XML 45 R25.htm IDEA: XBRL DOCUMENT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2012

The consolidated financial statements include the accounts of NV Energy, Inc. and its wholly-owned subsidiaries, NPC, SPPC, Sierra Pacific Communications, Lands of Sierra, Inc., NVE Insurance and Sierra Gas Holding Company. All intercompany balances and intercompany transactions have been eliminated in consolidation.

The preparation of 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 statements and the reported amounts of certain revenues and expenses during the reporting period. Actual results could differ from these estimates.

NPC is an operating public utility that provides electric service in Clark County in southern Nevada. The assets of NPC represent approximately 72% of the consolidated assets of NVE at December 31, 2012. NPC provides electricity to approximately 850,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. The consolidated financial statements of NPC include its wholly-owned subsidiary, NEICO.

SPPC is an operating public utility that provides electric service in northern Nevada and previously provided service to northeastern California. SPPC also provides natural gas service in the Reno/Sparks area of Nevada. The assets of SPPC represent approximately 28% of the consolidated assets of NVE at December 31, 2012. SPPC provides electricity to approximately 324,000 customers in an approximate 42,000 square mile service area including western, central and northeastern Nevada, including the cities of Reno, Sparks, Carson City and Elko. On January 1, 2011, SPPC sold its California Assets, as discussed in Note 15, Assets Held for Sale. SPPC also provides natural gas service in Nevada to approximately 153,000 customers in an area of about 800 square miles in the Reno and Sparks areas. The consolidated financial statements of SPPC include the accounts of SPPC's wholly-owned subsidiaries, PPC, PPIC and GPSF-B.

The Utilities' accounts are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

Regulatory Accounting and Other Regulatory Assets

The Utilities' rates are subject to the approval of the PUCN and are designed to recover the cost of providing generation, transmission and distribution services. As a result, the Utilities qualify for the application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC. This statement recognizes that the rate actions of a regulator can provide reasonable assurance of the existence of an asset and requires the deferral of incurred costs that would otherwise be charged to expense where it is probable that future revenue will be provided to recover these costs. The accounting guidance prescribes the method to be used to record the financial transactions of a regulated entity. The criteria for applying the accounting for regulated operations include the following: (i) rates are set by an independent third party regulator; (ii) regulated rates are designed to recover the specific costs of the regulated products or services; and (iii) it is reasonable to assume that rates are set at levels that recovered costs can be charged to and collected from customers. Management periodically assesses whether the requirements for application of regulatory accounting treatment as allowed by the Regulated Operations Topic of the FASC are satisfied.

Regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management believes the existing regulatory assets are probable of recovery either because the Utilities received prior PUCN approval or due to regulatory precedent set for similar circumstances. Included in Note 3, Regulatory Actions, are details of other regulatory assets and liabilities, and their current regulatory treatment.

Equity Carrying Charges

In accordance with various regulatory orders, the Utilities record carrying charges as allowed by the Regulated Operations Topic of the FASC. However, for financial reporting purposes the amounts representing equity carrying charges are not recognized until collected through regulated rates. As of December 31, 2012 and 2011, NPC and SPPC have accumulated approximately $11.1 million and $0.6 million, and $12.7 million and $0.9 million, respectively, of equity related carrying charges that will be recognized into income when the corresponding regulatory assets primarily related to NPC's deferred rate increase, the Lenzie Generating Station and the Utilities' conservation programs are collected through rates. For further information, see Note 3, Regulatory Actions, Other Regulatory Assets table.

Deferred Energy Accounting

Nevada and California statutes permit regulated utilities to adopt deferred energy accounting procedures. However, on January 1, 2011, SPPC sold its California Assets, as disclosed in Note 15, Assets Held for Sale. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased gas, fuel and purchased power.

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 statement of operations but rather is deferred and recorded as an asset on the balance sheet in accordance with the provisions of the Regulated Operations Topic of the FASC. Conversely, a liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs. These excess amounts are reflected in adjustments to rates and recorded as revenue or expense in future time periods, subject to PUCN review.

Nevada law requires the Utilities file annual DEAA applications and provides that the PUCN may not allow the recovery of any costs for purchased fuel or purchased power “that were the result of any practice or transaction that was undertaken, managed or performed imprudently by the electric utility.” Nevada law also specifies that fuel and purchased power costs include all costs incurred to purchase fuel, to purchase capacity and to purchase energy. The Utilities also record and are eligible under the statute to recover a carrying charge on such deferred balances. The Utilities may also file to reset BTERs quarterly, based on the last 12 months fuel and purchased power costs. Additionally, Nevada regulations allow an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Utilities are still required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change. See Note 3, Regulatory Actions for details regarding deferred energy balances.

Energy Efficiency Implementation Rate (EEIR) and Energy Efficiency Program Rate (EEPR)

In July 2010, regulations were adopted by the Legislature 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. As a result, the Utilities file annually in March, to adjust rates and set a clearing rate or EEIR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. In addition, the regulation approved the transition of the recovery for the implementation costs of energy efficiency programs from general rates (filed every 3 years) to recovery through annual rate filings annually in March, to adjust rates and set a clearing rate or EEPR effective in October of the same year for over or under collected balance, similar to the deferred energy mechanism discussed above. See Note 3, Regulatory Actions for details regarding EEIR and EEPR balances

Utility Plant

The cost of additions, including betterments and replacements of units of property, are charged to utility plant. When units of property are replaced, renewed or retired, their cost plus removal or disposal costs, less salvage proceeds, are charged to accumulated depreciation. The cost of current repairs and minor replacements are charged to maintenance expense when incurred, with the exception of long term service agreements. These agreements may have annual payment amounts for repairs which could vary over the life of the agreement between maintenance expense and amounts to be capitalized. To ensure consistency in annual expense for rate making purposes, the amounts to be charged to maintenance expense are smoothed over the life of the contract, with an offset to a regulatory asset or liability account. Amounts prepaid for capital expenditure are recorded in a prepaid asset account.

In addition to direct labor and material costs, certain other direct and indirect costs are capitalized. The indirect construction overhead costs capitalized are based upon the following cost components: the cost of time spent by administrative and supervision employees in planning and directing construction; property taxes; employee benefits including such costs as pensions, postretirement and post-employment benefits, vacations and payroll taxes; and an AFUDC which includes the cost of debt and equity capital associated with construction activity.

Included in Total Utility Property, net, as Electric and Natural Gas Distribution assets are the net carrying values of the remaining meters subject to early retirement under the NV Energize program for NPC and SPPC. In accordance with a PUCN order, the net carrying values are reclassified to a regulatory asset at the time of retirement. NPC and SPPC expect full recovery of the regulatory assets through the Utilities' regulatory proceedings.

Utility Property

NVE, NPC and SPPC's gross utility property and CWIP are divided into the following major classes at December 31 (dollars in millions):

		2012						2011
		NVE		NPC		SPPC		NVE		NPC		SPPC
Electric Generation assets		$	4,766	$	3,706	$	1,060	$	4,791	$	3,724	$	1,067
Electric Transmission assets			1,867		1,189		678		1,853		1,183		670
Electric Distribution assets			4,142		2,886		1,256		4,108		2,874		1,234
Electric General, Intangible plant			685		583		102		659		564		95
Electric CWIP			683		568		115		443		353		90
Natural Gas Distribution assets			341		-		341		312		-		312
Natural Gas General, Intangible plant			13		-		13		3		-		3
Natural Gas CWIP			6		-		6		14		-		14
Common General, Intangible Plant			218		-		218		197		-		197
Common CWIP			18		-		18		31		-		31
	Total Utility Property, Gross	$	12,739	$	8,932	$	3,807	$	12,411	$	8,698	$	3,713

Depreciation

Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC. Depreciation expense is calculated using the straight-line composite method over the estimated remaining service lives of the related properties, which approximates the anticipated physical lives of these assets in most cases. NPC's depreciation provision, as authorized by the PUCN and stated as a percentage of the average depreciable property balances for those years, was approximately 3.22%, 3.04% and 2.99% during 2012, 2011 and 2010, respectively. SPPC's depreciation provision for 2012, 2011 and 2010, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 2.94%, 2.89% and 3.02%, respectively.

The average estimated useful life for each major class of utility property, plant and equipment are as follows:

	Estimated Useful Lives
	NPC	SPPC
Electric Generation	25 to 125 years	25 to 125 years
Electric Transmission	45 to 65 years	50 to 70 years
Electric Distribution	20 to 65 years	30 to 65 years
Gas Distribution	N/A	40 to 70 years
General Plant	5 to 65 years	5 to 65 years

AFUDC

AFUDC represents the cost of borrowed funds and, where appropriate, the cost of equity funds used for construction purposes in accordance with rules prescribed by the FERC and the PUCN. AFUDC is capitalized in the same manner as construction labor and material costs, however, with an offsetting credit to “other income” for the portion representing the cost of equity funds; and as a reduction of interest charges for the portion representing borrowed funds. Recognition of this item as a cost of utility plant is in accordance with established regulatory ratemaking practices. Such practices are intended to permit the Utility to earn a fair return on, and recover in rates charged for utility services, all capital costs. This is accomplished by including such costs in the rate base and in the provision for depreciation. NPC's AFUDC rate used during 2012, 2011 and 2010 were 8.09%, 8.47% and 8.32% respectively. SPPC's AFUDC rates used during 2012, 2011 and 2010 were 7.86% (Electric), 5.15% (Gas) and 7.59% (Common), 7.86% (Electric) and 5.15% (Gas), and 7.85%, respectively. (In 2012 and 2011, separate rates were calculated for common due to different rates of return allowed by PUCN Docket 10-06002 for electric and gas). 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.

Impairment of Long-Lived Assets

NVE, NPC and SPPC evaluate on an ongoing basis the recoverability of its assets for impairments whenever events or changes in circumstance indicate that the carrying amount may not be recoverable as described in the Property, Plant and Equipment Topic of the FASC.

Cash and Cash Equivalents

Cash is comprised of cash on hand and working funds. Cash equivalents consist of high quality investments in money market funds with maturities of 90 days or less and do not have any withdrawal restrictions.

Federal Income Taxes

NVE and the Utilities file a consolidated federal income tax return. Current income taxes are allocated based on NVE's and each Utility's respective taxable income or loss and tax credits as if each Utility filed a separate return.

NVE and the Utilities recognize deferred tax liabilities and assets for the future tax consequences of events that have been included in the financial statements or tax returns. Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets are also recorded for deductions incurred and credits earned that have not been utilized in tax returns filed or to be filed for tax years through the date of the financial statements. Management considers estimates of the amount and character of future taxable income by tax jurisdiction in assessing the likelihood of realization of deferred tax assets. If it is not more likely than not that a deferred tax asset will be realized in its entirety, a valuation allowance is recorded with respect to the portion estimated not likely to be realized.

Tax benefits associated with income tax positions taken, or expected to be taken, in a tax return are recorded only when the more-likely-than-not recognition threshold is satisfied and measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. NVE and the Utilities classify interest and penalties associated with unrecognized tax benefits as interest and other expense, respectively, within the income statement. No interest expense or penalties associated with unrecognized tax benefits have been recorded.

The Utilities reduce rates to reflect the current tax benefits associated with recognizing certain tax deductions sooner than when the expenses are recognized for financial reporting purposes. A regulatory asset is recorded for these amounts to reflect the future increases in income taxes payable that will be recovered from customers when these temporary differences reverse. The Utilities have been fully normalized since 1987. AFUDC-equity is recorded on an after-tax basis. Accordingly, a regulatory asset is recorded when AFUDC-equity is recognized. This regulatory asset reverses as the related plant is depreciated, resulting in an increase to the tax provision.

The Utilities also record regulatory liabilities for obligations to reduce rates charged customers for deferred taxes recovered from customers in prior years at corporate tax rates higher than the current tax rates. The reduction in rates charged customers will occur as the temporary differences resulting in the excess deferred tax liabilities reverse.

Investment tax credits are deferred and amortized over the estimated service lives of the related properties.

Utility, Revenue and Expense Recognition, Policy [Policy Text Block]

Unbilled

Revenues related to the sale of energy are recorded based on meter reads, which occur on a systematic basis throughout a month, rather than when the service is rendered or energy is delivered. At the end of each month, the energy delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenues are calculated. These estimates of unbilled sales and revenues are based on the ratio of billable days versus unbilled days, amount of energy procured and generated during that month, historical customer class usage patterns, line loss and the Utilities' current tariffs. Accounts receivable as of December 31, 2012, included unbilled receivables of $86 million and $50 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2011, included unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively.

Franchise Fees and Universal Energy Charges

NPC and SPPC, as agents for some state and local governments collect from customers franchise fees and universal energy charges levied by the state or local governments on our customers. NPC and SPPC present such fees on a net basis, as such, fees are excluded from revenue and expense.

Asset Retirement Obligations

The Asset Retirement and Environmental Liabilities Topic of the FASC provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. Under the accounting guidance, these liabilities are recognized in other deferred credits and liabilities at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. Accretion of the liabilities due to the passage of time is classified as an operating expense. Retirement obligations associated with long-lived assets included within the scope of the accounting guidance are those for which a legal obligation exists under enacted laws, statutes written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

Management's methodology to assess its legal obligation included an inventory of assets by company, system and components and a review of rights of way and easements, regulatory orders, leases and federal, state and local environmental laws. Management identified a legal obligation to retire generation plant assets specified in land leases for NPC's jointly-owned Navajo Generating Station and the Higgins Generating Station. Provisions of the lease require the lessees to remove the facilities upon request of the lessors at the expiration of the leases. Additionally, management has determined evaporative ponds, dry ash landfills, fuel storage tanks, asbestos and oils treated with Poly Chlorinated Biphenyl to have met the conditional asset retirement obligations as defined in the Asset Retirement and Environmental Liabilities Topic of the FASC.

The following table presents a reconciliation of the beginning and ending aggregate carrying amounts of asset retirement obligation for the years presented below (dollars in thousands):

		NVE				NPC				SPPC
		2012		2011		2012		2011		2012		2011
ARO balance at January 1	$	70,984	$	55,204	$	61,020	$	47,128	$	9,964	$	8,076
Liabilities incurred in current period		-		3,282		-		3,282		-		-
Liabilities settled in current period		-		(6,996)		-		(6,996)		-		-
Accretion expense		4,064		3,866		3,453		3,348		611		518
Revision in estimated cash flows		145		16,391		(4,002)		15,021		4,147		1,370
Gain/Loss on settlement		-		(763)		0		(763)		-		-
ARO balance at December 31	$	75,193	$	70,984	$	60,471	$	61,020	$	14,722	$	9,964

Cost of Removal

In addition to the legal asset retirement obligations booked under the accounting guidance for asset retirement obligations, the Utilities have accrued for the cost of removing non-legal retirement obligations of other electric and gas assets. The amounts of such accruals included in regulatory liabilities in 2012 are approximately $252.6 million and $204.4 million for NPC and SPPC, respectively. In 2011, the amounts were approximately $232.0 million and $189.9 million for NPC and SPPC, respectively.

Variable Interest Entities

NVE and the Utilities continually perform an analysis to determine whether their variable interests give them controlling financial interest in a VIE which would require consolidation. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the following characteristics: a) the power to direct the activities of a VIE that most significantly impact the entity's economic performance, and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. To identify potential variable interests, management reviews 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 defined above, as they primarily lacked the power to direct the activities of the entity, including the ability to operate the generating facilities 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 December 31, 2012, the carrying amount of assets and liabilities in the Utilities' balance sheets that relate to their involvement 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.

PriorPeriodReclassificationAdjustmentDescription

Reclassifications

Financial statement line items for current and long-term risk management liabilities from prior periods have been combined with Other current liabilities and Other deferred credits and liabilities lines to conform with current year presentation. In addition, interest on regulatory items other than deferred charges has been classified from Other income, Other expense to Interest income (expense) on regulatory items. The reclassifications have not affected previously reported reports of operations, statements of financial position or shareholders' equity.

InventoryPolicyTextBlock

Materials, Supplies and Fuel

Generally, materials and supplies include the average cost of transmission, distribution, and generating plant materials. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed. Fuel inventory includes the average cost of coal, natural gas and oil. Fuel is charged to inventory when purchased and then expensed as used in energy costs and recovered by the Utilities through BTER rates approved by the PUCN

DerivativesPolicyTextBlock

Derivatives and Hedging Activities

NVE and the Utilities apply the accounting guidance as required by the Derivatives and Hedging Topic of the FASC. The accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value, and recognize changes in the fair value of the derivative instruments in earnings in the period of change, unless the derivative meets certain defined conditions and qualifies as an effective hedge. The accounting guidance for derivative instruments also provides a scope exception for commodity contracts that meet the normal purchase and sales criteria specified in the standard. The normal purchases and normal sales exception requires, among other things, physical delivery in quantities expected to be used or sold over a reasonable period in the normal course of business. Contracts that are designated as normal purchases and normal sales are accounted for under deferred energy accounting and not recorded on the consolidated balance sheets of NVE and the Utilities at fair value.

Commodity Risk

The energy supply function encompasses the reliable and efficient operation of the Utilities' generation, the procurement of all fuels and power and resource optimization (i.e., physical and economic dispatch) and is exposed to risks relating to, but not limited to, changes in commodity prices. NVE and the Utilities' objective in using derivative instruments is to reduce exposure to energy price risk. Energy price risks result from activities that include the generation, procurement and sale of power and the procurement and sale of natural gas. Derivative instruments used to manage energy price risk from time to time may include: forward contracts, which involve physical delivery of an energy commodity; over-the-counter options with financial institutions and other energy companies, which mitigate price risk by providing the right, but not the requirement, to buy or sell energy related commodities at a fixed price; and swaps, which require the Utilities to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity. These contracts may assist the Utilities reduce the risks associated in volatile electricity and natural gas markets. As of December 31, 2012, the Utilities were not parties to such derivative transactions.

Interest Rate Risk

NVE and the Utilities may enter into interest rate swap agreements to manage existing and future fixed rate interest rate exposure in an effort to lower overall borrowing costs. These transactions are discussed further in Note 6, Long Term Debt, under the respective financing agreements as applicable

AccountingChangesAndErrorCorrectionsTextBlock

NVE and SPPC Balance Sheet Corrections

During the fourth quarter of 2012, SPPC discovered an error in its calculation of deferred income taxes and the related income tax regulatory asset specific to amounts associated with AFUDC-equity resulting in an understatement of both regulatory assets and deferred tax liabilities of the same amount. NVE and SPPC have corrected the December 31, 2011 consolidated balance sheets to increase the regulatory assets and deferred income tax liabilities by $32.0 million, which did not result in a change to net assets. NVE and SPPC's Statements of Comprehensive Income, Equity and Cash Flow were not impacted. December 31, 2011 and 2010 amounts for Assets, in Note 2, Segment Information, for both NVE and SPPC were also adjusted by $32.0 million and $30.6 million, respectively. Additionally, December 31, 2011 amounts for Regulatory assets, Income taxes, in the Other Regulatory Assets tables for both NVE and SPPC in Note 3, Regulatory Actions, and related deferred tax amounts in Note 9, Income Taxes (Benefits), have been adjusted. Management has concluded that this correction is immaterial

ReceivablesPolicyTextBlock

Allowance for Uncollectible Accounts

The allowance for uncollectible accounts is based on the Utilities' estimate of the collectability of amounts owed by customers. This estimate is primarily derived from historical write-off trends applied to the previous five months of revenue and accounts receivable balances. The Utilities' also have the ability to assess deposits on customers who have delayed payments or who are deemed to be a credit risk. Accounts receivable are shown on the balance sheet net of the allowance for uncollectible accounts