred income tax assets
|
130
|
|
|
148
|
|
|
|
|
|
|
|
Deferred income tax liabilities:
|
|
|
|
|
Property-related items
|
(441
|
)
|
|
(416
|
)
|
|
Regulatory assets
|
(148
|
)
|
|
(155
|
)
|
|
Capital and financial leases
|
(8
|
)
|
|
(1
|
)
|
|
Other
|
(10
|
)
|
|
(20
|
)
|
|
Total deferred income tax liabilities
|
(607
|
)
|
|
(592
|
)
|
|
Net deferred income tax liability
|
$
|
(477
|
)
|
|
$
|
(444
|
)
|
|
|
|
|
|
|
Reflected as:
|
|
|
|
|
Deferred income taxes - current
|
$
|
48
|
|
|
$
|
22
|
|
|
Deferred income taxes - long-term
|
(525
|
)
|
|
(466
|
)
|
|
Net deferred income tax liability
|
$
|
(477
|
)
|
|
$
|
(444
|
)
|
The following table provides the Company's federal net operating loss and tax credit carryforwards and expiration dates as of December 31, 2013 (in millions):
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
$
|
161
|
|
|
Deferred income taxes on federal net operating loss carryforwards
|
$
|
56
|
|
|
Expiration dates
|
2029-2033
|
|
|
|
|
Other tax credits
|
$
|
5
|
|
|
Expiration dates
|
2014-2033
|
The United States federal jurisdiction is the only significant income tax jurisdiction for NV Energy. In July 2012, the United States Internal Revenue Service and the Joint Committee on Taxation concluded their examination of NV Energy with respect to its United States federal income tax returns for December 31, 2005 through December 31, 2008.
A reconciliation of the beginning and ending balances of the Company's net unrecognized tax benefits is as follows for the years ended December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
|
|
|
|
|
Beginning balance
|
$
|
3
|
|
|
$
|
10
|
|
|
Additions for tax positions of prior years
|
—
|
|
|
2
|
|
|
Reductions for tax positions of prior years
|
—
|
|
|
(9
|
)
|
|
Ending balance
|
$
|
3
|
|
|
$
|
3
|
|
The unrecognized tax benefits relate to tax positions for which ultimate deductibility is highly certain but for which there is uncertainty as to the timing of such deductibility. Recognition of these tax benefits, other than applicable interest and penalties, would not affect the Company's effective income tax rate.
(12) Related Party Transactions
The Company provided electricity and other services to PacifiCorp, an indirect subsidiary of MEHC, of $- million,
$3 million
and
$7 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. PacifiCorp provided electricity to the Company of $- million, $- million and
$1 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively.
The Company provided electricity to Nevada Power of
$1 million
,
$1 million
and
$2 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. The Company purchased electricity from Nevada Power of
$36 million
,
$20 million
and
$22 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. The Company provided intercompany administrative services to Nevada Power of
$22 million
,
$22 million
and
$22 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. Nevada Power provided intercompany administrative services to the Company of
$24 million
,
$20 million
and
$18 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. As of December 31,
2013
and
2012
, the Company's Consolidated Balance Sheets included net amounts due to Nevada Power of
$9 million
and
$1 million
, respectively.
The Company has been provided intercompany administrative and shared facility costs from NV Energy of
$19 million
,
$12 million
and
$10 million
for the years ended December 31,
2013
,
2012
and
2011
, respectively. As of December 31,
2013
and
2012
, the Company's Consolidated Balance Sheets included amounts due to NV Energy of
$28 million
and
$24 million
as of December 31,
2013
and
2012
, respectively.
(13) Retirement Plan and Postretirement Benefits
The Company is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non-Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provide certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of the Company. The Company contributed
$20 million
,
$15 million
and
$25 million
to the Qualified Pension Plan and
$5 million
,
$7 million
and
$1 million
to the Other Postretirement Plans for the years ended December 31, 2013, 2012 and 2011, respectively. The Company did not make any contributions to the Non-Qualified Pension Plans for the years ended December 31,
2013
,
2012
and
2011
. Amounts attributable to the Company were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in AOCI.
Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following as of December 31(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
Qualified Pension Plan:
|
|
|
|
|
Other assets
|
$
|
18
|
|
|
$
|
—
|
|
|
Other long-term liabilities
|
—
|
|
|
(37
|
)
|
|
|
|
|
|
|
Non-Qualified Pension Plans:
|
|
|
|
|
Customer deposits and other
|
(1
|
)
|
|
—
|
|
|
Other long-term liabilities
|
(11
|
)
|
|
(12
|
)
|
|
|
|
|
|
|
Other Postretirement Plans -
|
|
|
|
|
Other long-term liabilities
|
(38
|
)
|
|
(49
|
)
|
(14) Asset Retirement Obligations
The Company estimates its ARO liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons, including plan revisions, inflation and changes in the amount and timing of the expected work.
The Company does not recognize liabilities for AROs for which the fair value cannot be reasonably estimated. Due to the indeterminate removal date, the fair value of the associated liabilities on certain transmission, distribution and other assets cannot currently be estimated, and no amounts are recognized on the Consolidated Financial Statements other than those included in the cost of removal regulatory liability established via approved depreciation rates in accordance with accepted regulatory practices. These accruals totaled
$219 million
and
$203 million
as of December 31, 2013 and 2012, respectively.
The following table presents the Company's ARO liabilities by asset type as of December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
|
|
|
|
|
Evaporative ponds and dry ash landfills
|
$
|
7
|
|
|
$
|
7
|
|
|
Asbestos
|
6
|
|
|
5
|
|
|
Other
|
3
|
|
|
3
|
|
|
Total asset retirement obligations
|
$
|
16
|
|
|
$
|
15
|
|
The following table reconciles the beginning and ending balances of the Company's ARO liabilities for the years ended December 31, (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
|
|
|
|
|
Beginning balance
|
$
|
15
|
|
|
$
|
10
|
|
|
Accretion
|
1
|
|
|
1
|
|
|
Change in estimated costs
|
—
|
|
|
4
|
|
|
Ending balance
|
$
|
16
|
|
|
$
|
15
|
|
Certain of the Company's decommissioning and reclamation obligations relate to jointly-owned facilities, and as such, the Company is committed to pay a proportionate share of the decommissioning or reclamation costs. In the event of a default by any of the other joint participants, the respective subsidiary may be obligated to absorb, directly or by paying additional sums to the entity, a proportionate share of the defaulting party's liability. The Company's estimated share of the decommissioning and reclamation obligations are primarily recorded as ARO liabilities in other long-term liabilities on the Consolidated Balance Sheets.
|
|
|
|
(15)
|
Commitments and Contingencies
|
Commitments
The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheet. Minimum payments as of December 31, 2013 are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 and
|
|
|
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
$
|
94
|
|
|
$
|
96
|
|
|
$
|
98
|
|
|
$
|
100
|
|
|
$
|
77
|
|
|
$
|
585
|
|
|
$
|
1,050
|
|
|
Purchased power - not commercially operable
|
—
|
|
|
—
|
|
|
7
|
|
|
7
|
|
|
7
|
|
|
146
|
|
|
167
|
|
|
Coal and natural gas
|
154
|
|
|
59
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
213
|
|
|
Transportation
|
78
|
|
|
58
|
|
|
30
|
|
|
30
|
|
|
29
|
|
|
108
|
|
|
333
|
|
|
Long-term service agreements
|
5
|
|
|
5
|
|
|
4
|
|
|
4
|
|
|
4
|
|
|
11
|
|
|
33
|
|
|
Capital projects
|
—
|
|
|
3
|
|
|
3
|
|
|
3
|
|
|
3
|
|
|
48
|
|
|
60
|
|
|
Operating leases
|
4
|
|
|
4
|
|
|
2
|
|
|
2
|
|
|
1
|
|
|
34
|
|
|
47
|
|
|
Total commitments
|
$
|
335
|
|
|
$
|
225
|
|
|
$
|
144
|
|
|
$
|
146
|
|
|
$
|
121
|
|
|
$
|
932
|
|
|
$
|
1,903
|
|
Purchased Power
The Company has several contracts for long-term purchase of electric energy which have been approved by the PUCN. The expiration of these contracts range from 2014 to 2039. While the Company is not required to make payment if power is not delivered under these contracts, estimated future payments are included in the tables above. Purchased power includes contracts which meet the definition of a lease. The Company's rent expense for purchase power contracts which met the lease criteria for
2013
,
2012
and
2011
were
$63 million
,
$60 million
and
$63 million
, respectively, and are recorded as cost of fuel, energy and capacity on the Consolidated Statements of Operations.
Purchased Power - Not Commercially Operable
The Company has several contracts for long-term purchase of electric energy in which the facility remains under development. Amounts represent the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.
Coal and Natural Gas
The Company has several long-term contracts for the purchase of coal and natural gas. The expiration of these contracts range from 2014 to 2015.
Transportation
The Company has several long-term contracts for the transport of coal and natural gas. The expiration of these transportation contracts range from 2014 to 2030.
Long-Term Service Agreements
The Company has a long-term service agreement for the performance of maintenance on the Tracy Generating Station. Obligation amounts are based on estimated usage. The service agreements expires in 2020.
Operating Leases
The Company has various non-cancelable operating leases primarily for building, land and equipment. Contract expiration dates range from 2014 to 2103. Rent expense on non-cancelable operating leases totaled
$5 million
for 2013,
$6 million
for 2012 and
$7 million
for 2011.
Environmental Laws and Regulations
The Company is subject to federal, state and local laws and regulations regarding air and water quality, renewable portfolio standards, emissions performance standards, climate change, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.
Valmy Generation Station
In June 2009, 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 Valmy Generating Station located in Valmy, Nevada. The Company co-owns and operates this coal-fueled generating facility. Idaho Power Company owns the remaining
50%
. The Environmental Protection Agency's Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the Environmental Protection Agency relating to the plant. The Company completed its response to the Environmental Protection Agency in December 2009 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 information request.
Legal Matters
The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. The Company is also involved in other kinds of legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.
Newmont Nevada Energy Investment - TS Power Plant
Newmont Nevada Energy Investment, LLC ("Newmont") owns a
203
megawatt coal-fired power plant facility located in Eureka County, NV (the "TS Power Plant") that is interconnected to the Company's transmission system. As a result of system modifications required for the ON Line, Newmont will need to install certain protection equipment at its TS Power Plant. Newmont brought suit against the Company in the Second Judicial District of Nevada (Washoe County) seeking declaratory relief and to enjoin the operation at full capacity of certain equipment (series capacitors) to be installed by the Company for the ON Line project, until such time as Newmont completes the design, fabrication and installation of protection equipment at its power plant to protect its generator from potential adverse effects caused by the operation of the Company's equipment at full capacity. In addition, Newmont's complaint asserted a claim under the parties' interconnection agreement seeking to recover the cost of making the necessary modifications to the TS Power Plant, estimated by Newmont to be
$11 million
.
A hearing on Newmont's motion for a preliminary injunction was held during the week of August 12, 2013, after which the trial court concluded that it would enter an order enjoining the Company from operating its equipment (series capacitors) at full capacity from January 1, 2014 until approximately April 8, 2014, and from approximately June 1, 2014 to June 30, 2014 (or the time Newmont has completed the installation of its protection equipment), so as to allow installation and testing of protection equipment at the TS Power Plant. The district court issued the order on December 17, 2013. Newmont posted the required
$1 million
bond and is undertaking efforts at FERC under the Dispute Resolution provisions of the interconnection agreement. The issue of who is to pay for the protection equipment and its installation was not decided by the district court, and is pending before the FERC in Docket No. EL14-16-000. Management cannot predict the outcome of this matter at this time.
Caughlin Fire
On November 18, 2011, a fire was reported in the hills near Reno, Nevada (the "Caughlin Fire"). In January 2012, the Reno Fire Department issued a report in which they opined that "this fire was most likely the result of an electrical event in the area," and that "something such as a tree branch hitting the power-line" was a likely cause of the fire. The Company is continuing its investigation in the matter.
To date,
six
subrogation lawsuits and
two
individual claimant lawsuits have been filed against the Company in relation to the Caughlin Fire. The subrogation lawsuits have been brought by various insurance companies, and involve similar causes of action (negligence, inverse condemnation, trespass, nuisance, subrogation and strict liability).
One
of the individual claimant lawsuits identifies
six
plaintiffs, while the other individual claimant lawsuit purports to be brought on behalf of a class of similarly affected individuals within the fire perimeter who suffered damage or loss of use of their property as a result of the Caughlin Fire and the evacuation order associated with it.
All of the cases have been consolidated before a single judge in Washoe County, Nevada. The court has not yet entered a scheduling order in this case. At this time, management cannot assess or predict what the impact or outcome of this litigation may be, or what, if any, other litigation may be brought on this matter.
(16)
Supplemental Cash Flow Disclosures
The summary of supplemental cash flow disclosures as of and for the years ended December 31 is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
2012
|
|
2011
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information -
|
|
|
|
|
|
|
Interest paid, net of amounts capitalized
|
$
|
59
|
|
|
$
|
60
|
|
|
$
|
60
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of non-cash investing and financing transactions:
|
|
|
|
|
|
|
Accruals related to property, plant and equipment additions
|
$
|
37
|
|
|
$
|
27
|
|
|
$
|
20
|
|
|
ON Line transmission use financial lease obligation
|
$
|
22
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(17)
Segment Information
The Company has identified
two
reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.
The Company believes presenting gross margin allows the reader to assess the impact of the Company's regulatory treatment and its overall regulatory environment on a consistent basis and is meaningful. Gross margin is calculated as operating revenue less cost of fuel, energy and capacity and natural gas purchased for resale.
The following tables provide information on a reportable segment basis for the years ended December 31 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Electric
|
|
Gas
|
|
Total
|
|
|
Operating revenue
|
|
$
|
747
|
|
|
$
|
106
|
|
|
$
|
853
|
|
|
|
Cost of fuel, energy and capacity
|
|
292
|
|
|
—
|
|
|
292
|
|
|
|
Natural gas purchased for resale
|
|
—
|
|
|
56
|
|
|
56
|
|
|
|
Gross margin
|
|
$
|
455
|
|
|
$
|
50
|
|
|
505
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
|
|
|
|
|
197
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
123
|
|
|
|
Property and other taxes
|
|
|
|
|
|
25
|
|
|
|
Merger-related expenses
|
|
|
|
|
|
20
|
|
|
|
Interest expense, net of allowance for debt funds
|
|
|
|
|
|
60
|
|
|
|
Allowance for equity funds
|
|
|
|
|
|
(2
|
)
|
|
|
Other, net
|
|
|
|
|
|
(6
|
)
|
|
|
Income before income tax expense
|
|
|
|
|
|
$
|
88
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,957
|
|
|
$
|
335
|
|
|
$
|
3,369
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
141
|
|
|
$
|
16
|
|
|
$
|
157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Electric
|
|
Gas
|
|
Total
|
|
|
Operating revenue
|
|
$
|
726
|
|
|
$
|
108
|
|
|
$
|
834
|
|
|
|
Cost of fuel, energy and capacity
|
|
263
|
|
|
—
|
|
|
263
|
|
|
|
Natural gas purchased for resale
|
|
—
|
|
|
62
|
|
|
62
|
|
|
|
Gross margin
(2)
|
|
$
|
463
|
|
|
$
|
46
|
|
|
509
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expenses
|
|
|
|
|
|
190
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
108
|
|
|
|
Property and other taxes
|
|
|
|
|
|
23
|
|
|
|
Interest expense, net of allowance for debt funds
|
|
|
|
|
|
63
|
|
|
|
Allowance for equity funds
|
|
|
|
|
|
(3
|
)
|
|
|
Other, net
|
|
|
|
|
|
4
|
|
|
|
Income before income tax expense
|
|
|
|
|
|
$
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,919
|
|
|
$
|
319
|
|
|
$
|
3,316
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
191
|
|
|
$
|
20
|
|
|
$
|
211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011
|
|
|
|
|
|
|
Natural
|
|
|
|
|
|
|
Electric
|
|
Gas
|
|
Total
|
|
|
Operating revenue
|
|
$
|
716
|
|
|
$
|
173
|
|
|
$
|
889
|
|
|
|
Cost of fuel, energy and capacity
|
|
273
|
|
|
—
|
|
|
273
|
|
|
|
Natural gas purchased for resale
|
|
—
|
|
|
124
|
|
|
124
|
|
|
|
Gross margin
(2)
|
|
$
|
443
|
|
|
$
|
49
|
|
|
492
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expenses
|
|
|
|
|
|
192
|
|
|
|
Depreciation and amortization
|
|
|
|
|
|
106
|
|
|
|
Property and other taxes
|
|
|
|
|
|
23
|
|
|
|
Interest expense, net of allowance for debt funds
|
|
|
|
|
|
67
|
|
|
|
Allowance for equity funds
|
|
|
|
|
|
(3
|
)
|
|
|
Other, net
|
|
|
|
|
|
16
|
|
|
|
Income before income tax expense
|
|
|
|
|
|
$
|
91
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
2,845
|
|
|
$
|
308
|
|
|
$
|
3,216
|
|
(1)
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
$
|
133
|
|
|
$
|
13
|
|
|
$
|
146
|
|
|
|
|
|
|
(1)
|
Certain assets totaling
$77 million
,
$78 million
and
$63 million
for the years ended 2013, 2012 and 2011, respectively, consisting principally of cash and cash equivalents are not included in either the regulated electric or regulated natural gas segments.
|
|
|
|
|
(2)
|
Energy efficiency program costs were reclassified from gross margin to operating and maintenance expenses for presentation purposes.
|
(18) Unaudited Quarterly Operating Results (in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-Month Periods Ended
|
|
|
March 31, 2013
|
|
June 30, 2013
|
|
September 30, 2013
|
|
December 31, 2013
|
|
Regulated electric operating revenue
|
$
|
172
|
|
|
$
|
175
|
|
|
$
|
213
|
|
|
$
|
187
|
|
|
Regulated natural gas operating revenue
|
40
|
|
|
20
|
|
|
14
|
|
|
32
|
|
|
Operating income
|
49
|
|
|
30
|
|
|
58
|
|
|
3
|
|
|
Net income
|
22
|
|
|
11
|
|
|
29
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three-Month Periods Ended
|
|
|
March 31, 2012
|
|
June 30, 2012
|
|
September 30, 2012
|
|
December 31, 2012
|
|
Regulated electric operating revenue
|
$
|
170
|
|
|
$
|
168
|
|
|
$
|
212
|
|
|
$
|
176
|
|
|
Regulated natural gas operating revenue
|
46
|
|
|
20
|
|
|
12
|
|
|
30
|
|
|
Operating income
|
45
|
|
|
35
|
|
|
66
|
|
|
42
|
|
|
Net income
|
19
|
|
|
13
|
|
|
34
|
|
|
18
|
|
