The significant accounting policies for both utility and non-utility operations are as follows:

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 73% of the consolidated assets of NVE at December 31, 2011. NPC provides electricity to approximately 840,000 customers in the communities of Las Vegas, North Las Vegas, Henderson, Searchlight, Laughlin and adjoining areas, including Nellis Air Force Base. Service is also provided to the Department of Energy's Nevada Test Site in Nye County. 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 27% of the consolidated assets of NVE at December 31, 2011. SPPC provides electricity to approximately 323,000 customers in an approximate 50,000 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 16, Assets Held for Sale. SPPC also provides natural gas service in Nevada to approximately 152,000 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.

The Utilities' rates are subject to the approval of the PUCN, and in the case of SPPC during 2010, the CPUC, 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. However, on January 1, 2011, SPPC sold its California Assets, as disclosed in Note 16, Assets Held for Sale. 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.

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, 2011 and 2010, NPC and SPPC have accumulated approximately $12.7 million, and $.9 million, and $12.0 million and $1.1 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, Lenzie and the Utilities' conservation programs are collected through rates. For further information, see Note 3, Regulatory Actions, Other Regulatory Assets table.

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 16, 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. In 2011, the Legislature passed Assembly Bill 215 which allows 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 will still be 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 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing 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 PUCN opened Docket No. 09-07016 to amend and adopt the regulation. The regulation was adopted by the Legislature on July 22, 2010. 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.

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, post retirement and post employment benefits, vacations and payroll taxes; and an AFUDC which includes the cost of debt and equity capital associated with construction activity.

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

		2011						2010
		NVE		NPC		SPPC		NVE		NPC		SPPC
Electric Generation assets		$	4,791	$	3,724	$	1,067	$	4,056	$	2,991	$	1,065
Electric Transmission assets			1,853		1,183		670		1,840		1,183		657
Electric Distribution assets			4,108		2,874		1,234		4,019		2,820		1,199
Electric General, Intangible plant			659		564		95		657		558		99
Electric CWIP			473		353		121		906		825		81
Natural Gas Distribution assets			312		-		312		303		-		303
Natural Gas General, Intangible plant			3		-		3		3		-		3
Natural Gas CWIP			14		-		14		2		-		2
Common Assets			197		-		197		191		-		191
	Total Utility Property, Gross	$	12,411	$	8,698	$	3,713	$	11,977	$	8,377	$	3,600

As part of the cost of constructing utility plant, the Utilities capitalize 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 2011, 2010 and 2009 were 8.47%, 8.32% and 8.57% respectively. SPPC's AFUDC rates used during 2011, 2010 and 2009 were 7.86% (Electric) and 5.15% (Gas), 7.85%, 7.96% respectively. (In 2011, separate rates were calculated for electric and gas due to different rates of return allowed by PUCN Docket 10-06002). 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.

Substantially all of the Utilities' plant is subject to the ratemaking jurisdiction of the PUCN or the FERC, and, in the case of SPPC, the CPUC. 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 3.04%, 2.99% and 2.74% during 2011, 2010 and 2009, respectively. SPPC's depreciation provision for 2011, 2010 and 2009, as authorized by the PUCN and stated as a percentage of the average cost of depreciable property, was approximately 2.89%, 3.02% and 3.07% 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

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

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.

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, 2011, include unbilled receivables of $93 million and $51 million for NPC and SPPC, respectively. Accounts receivable as of December 31, 2010, include unbilled receivables of $89 million and $60 million for NPC and SPPC, respectively.

As adopted by the PUCN in July 2010, the Utilities were authorized to recover lost revenue that was attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. The Utilities accounted for the effects of such regulation in accordance with FASC 980-605-25, Alternative Revenue Programs which permits the recording of revenue if all of the following conditions are met: (1) the program allows for automatic adjustment of future rates, (2) the amount of revenues is objectively determinable and probable of recovery, and (3) the additional revenues will be collected within 24 months. See Note 3, Regulatory Actions, EEIR, for further discussion on the recording of such revenues.

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 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
		2011		2010		2011		2010		2011		2010
ARO balance at January 1	$	55,202	$	55,968	$	47,126	$	48,320	$	8,076	$	7,648
Liabilities incurred in current period		3,282		-		3,282		-		-		-
Liabilities settled in current period		(6,996)		(34)		(6,996)		(34)		-		-
Accretion expense		3,866		3,877		3,348		3,383		518		494
Revision in estimated cash flows		16,391		(4,606)		15,021		(4,540)		1,370		(66)
Gain/Loss on settlement		(763)		(3)		(763)		(3)		-		-
ARO balance at December 31	$	70,982	$	55,202	$	61,018	$	47,126	$	9,964	$	8,076

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 2011 are approximately $232.0 million and $189.9 million for NPC and SPPC, respectively. In 2010, the amounts were approximately $208.8 million and $173.5 million.

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, 2011, 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.

NPC and SPPC, as agents for some state and local governments collect from customers franchise fees and universal energy charges (UEC) 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.

In January 2010, the FASB amended the Fair Value Measurements and Disclosure Topic as reflected in the FASB Accounting Standards Codification for recurring and nonrecurring fair value measurements. NVE and the Utilities adopted this amendment on January 1, 2010. The new accounting guidance adds requirements for disclosures about transfers into and out of Levels 1 and 2 and separate disclosures about purchases, sales, issuances, and settlements relating to Level 3 measurements. It also clarifies existing fair value disclosures about the level of disaggregation and about inputs and valuation techniques used to measure fair value. In addition, the accounting update amends guidance on employers' disclosures about postretirement benefit plan assets to require disclosures by classes of assets instead of by major categories of assets. The amendment is effective for NVE and the Utilities as of January 1, 2010, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward activity in Level 3 fair value measurements. Those disclosures are effective for NVE and the Utilities as of January 1, 2011. The adoption of this guidance did not have a significant impact on the disclosure requirements for NVE and the Utilities.

In May 2011, the FASB amended existing requirements for measuring fair value and for disclosing information about fair value measurements. This revised guidance results in a consistent definition of fair value, as well as common requirements for measurement and disclosure of fair value information between U.S. GAAP and International Financial Reporting Standards (IFRS). In addition, the amendments set forth enhanced disclosure requirements with respect to recurring Level 3 measurements, nonfinancial assets measured or disclosed at fair value, transfers between levels in the fair value hierarchy, and assets and liabilities disclosed but not recorded at fair value. The amendment is to be applied prospectively and is effective for NVE and the Utilities as of the beginning of a fiscal reporting year that begins after December 15, 2011, for all public entities. The adoption of this guidance will not have a significant impact on the disclosure requirements for NVE and the Utilities.

In June 2011, the FASB amended the Comprehensive Income Topic as reflected in the FASB Accounting Standards Codification for presentation of comprehensive income. The amendment does not change the amount of comprehensive income reported, but rather establishes a standard for the reporting and presentation of comprehensive income providing an entity the option to present the total of comprehensive income, the components of net income, and the components of other comprehensive income (including reclassification adjustments) either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendment is to be applied retrospectively to all reporting periods presented and is effective as of the beginning of a fiscal reporting year that begins after December 15, 2011, for all public entities. NVE and the Utilities have elected to early adopt this amendment presenting total comprehensive income in a single continuous statement for each of the three years in the period ended December 31, 2011. This amendment changes the presentation of our financial statements but does not affect the calculation of net income, comprehensive income or earnings per share.

In December 2011, the FASB deferred the effective date of a portion of the June 2011 amendment related to the presentation of reclassification adjustments out of accumulated other comprehensive income. The effective date was deferred to allow the Board time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income for all periods presented. As of December 31, 2011 NVE and the Utilities have not recorded reclassification adjustments subject to this amendment as such NVE and the Utilities do not expect the deferral to have a material impact on the presentation of our financial statements.

In November 2011, the FASB amended the Balance Sheet Topic as reflected in the FASB Accounting Standards Codification to enhance current disclosures regarding offsetting (netting) of assets and liabilities on the face of the financial statements. The amendment requires an entity to disclose information about offsetting and related arrangements to enable users of the financial statements to understand the effect of those arrangements on its financial position. The scope of this amendment would include derivatives, sale and repurchase agreements and reverse sale and repurchase agreements, and securities borrowing and securities lending arrangements. The amendment is to be applied retrospectively to all periods presented and is effective for all reporting periods beginning on or after January 1, 2013. NVE and the Utilities will evaluate the effects on this amendment but do not expect the amendment to have a material impact on our disclosure requirement.