form10-q.htm

Foreign steel, iron, or manufactured good

Domestic steel, iron, or manufactured good

Foreign steel, iron, or manufactured good

Domestic steel, iron, or manufactured good

The following table shows the fair value of the open derivative positions recorded on the consolidated balance sheets of NVE, NPC and SPPC and the related regulatory assets and/or liabilities that did not meet the normal purchase and normal sales exception criteria as required by the Derivatives and Hedging Topic of the FASC. Due to regulatory accounting treatment under which the utilities operate, regulatory assets and liabilities are established to the extent that derivative gains and losses are recoverable or payable through future rates, once realized. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on derivative transactions until the period of settlement (dollars in millions):

	March 31, 2010									December 31, 2009
Derivative Contracts	Level 2									Level 2
	NVE			NPC			SPPC			NVE			NPC			SPPC

Risk management assets- current	$	0.1		$	0.1		$	0.0		$	15.7		$	12.7		$	3.0
Risk management assets- noncurrent(1)		3.8			3.8			0.0			4.8			4.2			0.6
Total risk management assets		3.9			3.9			0.0			20.5			16.9			3.6

Risk management liabilities- current		106.1			79.2			26.9			66.9			39.1			27.8
Risk management liabilities- noncurrent		4.0			3.2			0.8			2.2			1.1			1.1
Total risk management liabilities		110.1			82.4			27.7			69.1			40.2			28.9

Risk management regulatory assets/liabilities – net (2)	$	(106.2	)	$	(78.5	)	$	(27.7	)	$	(48.6	)	$	(23.3	)	$	(25.3	)

(1)

Included in Risk management assets – noncurrent at March 31, 2010, is a $3.8 million cumulative gain for interest rate swaps with the offset recorded in the risk management regulatory assets/liabilities amounts above.

(2)

When amount is negative it represents a risk management regulatory asset, when positive it represents a risk management regulatory liability. For the three months ended March 31, 2010, NVE, NPC and SPPC would have recorded a loss of $57.6 million, $55.2 million, and $2.4 million, respectively; however, as permitted by the Regulated Operations Topic of the FASB Accounting Standards Codification, NVE and the Utilities deferred these gains and losses, which are included in the risk management regulatory assets/liabilities amounts above.

As a result of the nature of operations and the use of mark-to-market accounting for certain derivatives that do not meet the normal purchase and normal sales exception criteria, mark-to-market fair values will fluctuate. The Utilities’ cannot predict these fluctuations, but the primary factors that cause changes in the fair values are the number and size of the Utilities’ open derivative positions with their counterparties and the changes in market prices. The increase in risk management liabilities as of March 31, 2010, as compared to December 31, 2009, is primarily due to a decrease in natural gas prices relative to contract prices compared to natural gas prices at December 31, 2009.

The following table shows the commodity volume for our open derivative contracts related to natural gas contracts (amounts in millions):

	March 31, 2010						December 31, 2009
	Commodity Volume (MMBTU)						Commodity Volume (MMBTU)
	NVE		NPC		SPPC		NVE		NPC		SPPC

Commodity volume assets- current		0.4		0.3		0.1		47.1		40.7		6.4
Commodity volume assets- noncurrent		0.0		0.0		0.0		10.3		7.6		2.7
Total commodity volume of assets		0.4		0.3		0.1		57.4		48.3		9.1

Commodity volume liabilities- current		84.4		64.6		19.8		51.7		32.7		19.0
Commodity volume liabilities- noncurrent		5.6		4.7		0.9		7.8		5.3		2.5
Total commodity volume of liabilities		90.0		69.3		20.7		59.5		38.0		21.5

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NOTE 7. RETIREMENT PLAN AND POST-RETIREMENT BENEFITS

A summary of the components of net periodic pension and other post-retirement costs for the three months ended March 31 follows. This summary is based on a December 31, measurement date (dollars in thousands):

NVE, Consolidated	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	4,727		$	4,709		$	617		$	577
Interest cost		10,718			11,036			2,184			2,637
Expected return on plan assets		(11,069	)		(9,290	)		(1,556	)		(1,508	)
Amortization of prior service cost		(448	)		(448	)		(972	)		(171	)
Amortization of net loss		3,777			6,894			1,085			1,273
Settlement loss		-			-			-			84

Net periodic benefit cost	$	7,705		$	12,901		$	1,358		$	2,892

The average percentage of NVE net periodic costs capitalized during 2010 and 2009 were 33.20% and 36.24% respectively.

NPC	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	2,392		$	2,393		$	353		$	310
Interest cost		5,023			5,270			619			607
Expected return on plan assets		(5,362	)		(4,462	)		(567	)		(509	)
Amortization of prior service cost		(433	)		(433	)		236			289
Amortization of net loss		1,764			3,298			300			287
Settlement loss		-			-			-			19

Net periodic benefit cost	$	3,384		$	6,066		$	941		$	1,003

The average percentage of NPC net periodic costs capitalized during 2010 and 2009 were 35.93% and 40.23% respectively.

SPPC	Pension Benefits						Other Post-Retirement Benefits
	2010			2009			2010			2009

Service cost	$	2,004		$	2,061		$	245		$	251
Interest cost		5,389			5,471			1,547			2,014
Expected return on plan assets		(5,431	)		(4,580	)		(961	)		(977	)
Amortization of prior service cost		(26	)		(26	)		(1,213	)		(465	)
Amortization of net loss		1,969			3,425			777			978
Settlement loss		-			-			-			65

Net periodic benefit cost	$	3,905		$	6,351		$	395		$	1,866

The average percentage of SPPC net periodic costs capitalized during 2010 and 2009 were 33.70% and 35.03% respectively.

In the quarter ended March 31, 2010, the company made a contribution to the pension plan in the amount of $10 million, allocated to the 2010 plan year. Additional funding may be required for both the pension and other post-retirement benefits plans in 2010 in order to meet the minimum funding requirements under the Pension Protection Act of 2006; however, the amounts will not be known until asset values and market conditions can be evaluated at the time of the contribution. Currently, NVE expects to fund approximately $40 million to the pension plan in 2010.

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NOTE 8. COMMITMENTS AND CONTINGENCIES

Environmental

NPC

NEICO

NEICO, a wholly-owned subsidiary of NPC, owns property in Wellington, Utah, which was the site of a coal washing and load-out facility. The site has a reclamation estimate supported by a bond of approximately $5 million with the Utah Division of Oil and Gas Mining, which management believes is sufficient to cover reclamation costs. Management is continuing to evaluate various options including reclamation and sale.

SPPC

Valmy Generating Station

On June 22, 2009, SPPC received a request for information from the EPA—Region 9 under Section 114 of the Federal Clean Air Act requesting current and historical operations and capital project information for SPPC’s Valmy Generating Station located in Valmy, Nevada. SPPC co-owns and operates this coal-fired plant. Idaho Power Company owns the remaining 50%. The EPA’s Section 114 information request does not allege any incidents of non-compliance at the plant, and there have been no other new enforcement-related proceedings that have been initiated by the EPA relating to the plant. SPPC completed its response to the EPA in December 2009 and will continue to monitor developments relating to this Section 114 request. SPPC cannot predict the impact, if any, associated with this info rmation request.

Other Environmental Matters

NVE and the Utilities are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. As disclosed in Note 13, Commitments and Contingencies of the Notes to Financial Statements, Environmental, in the 2009 Form 10-K, NPC was subject to various environmental proceedings which were settled as of December 31, 2009. NPC continues to comply with these environmental commitments. As of March 31, 2010, environmental expenditures did not change materially from those disclosed in the 2009 Form 10-K.

Litigation Contingencies

NPC and SPPC

Peabody Western Coal Company

NPC owns an 11% interest in the Navajo Generating Station which is located in Northern Arizona and is operated by Salt River. Other participants in the Navajo Generating Station are Arizona Public Service Company, Los Angeles Department of Water and Power and Tucson Electric Power Company (together with Salt River and NPC, the “Navajo Joint Owners”). NPC also owns a 14% interest in the Mohave Generating Station which is located in Laughlin, Nevada and was operated by Southern California Edison (SCE) prior to the time it became non-operational on December 31, 2005.

Royalty Claim

On October 15, 2004, the Navajo Generating Station’s coal supplier, Peabody Western Coal Co. (Peabody WC), filed a complaint against the Navajo Joint Owners in Missouri State Court in St. Louis, alleging, among other things, a declaration that the Navajo Joint Owners are obligated to reimburse Peabody WC for any royalty, tax or other obligations arising out of a lawsuit that the Navajo Nation filed against Salt River, several Peabody Coal Company entities (including Peabody WC and collectively referred to as “Peabody”) and SCE in June 1999 in the U.S. District Court for the District of Columbia (DC Lawsuit).

The Navajo Joint owners were first served in the Missouri lawsuit in January 2005. The operating agent for the Navajo Generating Station, Salt River, defended the suit on behalf of the Navajo Joint Owners. In July 2008, the Court dismissed all counts against NPC, two without prejudice to their possible refiling at a later date. NPC is unable to predict whether any liability may arise from any of these matters, including from the ultimate outcome of the DC Lawsuit.

NPC is not a party to the DC Lawsuit although, as noted above, it is a participant in both the Navajo Generating Station and the Mohave Generating Station. The DC Lawsuit consists of various claims relating to the renegotiations of coal royalty and lease agreements and alleges, among other things, that the defendants obtained a favorable coal royalty rate for the lease agreements under which Peabody mines coal for both the Navajo Generating Station and the Mohave Generating Station by improperly influencing the

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outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. Initially, the DC Lawsuit sought $600 million in damages, treble damages, and punitive damages of not less than $1 billion, and the ejection of defendants from all possessory interests and Navajo Tribal lands arising out of the primary coal lease In July 2001, the U.S. District Court dismissed all claims against Salt River. The action had been stayed since October, 2004 until March, 2008, when the U.S. District Court lifted the stay. On April 12, 2010, the Navajo Nation amended their complaint; it no longer seeks treble damages. The Court ordered substantial completion of factual discovery (except for certain depositions) by July 15, 2010. Management cannot predict the timing or outcome of a decision on this matter.

SPPC

Farad Dam

SPPC sold four hydro generating units, (10.3 MW total capacity), located in Nevada and California, for $8 million to TMWA in June 2001. The Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. The current estimate to rebuild the diversion dam, if management decides to proceed, is approximately $20 million. Under the terms of the contract with TMWA, SPPC is not entitled to receive the proceeds of sale relating to Farad unless and until it has reconstructed the Farad facility in a manner reasonably acceptable to TMWA or, alternatively SPPC assigns its casualty loss claim to TMWA and TMWA is reasonably satisfied regarding its rights with respect to such claim.

SPPC filed a claim with the insurers Hartford Steam Boiler Inspection and Insurance Co. and Zurich-American Insurance Company (collectively, the “Insurers”) for the Farad flume and Farad Dam. In December 2003, SPPC sued the Insurers in the U.S. District Court for the District of Nevada on a coverage dispute relating to potential rebuild costs for Farad Dam. The case went to trial before the Court in April 2008. On September 30, 2008, the Court ruled that SPPC was not time barred from reconstructing Farad Dam, and has coverage for the full rebuild costs, subject to coverage sub-limits set forth in the insurance policies. The Court further ruled that SPPC is entitled to recover $4 million for costs incurred to date on Farad Dam and that SPPC shall have three years to rebuild the da m from the date of the Court’s decision. In the event Farad Dam is not rebuilt, the Court determined SPPC would be entitled to actual cash value of approximately $1.3 million. SPPC has requested the court to reconsider the cash value to reflect rebuild costs. On July 10, 2009, the District Court declined SPPC’s request to reconsider the cash value and further ordered that the three year period to replace the dam commences as of July 10, 2009 (Order). In early August 2009, SPPC appealed the District Court’s $1.3 million cash value determination with the U.S. Court of Appeals for the Ninth Circuit. Subsequently, in August 2009, the Insurers appealed the District Court’s insurance coverage decision with the Ninth Circuit. All briefings have been completed. It is expected that the Ninth Circuit will order arguments on the appeal either late in 2010 or early to mid 2011.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which, in the opinion of management, is expected to have a significant impact on their financial positions, results of operations or cash flows.

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NOTE 9. EARNINGS PER SHARE (NVE)

The difference, if any, between basic EPS and diluted EPS is due to potentially dilutive common shares resulting from stock options, the employee stock purchase plan, performance and restricted stock plans, and the non-employee director stock plan. Due to the net loss for the three months ended March 31, 2010 and 2009, these items are anti-dilutive and diluted EPS for the period is computed using the weighted average number of shares outstanding before dilution.

The following table outlines the calculation for earnings per share (EPS):

		Three Months Ended March 31,
		2010			2009
Basic and Diluted EPS
Numerator ($000)

	Net loss	$	(1,721	)	$	(22,244	)

Denominator (1)
	Weighted average number of common shares outstanding		234,858,642			234,331,044

Per Share Amounts

	Net loss per share - basic and diluted	$	(0.01	)	$	(0.09	)

(1)

The denominator does not include stock equivalents for stock options, restricted and performance shares issued under the executive long-term incentive plan, shares issuable under the non-employee director stock plan and the employee stock purchase plan shares for the periods ending March 31, 2010 and 2009, due to their anti-dilutive effect in the calculation of diluted EPS. The amounts that would otherwise be included in the calculation for the periods ending March 31, 2010 and 2009 are 585,241 and 284,221 shares, respectively. The denominator also does not include stock equivalents for all the options issued under the non-qualified stock option plan for the years ended March 31, 2010 and 2009, due to conversion prices being higher than market prices for all periods. Under this plan, an additional 714,6 28 and 1,072,678 shares, respectively, would be included in each of these periods if the conditions for conversion were met.

NOTE 10. ASSETS HELD FOR SALE

In April 2009, SPPC entered into an agreement to sell its California electric distribution and generation assets to CalPeco. Based on the terms of the purchase agreement, SPPC will receive proceeds that include a premium on current net rate base assets as of the closing date, plus a working capital adjustment. Net rate base assets include utility plant in service, net and deferred credits and other liabilities. Such proceeds are expected to be above the current book value of the related net assets. The sale is expected to close in 2010, and is subject to obtaining necessary federal and state regulatory approvals.

Below are the major classes of assets and liabilities held for sale and presented in the consolidated balance sheets as of March 31, 2010 and December 31, 2009 (dollars in millions):

Assets	March 31, 2010		December 31, 2009
Utility Plant in Service	$	190.1	$	188.6
Less: Accumulated depreciation		54.2		55.4
Utility Plant in Service, net		135.9		133.2
CWIP		3.9		4.6
Other current assets		8.7		8.6
Deferred Charges		0.6		0.8

Assets Held for Sale	$	149.1	$	147.2

Liabilities
Deferred Credits and Other Liabilities	$	26.6	$	25.7
Liabilities Held for Sale	$	26.6	$	25.7

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NOTE 11. SUBSEQUENT EVENTS

On May 4, 2010, NVE’s BOD declared a quarterly cash dividend of $0.11 cents per share payable on June 16, 2010 to common shareholders of record on June 1, 2010.

On May 4, 2010, NPC and SPPC declared a dividend to NVE of $26 million and $12 million, respectively.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

Forward-Looking Statements and Risk Factors

The information in this Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

Words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan” and “objective” and other similar expressions identify those statements that are forward-looking. These statements are based on management’s beliefs and assumptions and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such statements, factors that could cause the actual results of NVE, NPC or SPPC; (NPC and SPPC are collectively referred to as the “Utilities”) to differ materially from those contemplated in any forward-looking statement include, among others, the following:

(1)

economic conditions both nationwide and regionally, including availability and cost of credit, inflation rates, monetary policy, unemployment rates, customer bankruptcies, weaker housing markets, a decrease in tourism, particularly in southern Nevada, and cancelled or deferred hotel construction projects, each of which affect customer growth, customer collections, customer demand and usage patterns;

(2)

changes in the rate of industrial, commercial and residential growth in the service territories of the Utilities, including the effect of weaker housing markets, increased unemployment, and energy conservation programs, which could affect the Utilities’ ability to accurately forecast electric and gas demand;

(3)	changes in environmental laws or regulations, including the imposition of limits on emissions of carbon dioxide or other greenhouse gases from electric generating facilities, which could significantly affect our existing operations as well as our construction program;

(4)

unfavorable or untimely rulings in rate or other cases filed or to be filed by the Utilities with the PUCN, including the periodic applications to recover costs for fuel and purchased power that have been recorded by the Utilities in their deferred energy accounts, and deferred natural gas costs recorded by SPPC for its gas distribution business;

(5)

employee workforce factors, including changes in and renewals of collective bargaining unit agreements, strikes or work stoppages, the ability to adjust the labor cost structure to changes in growth within our service territories, and potential difficulty in recruiting new talent to mitigate losses in critical knowledge and skill areas due to an aging workforce;

(6)

the ability and terms upon which NVE, NPC and SPPC will be able to access the capital markets to support their requirements for working capital, including amounts necessary for construction and acquisition costs and other capital expenditures, as well as to finance deferred energy costs, particularly in the event of: continued volatility in the global credit markets, changes in availability and cost of capital either due to market conditions or as a result of unfavorable rulings by the PUCN, a downgrade of the current debt ratings of NVE, NPC or SPPC, and/or interest rate fluctuations;

(7)	whether the Utilities can procure and/or obtain sufficient renewable energy sources in each compliance year to satisfy the Portfolio Standard in the State of Nevada;

(8)

unseasonable or severe weather, drought, threat of wildfire and other natural phenomena, which could affect the Utilities’ customers’ demand for power, could seriously impact the Utilities’ ability and/or cost to procure adequate supplies of fuel or purchased power, and could affect the amount of water available for electric generating plants in the Southwestern U.S., and could have other adverse effects on our business;

(9)

whether the Utilities will be able to continue to obtain fuel and power from their suppliers on favorable payment terms and favorable prices, particularly in the event of unanticipated power demands (for example, due to unseasonably hot weather), suspension of a hedging program, physical availability, sharp increases in the prices for fuel (including increases in long-term transportation costs) and/or power, or a ratings downgrade;

(10)

wholesale market conditions, including availability of power on the spot market and the availability to enter into gas financial hedges with creditworthy counterparties, which affect the prices the Utilities have to pay for power as well as the prices at which the Utilities can sell any excess power;

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(11)

whether the Nevada Supreme Court's January 28, 2010 ruling in Great Basin Water Network v. Nevada State Engineer could impact some of NVE's pending water appropriation applications and could impact the pending water appropriation applications of other third parties, which, respectively, could have an adverse effect on the Utilities' water rights and/or the water supply necessary for the operation of the Utilities' generating units, and, with respect to the pending water appropriation applications of third parties, may affect the water supply to the Utilities' service territories, which could have an adverse impact on future growth and customer usage patterns;

(12)	whether the Utilities will be able to continue to pay NVE dividends under the terms of their respective financing and credit agreements and limitations imposed by the Federal Power Act;

(13)	whether the Utilities will be able to integrate the new advanced metering system with their billing and other computer information systems and whether the technologies and equipment will perform as expected, and in all other respects, meet operational, commercial and regulatory requirements;

(14)

construction risks, such as delays in permitting, changes in environmental laws, difficulty in securing adequate skilled labor, cost and availability of materials and equipment (including escalating costs for materials, labor and environmental compliance due to timing delays and other economic factors which may affect vendor access to capital), equipment failure, work accidents, fire or explosions, business interruptions, possible cost overruns, delay of in-service dates, and pollution and environmental damage;

(15)

the discretion of NVE's BOD regarding NVE's future common stock dividends based on the BOD periodic consideration of factors ordinarily affecting dividend policy, such as current and prospective financial condition, earnings and liquidity, prospective business conditions, regulatory factors, and restrictions in NVE's and the Utilities' agreements;

(16)	further increases in the unfunded liability or changes in actuarial assumptions, the interest rate environment and the actual return on plan assets for our pension plan, which can affect future funding obligations, costs and pension plan liabilities;

(17)	the effect that any future terrorist attacks, wars, threats of war or pandemics may have on the tourism and gaming industries in Nevada, particularly in Las Vegas, as well as on the national economy in general;

(18)	changes in tax or accounting matters or other laws and regulations to which NVE or the Utilities are subject;

(19)	the effect of existing or future Nevada, California or federal legislation or regulations affecting electric industry restructuring, including laws or regulations which could allow additional customers to choose new electricity suppliers or change the conditions under which they may do so;

(20)

changes in the business or power demands of the Utilities’ major customers, including those engaged in gold mining or gaming, which may result in changes in the demand for services of the Utilities, including the effect on the Nevada gaming industry of the opening of additional gaming establishments in California, other states and internationally; and

(21)	unusual or unanticipated changes in normal business operations, including unusual maintenance or repairs.

Other factors and assumptions not identified above may also have been involved in deriving these forward-looking statements, and the failure of those other assumptions to be realized, as well as other factors, may also cause actual results to differ materially from those projected. NVE, NPC and SPPC assume no obligation to update forward-looking statements to reflect actual results, changes in assumptions or changes in other factors affecting forward-looking statements.

NOTE REGARDING RELIANCE ON STATEMENTS IN OUR CONTRACTS

In reviewing the agreements filed as exhibits to this Quarterly Report on Form 10-Q, please remember that they are filed to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about NVE, the Utilities or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to the agreement if those statements prove to be inaccurate;
•	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
•	may apply standards of materiality in a way that is different from what may be viewed as material to investors; and

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•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

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EXECUTIVE OVERVIEW

Management’s Discussion and Analysis of Financial Condition and Results of Operations explains the general financial condition and the results of operations of NVE and its two primary subsidiaries, NPC and SPPC, collectively referred to as the “Utilities” (references to “we,” “us” and “our” refer to NVE and the Utilities collectively), and includes the following:

●	For each of NVE, NPC and SPPC:

	§	Results of Operations
	§	Analysis of Cash Flows
	§	Liquidity and Capital Resources

●	Regulatory Proceedings (Utilities)

NVE’s Utilities operate three regulated business segments which are NPC electric, SPPC electric and SPPC natural gas. The Utilities are public utilities engaged in the generation, transmission, distribution and sale of electricity and, in the case of SPPC, sale and distribution of natural gas. Other operations consist mainly of unregulated operations and the holding company operations. The Utilities are the principal operating subsidiaries of NVE and account for substantially all of NVE’s assets and revenues. NVE, NPC and SPPC are separate filers for SEC reporting purposes and as such this discussion has been divided to reflect the individual filers (NVE, NPC and SPPC), except for discussions that relate to all three entities or the Utilities.

NVE incurred a net loss of $1.7 million for the three months ended March 31, 2010 compared to a net loss of $22.2 million for the same period in 2009. The increase in consolidated gross margin and the reduction in net loss of approximately $21 million is primarily due to increased rates as a result of NPC’s GRC, which was effective beginning July 1, 2009.

The Utilities are regulated by the PUCN and, for the California electric service territory of SPPC, the CPUC, with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to generation, distribution and transmission operations. The FERC has jurisdiction under the Federal Power Act with respect to wholesale rates, service, interconnection, accounting, and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service. As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities’ revenues and operating income are subject to fluctuations during the year due to impacts that seasonal weather, rate changes, and customer usage patterns have on demand for electric energy and resources. NPC is a summer peaking utility experiencing its highest retail energy sales in response to the demand for air conditioning. SPPC’s electric system peak typically occurs in the summer, while its gas business typically peaks in the winter. The variations in energy usage due to varying weather, customer growth and other energy usage patterns necessitates a continual balancing of loads and resources and purchases and sales of energy under short and long term contracts. As a result, the prudent management and optimization of available resources has a direct effect on t he operating and financial performance of the Utilities. Additionally, the timely recovery of purchased power and fuel costs, and other costs, and the ability to earn a fair return on investments are essential to the operating and financial performance of the Utilities.

2010 and Beyond Objectives and Challenges

In 2010, management’s key objectives will remain focused on implementing our three part strategy of energy efficiency and conservation programs for our customers, purchase and development of renewable energy projects and construction of generating facilities and expansion of transmission capability. Another key objective will be to obtain PUCN approval of NPC’s IRP and to file SPPC’s IRP. The approval of NPC’s IRP will enable us to fulfill our three part strategy by increasing the dollars spent on DSM projects, implementing our ASD initiative, approval of the ON Line transmission line, which will connect the northern and southern service area and also provide greater access to renewable energy resources. However, due to the economic uncertainty in Nevada, NVE’s execution o f the three part strategy will be a significant challenge. Another challenge will be to further broaden our access to capital to fund the three-part strategy and maintain sufficient liquidity.

Economic Conditions

Although the economy in the U.S. is starting to show signs of recovery from the recession, Nevada continues to struggle. As of March 2010, the unemployment rate in Nevada was 13.4%, up 2.8% from a year ago. As of January 2010, taxable sales have declined 8.1% and gaming revenues decreased 3.2%, while visitor volume increased slightly by 1.6% compared to a year ago January 2009.

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Tourism and gaming remain southern Nevada’s leading industries, driving construction activity, the housing market and employment in the region, and together comprising one of NPC’s largest classes of customers. As of March 2010, unemployment in the Las Vegas area was 13.8%, up 3.2% from a year ago. In addition to employment, management continues to monitor hotel room additions and the hotel/motel occupancy rate in Las Vegas as signs of future growth in customers and customer usage. As of February 2010, the hotel/motel occupancy rate in Las Vegas has decreased approximately 5.0% from a year ago. In 2010, room growth is expected to increase by 2.7% and then slow to 0.1% in 2011. The increase in room growth for 2010 is primarily due to The Cosmopolitan Resort & Casino, which is expected to add approximately 3,000 rooms to Las Vegas. Gaming properties in southern Nevada are experiencing financial problems, including difficulties meeting debt payments, bankruptcies and delays or termination of construction projects which may further decrease the projected growth in rooms or offset any increases. In southern Nevada, construction activity, another leading indicator, has seen a decrease in the number of commercial permits while residential permits have remained relatively flat.

SPPC’s service territory, which consists primarily of Washoe County, has also been affected by the recessionary environment. Unemployment in Washoe County was at 13.2% as of March 2010, up 2.0% from a year ago. Taxable sales decreased 4.8%, and gaming revenues decreased 8.7% as of January 2010 compared to the same period in 2009. Other economic conditions affecting Nevada include the national decrease in real estate market activity which makes it more difficult for individuals and businesses to sell their properties in order to relocate to Nevada.

As the Utilities’ service territories continue to endure economically, management will continue to place a significant emphasis on evaluating the foregoing economic indicators and their effect on various interrelated factors including, but not limited to:

•	customer growth;
•	customer usage;
•	revenues;
•	load factors;
•	future capital projects and capital requirements;
•	managing operating and maintenance expenses within projected revenue growth without compromising safety, reliability and efficiency;
•	our liquidity and ability to access capital markets;
•	collections on accounts receivable;
•	counterparty risk; and
•	workforce reduction.

Management cannot predict when economic recovery may occur in Nevada, but expects that the Nevada economy will continue to struggle for the next several years. As such, a significant challenge for us will be to manage costs, while remaining steadfast in carrying out our three part strategy of the energy supply plan which includes energy efficiency and conservation programs; purchase and development of renewable energy projects and expansion of traditional generating capacity and transmission capability to move energy throughout the state. In response to this challenge, the three part strategy will become more focused on projects that will allow us to leverage existing assets, improve transmission capabilities which is necessary for the Utilities to meet their Portfolio Standard, discussed below, further develop t he ASD initiative, which will allow us to reduce our cost structure and future capital expenditures and effectively contain capital and operating costs. Effective capital and operating cost containment began during 2009 by the reduction and delay of capital expenditures and implementation of severance programs as discussed further in Note 17, Severance Programs, of the Notes to Financial Statements in the 2009 Form 10-K.

Three Part Strategy

Beginning in 2007, NVE embarked on a three part energy supply strategy to manage resources against our load by encouraging energy efficiency and conservation programs, the purchase and development of renewable energy projects, construction of generating facilities, and expansion of transmission capability in an effort to reduce our reliance on purchased power.

Energy Efficiency and Conservation Programs

Over the past two years, the Utilities invested approximately $120 million in energy efficiency and conservation. The Utilities expect to invest approximately $63 million during 2010, of which $35.6 million is pending approval before the PUCN in NPC’s IRP. Hearings are scheduled to begin in May 2010. The final amount may be adjusted by numerous factors, such as the economy, the impact of federal government stimulus legislation, and the performance of existing and new programs.

In addition, NVE has been awarded a $138 million grant in stimulus funding from the DOE specifically for NVE’s $301 million ASD initiative. The ASD initiative will provide NVE with the Smart Grid infrastructure necessary to enable widespread use of smart meters, enabling customers to more directly manage their energy usage. The ASD initiative entails the deployment of a

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delivery mechanism that sets a new, more advanced foundation for NVE’s demand response and energy efficiency and conservation programs.

The agreement between NVE and the DOE was signed in March 2010. As a result of executing the contract, the Utilities have begun a pilot program with the ultimate goal of completing the installation of approximately 1.5 million smart meters throughout the entire state of Nevada by 2012, making Nevada one of the first states to implement a statewide Smart Grid Plan.

NVE has submitted a plan in NPC’s 2009 IRP filed in February 2010 with a proposed company investment of $95 million and a demand response program budget of $16 million. SPPC’s investment of $50 million is expected to be submitted in its next IRP amendment filing. An additional $2 million within NVE’s capital budget covers energy management system upgrades in 2010.

Additional key objectives include management of energy risk, environmental matters, and regulatory filings, and to further broaden access to capital.

Purchase and Development of Renewable Energy Projects

NPC’s current capital budget includes investing approximately $112.3 million for renewable energy projects through 2012. In 2008, NPC entered into contracts to either jointly construct or pursue the development of projects using wind, geothermal and recovered energy generation technologies, and in 2009 received PUCN approval to purchase the output from three geothermal plants expanded by 32 MW, an additional 49 MW of output from two new solar projects, and a landfill gas project to be completed in 2010/2011. In 2010, the Utilities will continue development of these renewable energy projects, conduct additional requests for proposals for renewable energy, and explore other opportunities to add to their supplies of renewable energy and associated PECs.

During the first quarter of 2010, NPC submitted seven long-term renewable energy PPAs to the PUCN for approval. The seven contracts include two solar projects totaling 160 MW, three geothermal projects totaling 130 MW, one wind project totaling 150 MW and one landfill gas project with a capacity of 3 MW. Together the projects total 443 MW.

In addition, two short-term renewable energy PPAs were entered into. One was signed in December 2009 with renewable energy deliveries commencing at that time and the other agreement was signed in February 2010 with deliveries commencing in April 2010.

In April 2010, NPC and SPPC filed their joint Annual Compliance Report with the PUCN. SPPC reported that it met the Portfolio Standard for total PECs and the solar requirements of the Portfolio Standard. NPC reported that it met the solar requirement of the Portfolio Standard, but did not meet the Portfolio Standard requirement for total PECs. However, NPC expects that the shortfall in 2009 will be offset with credits earned in 2010.

Construction of Generating Facilities and Expansion of Transmission Capabilities

In 2010, NPC will continue the construction of the 500 MW (nominally rated) natural gas generating station at the existing Harry Allen Generating Station, which is expected to be operational by summer 2011. In addition, the Utilities will continue to optimize the operations of their existing generating assets.

In NPC’s IRP filed in February 2010 and SPPC’s 8th Amendment to its 2007 IRP filed in March 2010, the Utilities are requesting approval of ON Line, a 500 kV transmission line from the proposed Robinson Summit Substation near Ely, Nevada to the existing Harry Allen Substation located northeast of Las Vegas, Nevada at an aggregate cost of approximately $509 million. The preferred plan is a joint ownership proposal (“Joint Project”) of the line among NPC, SPPC and Great Basin Transmission, LLC (“GBT”), an affiliate of LS Power. The Utilities have entered into a Memorandum of Understanding and Term Sheet (“MOU”) for the Joint Project that contem plates two phases of development. The Joint Project is subject to negotiation of definitive agreements and other conditions, such as PUCN and FERC approvals. The alternative to the Joint Project, also filed in NPC’s IRP and SPPC’s 8th Amendment to its 2007 IRP, is for the Utilities’ to self build the ON Line. In addition to connecting NVE’s northern service territory with its service territory in southern Nevada, the ON Line would also provide access to isolated renewable energy resources in parts of northern and eastern Nevada, which would further advance the Utilities’ ability in meeting its Portfolio Standard, discussed above.

Further Broaden Access to Capital

A significant focus in 2010 will again be to generate sufficient cash from operations to meet operating needs and contribute to capital projects by managing recovery of deferred fuel and purchased power costs, reducing regulatory lag in recovery of costs and controlling costs. Maintaining or improving the Utilities credit ratings will be essential to negotiating favorable financing terms, and will continue to be a significant focus in 2010. Depending on the approval of NPC’s IRP, significant amounts of capital may be necessary to fund prospective construction projects, as discussed further under NVE’s Liquidity and Capital Resources in the 2009 Form 10-K. Additionally, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel and purchased power in a

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timely manner, the Utilities may need to issue additional debt to support their operating costs or delay capital expenditures. Management may be required to meet such financial obligations with a combination of internally generated funds, the use of the Utilities’ revolving credit facilities, the issuance of long-term debt, and/or the issuance of equity by NVE. As such, the ability to issue new debt or equity securities on favorable terms will be a significant focus in 2010. In April 2010, NPC and SPPC entered into new revolving credit facilities for $600 million and $250 million, respectively, which expire in April 2013 to replace their credit facilities expiring in November 2010.

NV ENERGY, INC.

RESULTS OF OPERATIONS

NV Energy, Inc. and Other Subsidiaries

NVE (Holding Company)

The operating results of NVE primarily reflect those of NPC and SPPC, discussed later. The holding company’s (stand alone) operating results included approximately $9.4 million of long term debt interest costs for each of the three months ended March 31, 2010 and 2009, respectively.

As of March 31, 2010, NPC had paid $27 million in dividends to NVE and SPPC had paid $13 million in dividends to NVE. On May 4, 2010, NPC and SPPC declared a dividend to NVE of $26 million and $12 million, respectively.

Other Subsidiaries

Other Subsidiaries of NVE, except for NPC and SPPC, did not contribute materially to the consolidated results of operations of NVE.

ANALYSIS OF CASH FLOWS

Cash flows decreased during the three months ended March 31, 2010 compared to the same period in 2009 due to a decrease in cash from financing activities and an increase in cash used by investing activities, partially offset by an increase in cash from operating activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to increased revenues as a result of the rate increase in NPC’s GRC. Also contributing to the increase were higher payments to vendors and pension plan funding in the first quarter of 2009, a reduction in spending for conservation programs and other regulated activities and the timing of interest payments. These increases were partially offset by a reduction in BTER rates charged to customers and the timing of property tax payments.

Cash Used By Investing Activities. Cash used by investing activities increased mainly due to continuing construction at the Harry Allen Generating Station. This increase was partially offset by the slowdown in construction for infrastructure.

Cash From Financing Activities. Cash from financing activities decreased due to a reduction in draws on the Utilities revolving credit facilities.

LIQUIDITY AND CAPITAL RESOURCES (NVE CONSOLIDATED)

Overall Liquidity

NVE’s consolidated operating cash flows are primarily derived from the operations of NPC and SPPC. The primary source of operating cash flows for the Utilities is revenues (including the recovery of previously deferred energy costs and natural gas costs) from sales of electricity and, in the case of SPPC, natural gas. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and interest. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcomes, and economic conditions.

Available Liquidity as of March 31, 2010 (in millions)
	NVE		NPC		SPPC
Cash and Cash Equivalents	$	10.6	$	34.8	$	28.5
Balance available on Revolving Credit Facilities (1)(2)		N/A		344.3		316.2

	$	10.6	$	379.1	$	344.7

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(1)	NPC’s and SPPC’s balances as of March 31, 2010 reflect amounts available under their $589 million and $332 million revolving credit facilities, respectively. In April 2010, NPC and SPPC entered into new revolving credit facilities with a capacity of $600 million and $250 million, respectively. See NPC and SPPC Financing Transactions.
(2)	As of May 4, 2010, NPC and SPPC had approximately $285.0 million and $208.5 million available under their revolving credit facilities which includes reductions for hedging transactions and letters of credits, as discussed under NPC’s and SPPC’s Financing Transactions.

NVE and the Utilities attempt to maintain their cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, the Utilities may use their revolving credit facilities, in order to meet their liquidity needs. Alternatively, depending on the usage of their revolving credit facilities, the Utilities may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NVE and the Utilities have no significant debt maturities in 2010. Significant debt maturities in 2011 are limited to NPC’s $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of May 4, 2010, NPC has borrowed approximately $221 million on its $600 million revolving credit facility, and SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NVE and the Utilities anticipate that they will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy, and the use of their revolving credit facilities. Furthermore, in order to fund long-term capital requirements, NVE and the Utilities will likely use a combination of internally generated funds, the Utilities’ revolving credit facilities, the issuance of long-term debt and/or equity and in the case of the Utilities capital contributions from NVE. However, if energy costs rise at a rapid rate and the Utilities do not recover the cost of fuel, purchased power and operating costs in a timely manner or the Utilities were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters, the amount of liquidity available to the Utilities could be significantly less. In order to maintain sufficient liquidity, NVE and the Utilities may be required to delay capital expenditures, re-finance debt or issue equity at NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter and the Utilities utilization of their revolving credit facilities may be limited.

The Utilities credit ratings on their senior secured debt remain at investment grade (see Credit Ratings below). However, disruptions in the banking and capital markets not specifically related to NVE or the Utilities may affect their ability to access funding sources or cause an increase in the interest rates paid on newly issued debt.

As of May 4, 2010, NVE has approximately $21.4 million payable of debt service obligations remaining for 2010, which it intends to pay through dividends from subsidiaries. (See “Factors Affecting Liquidity-Dividends from Subsidiaries” below).

NVE designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NVE has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in NVE’s 2009 Form 10-K. However, in April 2010, the Utilities entered into new revolving credit facilities, as discussed under their respective sections, Financing Transactions.

Factors Affecting Liquidity

Effect of Holding Company Structure

As of March 31, 2010, NVE (on a stand-alone basis) has outstanding debt and other obligations including, but not limited to: $63.7 million of its unsecured 7.803% Senior Notes due 2012; $191.5 million of its unsecured 6.75% Senior Notes due 2017; and $230 million of its unsecured 8.625% Senior Notes due 2014.

Due to the holding company structure, NVE’s right as a common shareholder to receive assets of any of its direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiary by its creditors. Therefore, NVE’s debt obligations are effectively subordinated to all existing and future claims of the creditors of NPC and SPPC and its other subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities and guarantee holders.

As of March 31, 2010, NVE, NPC, SPPC and their subsidiaries had approximately $5.6 billion of debt and other obligations outstanding, consisting of approximately $3.8 billion of debt at NPC, approximately $1.3 billion of debt at SPPC and approximately $485 million of debt at the holding company and other subsidiaries. Although NVE and the Utilities are parties to agreements that

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limit the amount of additional indebtedness they may incur, NVE and the Utilities retain the ability to incur substantial additional indebtedness and other liabilities.

Dividends from Subsidiaries

Since NVE is a holding company, substantially all of its cash flow is provided by dividends paid to NVE by NPC and SPPC on their common stock, all of which is owned by NVE. Since NPC and SPPC are public utilities, they are subject to regulation by state utility commissions, which impose limits on investment returns or otherwise impact the amount of dividends that the Utilities may declare and pay.

In addition, certain agreements entered into by the Utilities set restrictions on the amount of dividends they may declare and pay and restrict the circumstances under which such dividends may be declared and paid. As a result of the Utilities’ credit rating on their senior secured debt at investment grade by S&P and Moody’s, these restrictions are suspended for as long as the debt remains investment grade by both rating agencies. In addition to the restrictions imposed by specific agreements, the Federal Power Act prohibits the payment of dividends from “capital accounts.” Although the meaning of this provision is unclear, the Utilities believe that the Federal Power Act restriction, as applied to their particular circumstances, would not be construed or applied by th e FERC to prohibit the payment of dividends for lawful and legitimate business purposes from current year earnings, or in the absence of current year earnings, from other/additional paid-in capital accounts. If, however, the FERC were to interpret this provision differently, the ability of the Utilities to pay dividends to NVE could be jeopardized.

Credit Ratings

NVE, NPC and SPPC are currently rated by three Nationally Recognized Statistical Rating Organizations (NRSRO’s): Fitch, Moody’s and S&P. The senior secured debt of NPC and SPPC is rated investment grade by these three rating organizations. As of March 31, 2010, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NVE	Sr. Unsecured Debt	BB-	Ba3	BB
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

*Investment grade

S&P’s and Moody’s rating outlook for NVE, NPC and SPPC is Stable. Fitch’s rating outlook for NVE, NPC and SPPC is Positive.

A security rating is not a recommendation to buy, sell or hold securities. Security ratings are subject to revision and withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating.

Energy Supplier Matters

With respect to NPC’s and SPPC’s contracts for purchased power, NPC and SPPC purchase and sell electricity with counterparties under the WSPP agreement, an industry standard contract that NPC and SPPC use as members of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC and SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $57.5 million payment or obligation to NPC. No amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as required by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion.

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Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC and SPPC use several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes, which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical ga s supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of March 31, 2010, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit rating downgrades was approximately $30.6 million. Of this amount, approximatel y $22.9 million would be required if NPC’s Senior Unsecured ratings are downgraded from their current level and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

Financial Gas Hedges

The Utilities enter into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under NPC’s and SPPC’s Financing Transactions, the Utilities shall reduce their availability under the Utilities’ revolving credit facilities is reduced for negative mark-to-market positions on hedging contracts with counterparties who are lenders under the revolving credit facilities provided that the reduction of availability under the revolving credit facilities shall at no time be less than 50% of the total commitments then in effect under the credit facilities. As of May 4, 2010, the reduction to NPC’s and SPPC’s revolving credit facilities were $79.3 million and $25.2 million, based on mark-to-market values as of April 30, 2010. Currently, the Utilities only have hedging contracts with counterparties who are also lenders on the revolving credit facilities; however, future contracts entered into with non-lenders may require the Utilities to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, the Utilities have suspended their hedging program, and as such, expect their exposure to negative mark-to-market hedging transactions to decline.

Ability to Issue Debt

NV Energy, Inc.

Certain debt of NVE (holding company) places restrictions on debt incurrence, liens and dividends, unless, at the time the debt is incurred, the ratio of cash flow to fixed charges for NVE’s (consolidated) most recently ended four quarter period on a pro forma basis is at least 2 to 1. Under this covenant restriction, as of March 31, 2010, NVE (consolidated) would be allowed to incur up to $1.6 billion of additional indebtedness, assuming an interest rate of 7%. The amount of additional indebtedness allowed would likely be impacted if there is a change in current market conditions or material change in our financial condition.

Notwithstanding this restriction, under the terms of the debt, NPC and SPPC would still be permitted to incur a combined total of up to $500 million in indebtedness and letters of credit under their respective revolving credit facilities. As of March 31, 2010, the combined total outstanding indebtedness and letters of credit under their respective revolving credit facilities was approximately $261 million not including any reductions for negative mark-to-market transactions. See NPC’s and SPPC’s Ability to Issue Debt sections for further discussion of the Utilities’ limitations on ability to issue debt.

If the applicable series of debt is upgraded to investment grade by both Moody’s and S&P, these restrictions will be suspended and will no longer be in effect so long as the applicable series of Notes remain investment grade by both Moody’s and S&P (see Credit Ratings above).

Cross Default Provisions

None of the Utilities’ financing agreements contains a cross-default provision that would result in an event of default by that Utility upon an event of default by NVE or the other Utility under any of their respective financing agreements. Certain of NVE’s financing agreements, however, do contain cross-default provisions that would result in event of default by NVE upon an event of default by the Utilities under their respective financing agreements. In addition, certain financing agreements of each of NVE and the Utilities provide for an event of default if there is a failure under other financing agreements of that entity to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones

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relating to a failure to pay other indebtedness) provide for a cure period of 30-60 days from the occurrence of a specified event, during which time NVE or the Utilities may rectify or correct the situation before it becomes an event of default.

NEVADA POWER COMPANY

RESULTS OF OPERATIONS

NPC incurred a net loss of $12.3 million for the three months ended March 31, 2010 compared to a net loss of $35.2 million for the same period in 2009.

As of March 31, 2010, NPC had paid $27 million in dividends to NVE. On May 4, 2010, NPC declared an additional dividend of $26 million.

Gross margin is presented by NPC in order to provide information that management believes aids the reader in determining how profitable the electric business is at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is a key factor utilized by management in its analysis of its business.

NPC believes presenting gross margin allows the reader to assess the impact of NPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which NPC calculates as operating revenues less energy costs, provides a measure of income available to support the other operating expenses of NPC. For reconciliation to operating income, see Note 2, Segment Information, of the Condensed Notes to Financial Statements. 60; Gross margin changes based on such factors as general base rate adjustments (which are required to be filed by statute every three years) and reflect NPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

The components of gross margin were (dollars in thousands):

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Operating Revenues	$	426,960	$	436,529		-2.2	%

Energy Costs:
Fuel for power generation		156,115		154,062		1.3	%
Purchased power		71,227		88,206		-19.2	%
Deferred energy - net		19,463		38,190		-49.0	%
	$	246,805	$	280,458		-12.0	%


Gross Margin	$	180,155	$	156,071		15.4	%

Gross margin increased in the first quarter of 2010, compared to the same period in 2009, primarily due to an increase in BTGR revenue as a result of NPC’s 2008 GRC, effective July 1, 2009. Partially offsetting the increase was a change in customer usage patterns which may be attributable to economic conditions and conservation programs and decreased transmission revenue as well as revenue associated with renewable energy programs.

The causes for significant changes in specific lines comprising the results of operations for NPC for the respective years ended are provided below (dollars in thousands except for amounts per unit).

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Operating Revenue

	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year
Operating Revenues:
Residential	$	196,593	$	191,370		2.7	%
Commercial		94,269		96,794		-2.6	%
Industrial		119,648		128,039		-6.6	%
Retail revenues		410,510		416,203		-1.4	%
Other		16,450		20,326		-19.1	%
Total Operating Revenues	$	426,960	$	436,529		-2.2	%

Retail sales in thousands of MWhs		4,086		4,121		-0.8	%

Average retail revenue per MWh	$	100.47	$	101.00		-0.5	%

NPC’s retail revenues decreased for the three months ended March 31, 2010 as compared to the same period in 2009. The decrease in retail revenues is primarily due to the decrease in commercial and industrial revenues partially offset by the increase in residential retail revenue.

Commercial and Industrial retail revenues decreased primarily due to decreases in rates. Winter rates for time-of-use customers decreased as a result of NPC’s 2008 GRC, effective July 1, 2009. Also contributing to the decrease in rates were NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2009 Form 10-K). These decreases were offset by a slight increase in the number of customers. The average number of commercial and industrial customers increased by 1.6% and 0.1%, respectively.

Residential retail revenues increased primarily due to increases in rates as a result of NPC’s 2008 GRC, with increases effective July 1, 2009, partially offset by decreased rates as a result of NPC’s various BTER quarterly cases and deferred energy cases (See Note 3, Regulatory Actions of the Notes to the Financial Statements in the 2009 Form 10-K). The overall rate increase was offset by decreased customer usage due to changes in customer usage patterns and by a 0.4% decrease in the average number of residential customers.

Electric Operating Revenues – Other decreased compared to the same period in 2009. The decrease is primarily due to the expiration of a significant transmission agreement with Calpine Energy Services and decreases in sales for resale.

Energy Costs

Energy Costs include Fuel for Generation and Purchased Power. Energy costs are dependent upon several factors which may vary by season or period. As a result, NPC’s usage and average cost per MWh of fuel for generation versus purchased power to meet demand can vary significantly. Factors that may affect energy costs include, but are not limited to:

•		Weather
•		Generation efficiency
•		Plant outages
•		Total system demand
•		Resource constraints
•		Transmission constraints
•		Natural gas constraints
•		Long-term contracts; and
•		Mandated power purchases

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	Three Months Ended March 31, 2010
					Change from
	2010		2009		Prior Year
Energy Costs
Fuel for Generation	$	156,115	$	154,062		1.3	%
Purchased Power	$	71,227	$	88,206		-19.2	%
Energy Costs	$	227,342	$	242,268		-6.2	%

MWhs
Fuel for Generation (in thousands)		3,431		3,607		-4.9	%
Purchased Power (in thousands)		857		735		16.6	%
Total MWhs		4,288		4,342		-1.2	%

Average cost per MWh
Average fuel cost per MWh of Generated Power	$	45.50	$	42.71		6.5	%
Average cost per MWh of Purchased Power	$	83.11	$	120.01		-30.7	%
Average Cost per MWh	$	53.02	$	55.80		-5.0	%

Energy Costs decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to a decrease in hedging costs and a slight decrease in total system demand, partially offset by higher natural gas prices. The average cost per MWh for energy costs decreased primarily due to decreased hedging costs.

Fuel for generation costs increased primarily due to a change in method of allocating electric tolling option expense between fuel for generation and purchased power which had no impact on gross margin or operating income. Also contributing to the increase was an increase in the cost of natural gas prices. Partially offsetting these increases were decreased hedging costs and a decrease in volume due to an outage at the Higgins Generating Station.

·	Purchased power costs decreased primarily due to the change in method of allocating electric tolling option expense, as discussed above, and decreased hedging costs, slightly offset by an increase in volume.

Deferred Energy - Net

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Deferred energy - net	$	19,463	$	38,190		-49.0	%

Deferred energy – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates, the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates, the difference is recognized as an increase in costs. Deferred energy – net also includes the current amortization of fuel and purchased power costs previously deferred. Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements for further detail of deferred energy balances.

Amounts for the three months ended March 31, 2010 and 2009 include amortization of deferred energy related primarily to the reinstatement of deferred energy and Western Energy Crisis rate cases of $8.2 million and $8.2 million, respectively; and an over-collection of amounts recoverable in rates of $11.3 million in 2010 and $30.0 million in 2009.

Other Operating Expenses

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Other operating expense	$	67,880	$	70,193		-3.3	%
Maintenance expense	$	17,019	$	27,534		-38.2	%
Depreciation and amortization	$	55,101	$	52,363		5.2	%

Other operating expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses and in 2009 higher legal costs; partially offset by higher outside consulting fees.

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Maintenance expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to planned maintenance outages that occurred in 2009 at the Clark, Reid Gardner and Silverhawk Generating Stations.

Depreciation and amortization increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to environmental upgrades and the completion of various distribution and transmission projects.

Interest Expense

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Interest expense (net of AFUDC-debt)	$	53,356	$	55,043		-3.1	%

Interest expense decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to lower interest on variable rate debt, credit facility balances, and the partial redemption of Series 1997A in December 2009. Also contributing to the decrease were lower interest on taxes, customer deposits, and the expiration in 2009 of amortization of costs related to debt issues and redemptions.

Partially offsetting this decrease was higher interest on long term debt related to the issuance of the following debt:

·	$125 million Series U General and Refunding Mortgage Notes in January 2009; and
·	$500 million Series V General and Refunding Mortgage Notes in March 2009.

Other Income (Expense)

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Interest income (expense) on regulatory items	$	(31	)	$	1,853			-101.7	%
AFUDC-equity	$	5,362		$	5,621			-4.6	%
Other income	$	2,583		$	2,342			10.3	%
Other expense	$	(1,132	)	$	(3,207	)		-64.7	%

Interest income (expense) on regulatory items decreased for the three months ended March 31, 2010 compared to the same period in 2009 due to over-collected deferred energy balances. See Note 3, Regulatory Actions, for further details of deferred energy balances.

AFUDC-equity decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to completion of various construction partially offset by construction at the Harry Allen Generating Station.

Other income increased for the three months ended March 31, 2010 compared to the same period in 2009 due to several items, none of which are individually material.

Other expense decreased for the three months ended March 31, 2010 compared to the same period in 2009 primarily due to costs recorded in 2009 for permits.

ANALYSIS OF CASH FLOWS

Cash From Operating Activities. The increase in cash from operating activities was primarily due to increased revenues as a result of the rate increase in NPC’s 2008 GRC, prepayment of taxes in 2009, reduced funding for pension plans and a reduction in spending for conservation programs and other regulated activities. These increases were partially offset by a reduction in BTER rates charged to customers, the timing of payments for property taxes and higher payments to vendors.

Cash Used By Investing Activities. Cash used by investing activities increased primarily due to ongoing construction at the Harry Allen Generating Station.

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Cash From Financing Activities. Cash from financing activities decreased primarily due to a reduction in draws on the revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

NPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on NPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome, and economic conditions.

Available Liquidity as of March 31, 2010 (in millions)
	NPC
Cash and Cash Equivalents	$	34.8
Balance available on Revolving Credit Facility (1)(2)		344.3

	$	379.1

(1)	NPC’s balance as of March 31, 2010 reflects amounts available under NPC’s $589 million revolving credit facility. In April 2010 NPC entered into a new revolving credit facility with a capacity of $600 million. See Financing Transactions below.
(2)	As of May 4, 2010, NPC had approximately $285.0 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.

NPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, NPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, NPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

NPC has no significant debt maturities in 2010. NPC’s significant debt maturities in 2011 are limited to its $350 million 8.25% General and Refunding Notes, Series A, which mature on June 1, 2011. As of May 4, 2010, NPC has borrowed approximately $221 million on its $600 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

NPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including recovery of deferred energy, and the use of its revolving credit facility. Furthermore, in order to fund long term capital requirements, NPC will likely use a combination of internally generated funds, its revolving credit facility, the issuance of long-term debt and/or capital contributions from NVE. However, if energy costs rise at a rapid rate and NPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner or NPC were to experience a credit rating downgrade resulting in the posting of collateral as discussed below under Gas Supplier Matters, the amount of liquidity available to NPC could be significantly less. In order to maintain sufficient liquidity, NPC may be required to further delay capital expenditures, refinance debt or obtain funding through an equity issuance by NVE.

The ability to issue debt, as discussed later, is subject to certain covenant calculations which include consolidated net income of NVE and the Utilities. As a result of these covenant calculations and the seasonality of the Utilities’ business, the ability to issue debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

In the first quarter of 2010, NPC paid dividends to NVE of approximately $27 million.

NPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, NPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in NPC’s 2009 Form 10-K. However, in April 2010, NPC entered into a new revolving credit facility, as discussed under Financing Transactions.

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Financing Transactions

$600 Million Revolving Credit Facility

In April 2010, NPC terminated its $589 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $600 million secured revolving credit facility, maturing in April 2013. The fees on the $600 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility remains Wells Fargo Bank, National Association (formerly Wachovia Bank, National Association). The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highes t of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody’s. Currently, NPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $600 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that NPC can borrow or use for letters of credit and would require that NPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by NPC on a monthly basis, and after calculating such reduction, the NPC Credit Agreement provides that the availability under the revolving credit facility to NPC shall not be less than 50% of the total commitments thereunder.

The NPC Credit Agreement contains one financial maintenance covenant that requires NPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that NPC did not meet the financial maintenance covenant or there is an event of default, the NPC Credit Agreement would restrict dividends to NVE. Moreover, so long as NPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would not be a condition to the availability of credit under the facility. In the event that NPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in NPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

Factors Affecting Liquidity

Ability to Issue Debt

NPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and revolving credit facility agreements, and the terms of certain NVE debt. As of March 31, 2010, the most restrictive of the factors below is the PUCN authority. As such, NPC may issue up to $750 million in long term debt, in addition to the use of its existing credit facilities. However, depending on NVE’s or SPPC’s issuance of long term debt or the use of the Utilities’ revolving credit facilities the PUCN authority may not remain the most restrictive factor. The factors affecting NPC’s ability to issue debt are further detailed below:

a.	Financing authority from the PUCN - As of March 31, 2010, NPC has financing authority from the PUCN to issue (1) additional long term debt of up to $750 million for the period ending December 31, 2010, (2) ongoing authority to maintain a revolving credit facility of up to $1.3 billion, and (3) authority to refinance up to approximately $471 million of long-term debt securities.

b.	Financial covenants within NPC’s financing agreements – As stated in Financing Transactions above, NPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $600 million revolving credit agreement. Under the $600 million revolving credit facility, NPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on March 31, 2010 financial statements, NPC was in compliance with this covenant and could incur up to $1.7 billion of additional indebtedness.

	All other financial covenants contained in NPC’s financing agreements are suspended, as NPC’s senior secured debt is rated investment grade. However, if NPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, NPC would again be subject to the limitations under these additional covenants; and

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, NPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.6 billion.

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Ability to Issue General and Refunding Mortgage Securities

To the extent that NPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, NPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under NPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of NPC’s properties in Nevada. As of March 31, 2010, $3.9 billion of NPC’s General and Refunding Mortgage Securities were outstanding. NPC had the capacity to issue $867 million of General and Refunding Mortgage Securities as of March 31, 2010. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	The principal amount of retired General and Refunding Mortgage Securities; and/or
3.	The principal amount of first mortgage bonds retired after October 2001.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

NPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent NPC releases property from the lien of NPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

Credit Ratings

NPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. As of March 31, 2010, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
NPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*
NPC	Sr. Unsecured Debt	BB	Not rated	BB+

* Investment grade

S&P’s and Moody’s rating outlook for NPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to NPC’s contracts for purchased power, NPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that NPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

Under these contracts, a material adverse change (e.g., a credit rating downgrade) in NPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days follo wing the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. The net mark-to-market value as of March 31, 2010 for all suppliers continuing to provide power under a WSPP agreement would approximate a $57.5 million payment or obligation to NPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be marked-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, NPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse changes,

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which primarily means a credit rating downgrade below investment grade. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurances. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure.

Gas transmission service is secured under FERC Tariffs or custom agreements. These service contracts and Tariffs require the user to establish and maintain creditworthiness to obtain service or otherwise post cash or a letter of credit to be able to receive service. Service contracts are subject to FERC approved tariffs, which, under certain circumstances, require the Utilities to provide collateral to continue receiving service. NPC has one transmission counterparty for which it is required to post cash collateral or a letter of credit in the event of credit rating downgrades. As of March 31, 2010, the maximum amount of additional collateral NPC would be required to post under these contracts in the event of credit r ating downgrades was approximately $30.6 million. Of this amount, approximately $22.9 million would be required if NPC’s Senior Unsecured ratings are downgraded from their current level and an additional amount of approximately $7.7 million would be required if NPC’s Senior Secured ratings are downgraded to below investment grade.

Financial Gas Hedges

NPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under NPC’s Financing Transactions, the availability under NPC’s revolving credit facility is reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time be exceed 50% of the total commitments then in effect under the revolving credit facility. As of May 4, 2010, the reduction to NPC’s revolving credit facility was $79.3 million based on mark-to-market values as of April 30, 2010. Currently, NPC only has hedging contracts with counterparties wh o are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require NPC to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, NPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

Cross Default Provisions

None of the financing agreements of NPC contains a cross-default provision that would result in an event of default by NPC upon an event of default by NVE or SPPC under any of its financing agreements. In addition, certain financing agreements of NPC provide for an event of default if there is a failure under other financing agreements of NPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time NPC may rectify or correct the situation before it becomes an event of default.

SIERRA PACIFIC POWER COMPANY

RESULTS OF OPERATIONS

SPPC recognized net income of $17.1 million for the three months ended March 31, 2010 compared to net income of $19.1 million for the same period in 2009.

As of March 31, 2010, SPPC had paid $13 million in dividends to NVE. On May 4, 2010, SPPC declared an additional $12 million dividend to NVE.

Gross margin is presented by SPPC in order to provide information by segment that management believes aids the reader in determining how profitable the electric and gas businesses are at the most fundamental level. Gross margin, which is a “non-GAAP financial measure” as defined in accordance with SEC rules, provides a measure of income available to support the other operating expenses of the business and is utilized by management in its analysis of its business.

SPPC believes presenting gross margin allows the reader to assess the impact of SPPC’s regulatory treatment and its overall regulatory environment on a consistent basis. Gross margin, as a percentage of revenue, is primarily impacted by the fluctuations in regulated electric and natural gas supply costs versus the fixed rates collected from customers. While these fluctuating costs impact gross margin as a percentage of revenue, they only impact gross margin amounts if the costs cannot be passed through to customers. Gross margin, which SPPC calculates as operating revenues less fuel and purchased power costs, provides a measure of income available to support the other operating expenses of SPPC. Gross margin changes based on such factors as general base rate adjustments (which are requ ired to be filed by statute every three years) and reflect SPPC’s strategy to increase internal power generation versus purchased power, which generates no gross margin.

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The components of gross margin were (dollars in thousands):

	Three Months Ended March 31,
	2010			2009			Change from Prior Year
Operating Revenues:
Electric	$	209,981		$	237,738			-11.7	%
Gas		80,020			80,993			-1.2	%
	$	290,001		$	318,731			-9.0	%

Energy Costs:
Fuel for power generation	$	65,504		$	76,042			-13.9	%
Purchased power		36,136			37,181			-2.8	%
Gas purchased for resale		65,559			70,272			-6.7	%
Deferred energy – electric - net		(1,500	)		11,796			-112.7	%
Deferred energy – gas - net		(397	)		(4,351	)		-90.9	%
	$	165,302		$	190,940			-13.4	%
Energy Costs by Segment:
Electric	$	100,140		$	125,019			-19.9	%
Gas		65,162			65,921			-1.2	%
	$	165,302		$	190,940			-13.4	%

Gross Margin by Segment:
Electric	$	109,841		$	112,719			-2.6	%
Gas		14,858			15,072			-1.4	%
	$	124,699		$	127,791			-2.4	%

Electric gross margin decreased in the first quarter of 2010, compared to the same period in 2009, primarily due to a change in customer usage patterns which may be attributable to economic conditions and conservation programs, decreased revenues associated with renewable energy programs, and milder winter weather, partially offsetting these decreases was a slight increase in revenues from California customers.

Gas gross margin did not change materially for the first quarter of 2010, compared to the same period in 2009.

The causes of significant changes in specific lines comprising the results of operations are provided below (dollars in thousands except for amounts per unit):

Electric Operating Revenue

	Three Months Ended March 31,
	2010		2009		Change from Prior year %
Electric Operating Revenues:
Residential	$	83,159	$	93,785		-11.3	%
Commercial		76,974		90,437		-14.9	%
Industrial		42,631		46,067		-7.5	%
Retail revenues		202,764		230,289		-12.0	%
Other		7,217		7,449		-3.1	%
Total Revenues	$	209,981	$	237,738		-11.7	%

Retail sales in thousands
MWh		1,960		1,980		-1.0	%

Average retail revenues per MWh	$	103.45	$	116.31		-11.1	%

SPPC’s retail revenues decreased for the three months ended March 31, 2010, as compared to the same period in 2009, primarily due to decreases in retail rates as a result of SPPC’s various BTER quarterly updates and the annual Deferred Energy case effective October 1, 2009. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. The average number of residential and industrial customers decreased 0.2% and 1.9%, respectively, and the average number of commercial

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customers increased 0.1%. These decreases were offset by increased industrial usage primarily due to a gold mining customer which resumed operations in October 2009.

Electric Operating Revenues – Other decreased for the three month period ended March 31, 2010 compared to the same period in 2009 primarily due to decreased transmission revenues due to the expiration of several transmission service agreements.

Gas Operating Revenues

	Three Months Ended March 31,
	2010		2009		Change from Prior year %
Gas Operating Revenues:
Residential	$	42,363	$	45,881		-7.7	%
Commercial		20,482		21,840		-6.2	%
Industrial		5,939		5,892		0.8	%
Retail revenues		68,784		73,613		-6.6	%
Wholesale		10,561		6,734		56.8	%
Miscellaneous		675		646		4.5	%
Total Revenues	$	80,020	$	80,993		-1.2	%

Retail sales in thousands of Dths		5,985		6,107		-2.0	%

Average retail revenues per Dth	$	11.49	$	12.05		-4.7	%

SPPC’s retail gas revenues decreased in the three months ended March 31, 2010, compared to the same period in 2009, primarily due to decreases in retail customer rates and warmer temperatures in 2010. Retail rates decreased as a result of SPPC’s 2009 Natural Gas and Propane Deferred Rate Case and BTER quarterly updates. See Note 3, Regulatory Actions of the Notes to Financial Statements in the 2009 Form 10-K. The average number of retail customers increased by 0.6% for the three months ended March 31, 2010.

Wholesale revenues increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to excess supply resulting from lower customer usage.

Energy Costs

Energy Costs include Purchased Power and Fuel for Generation. These costs are dependent upon many factors which may vary by season or period. As a result, SPPC’s usage and average cost per MWh of Purchased Power versus Fuel for Generation can vary significantly as the company meets the demands of the season. These factors include, but are not limited to:

•		Weather
•		Plant outages
•		Total system demand
•		Resource constraints
•		Transmission constraints
•		Gas transportation constraints
•		Natural gas constraints
•		Long-term contracts
•		Mandated power purchases; and
•		Generation efficiency

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	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year
Energy Costs
Fuel for Generation	$	65,504	$	76,042		-13.9	%
Purchased Power	$	36,136	$	37,181		-2.8	%
Total Energy Costs	$	101,640	$	113,223		-10.2	%

MWhs
Fuel for Generation (in thousands)		1,190		1,279		-7.0	%
Purchased Power (in thousands)		869		870		-0.1	%
Total MWhs		2,059		2,149		-4.2	%

Average cost per MWh
Fuel for Generation	$	55.05	$	59.45		-7.4	%
Purchased Power	$	41.58	$	42.74		-2.7	%
Total average cost per MWh	$	49.36	$	52.69		-6.3	%

Energy costs decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a decrease in hedging costs, partially offset by increased natural gas costs.

·	The average cost per MWh for fuel for generation decreased in the three months ending March 31, 2010, primarily due to lower costs from hedging instruments partially offset by an increase in natural gas costs.
·	Purchase power costs, as a component of energy costs, and the average cost per MWh of purchased power decreased primarily due to higher resale of excess power, which are netted against purchased power costs.

Gas Purchased for Resale

	Three Months Ended March 31,
					Change from
	2010		2009		Prior Year

Gas Purchased for Resale	$	65,559	$	70,272		-6.7	%

Gas Purchased for Resale
(in thousands of Dth)		8,296		7,781		6.6	%

Average cost per Dth	$	7.90	$	9.03		-12.5	%

Gas purchased for resale decreased for the three months ended March 31, 2010, as compared to the same period in 2009. The decrease is primarily due to decreased costs associated with the settlement of hedging instruments partially offset by an increase in natural gas prices. Volume increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to excess availability of gas for wholesale customers.

Deferred Energy – Net

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Deferred energy – electric – net	$	(1,500	)	$	11,796			-112.7	%
Deferred energy - gas - net		(397	)		( 4,351	)		-90.9	%
Total	$	(1,897	)	$	7,445

Deferred energy – net represents the difference between actual fuel and purchased power costs incurred during the period and amounts recoverable through current rates. To the extent actual costs exceed amounts recoverable through current rates the excess is recognized as a reduction in costs. Conversely to the extent actual costs are less than amounts recoverable through current rates the difference is recognized as an increase in costs. Deferred energy – net also include the current amortization of fuel and purchased power costs previously deferred Reference Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, for further detail of deferred energy balances.

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Deferred energy - electric – net for the three months ended March 31, 2010 and 2009 reflect amortization of deferred energy of ($5.8) million and ($0.8) million, respectively; and an over-collection of amounts recoverable in rates of $4.3 million and $12.6 million respectively.

Deferred energy - gas - net for the three months ended March 31, 2010 and 2009 reflect amortization of deferred energy of ($3.5) million, and $0 million, respectively; and an over-collection of amounts recoverable in rates in 2010 of $3.1 million and an under-collection of $4.4 million in 2009.

Other Operating Expenses

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Other operating expense	$	40,672	$	44,015		-7.6	%
Maintenance expense	$	8,710	$	6,866		26.9	%
Depreciation and amortization	$	25,847	$	25,685		0.6	%

Other operating expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower employee pension and benefit expenses and lower costs associated with renewable energy programs; partially offset by higher outside consulting fees.

Maintenance expense increased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to scheduled combustion turbine maintenance at the Tracy Generating Station.

Depreciation and amortization increased slightly for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to regular system growth in plant-in-service.

Interest Expense

	Three Months Ended March 31,
	2010		2009		Change from Prior Year

Interest expense (net of AFUDC-debt)	$	17,045	$	17,927		-4.9	%

Interest expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to lower interest rates on variable rate debt, interest savings related to repurchased debt, lower interest on credit facility balances, the partial redemption of $73.3 million of the $325 million Series P General and Refunding Mortgage Bonds in December 2009, and interest on taxes in 2009. These amounts were partially offset by the issuance of $150 million of 6.0% Series M General and Refunding Mortgage Notes in August 2009. See Note 4, Long-Term Debt, of the Notes to Financial Statements of the 2009 Form 10-K for additional information regarding long-term debt.

Other Income and (Expenses)

	Three Months Ended March 31,
	2010			2009			Change from Prior Year

Interest income (expense) on regulatory items	$	(2,040	)	$	(673	)		203.1	%
AFUDC-equity	$	591		$	597			-1.0	%
Other income	$	1,755		$	2,715			-35.4	%
Other expense	$	(1,869	)	$	(1,991	)		-6.1	%

Interest income (expense) on regulatory items increased for the three months ended March 31, 2010, compared to the same period in 2009, due to higher over-collected deferred energy balances in 2010.

AFUDC-equity slightly decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a decrease in construction.

Other income decreased for the three months ended March 31, 2010, compared to the same period in 2009, primarily due to interest received for tax refunds in 2009, partially offset by interest income from investments in 2010.

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Other expense decreased for the three months ended March 31, 2010, compared to the same period in 2009, due to several items, each of which is not materially significant.

ANALYSIS OF CASH FLOWS

Cash flows increased during the three months ended March 31, 2010, compared to the same period in 2009, primarily due to a reduction in cash used by investing activities and an increase in cash from operating activities, partially offset by an increase in cash used by financing activities.

Cash From Operating Activities. The increase in cash from operating activities was primarily due to higher payments to vendors in the first quarter of 2009 and the timing of interest payments. These increases were partially offset by lower revenues as a result of BTER rate reductions, the timing of property tax payments, funding of pension plans and spending for conservation programs.

Cash Used By Investing Activities. Cash used by investing activities decreased due to the slowdown in construction for infrastructure.

Cash Used By Financing Activities. The increase in cash used by financing activities is primarily due to a reduction in draws on SPPC’s revolving credit facility.

LIQUIDITY AND CAPITAL RESOURCES

Overall Liquidity

SPPC’s primary source of operating cash flows is electric revenues, including the recovery of previously deferred energy costs. Significant uses of cash flows from operations include the purchase of electricity and natural gas, other operating expenses, capital expenditures and the payment of interest on SPPC’s outstanding indebtedness. Operating cash flows can be significantly influenced by factors such as weather, regulatory outcome and economic conditions.

Available Liquidity as of March 31, 2010 (in millions)
	SPPC
Cash and Cash Equivalents	$	28.5
Balance available on Revolving Credit Facility (1)(2)		316.2

	$	344.7

(1)	SPPC’s balance as of March 31, 2010 reflects amounts available under SPPC’s $332 million revolving credit facility. In April 2010 SPPC entered into a new revolving credit facility with a capacity of $250 million. See Financing Transactions below.
(2)	As of May 4, 2010, SPPC had approximately $208.5 million available under its revolving credit facility which includes reductions for hedging transactions and letters of credits, as discussed below under Financing Transactions.

SPPC attempts to maintain its cash and cash equivalents in highly liquid investments, such as U.S. treasury bills. In addition to cash on hand, SPPC may use its revolving credit facilities in order to meet its liquidity needs. Alternatively, depending on the usage of the revolving credit facilities, SPPC may issue debt, subject to certain restrictions as discussed in Factors Affecting Liquidity, Ability to Issue Debt, below.

SPPC has no significant debt maturities in 2010 or 2011. As of May 4, 2010, SPPC has no borrowings outstanding on its $250 million revolving credit facility, not including reductions for hedging transactions or letters of credit (see Financing Transactions below).

SPPC anticipates that it will be able to meet short-term operating costs, such as fuel and purchased power costs, with internally generated funds, including the recovery of deferred energy and the use of its revolving credit facilities. Furthermore, in order to fund long-term capital requirements, SPPC will likely meet such financial obligations with a combination of internally generated funds, the use of the revolving credit facilities, the issuance of long-term debt, and capital contributions from NVE. However, if energy costs rise at a rapid rate and SPPC does not recover the cost of fuel and purchased power in a timely manner, if operating costs are not recovered in a timely manner, the amount of liquidity available to SPPC could be significantly less. In order to maintain sufficient liquidity, SPPC may be required to further delay capital expenditures, re-finance debt or obtain funding through an equity issuance by NVE.

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debt can vary from quarter to quarter, and the Utilities may not be able to fully utilize the availability on their revolving credit facilities.

In the first quarter of 2010, SPPC paid dividends to NVE of $13 million.

SPPC designs operating and capital budgets to control operating costs and capital expenditures. In addition to operating expenses, SPPC has continuing commitments for capital expenditures for construction, improvement and maintenance of facilities.

During the three months ended March 31, 2010 there were no material changes to contractual obligations as set forth in SPPC’s 2009 Form 10-K. However, in April 2010, SPPC entered into a new revolving credit facility, as discussed under Financing Transactions.

Financing Transactions

$250 Million Revolving Credit Facility

In April 2010, SPPC terminated its $332 million secured revolving credit facility which would have expired in November 2010 and replaced it with a $250 million secured revolving credit facility, maturing in April 2013. The fees on the $250 million revolving credit facility for the unused portion and on the amounts borrowed have increased reflecting current market conditions. The Administrative Agent for the facility is Bank of America, N.A.. The rate for outstanding loans under the revolving credit facility will be at either an applicable base rate (defined as the highest of the Prime Rate, the Federal Funds Rate plus ½ of 1.0% and the LIBOR Base Rate plus 1.0%) plus a margin, or a LIBOR rate plus a margin. The margin varies based upon NPC’s credit rating by S&P and Moody̵ 7;s. Currently, SPPC’s applicable base rate margin is 1.25% and the LIBOR rate margin is 2.25%. The rate for outstanding letters of credit will be at the LIBOR rate margin plus a fee for the issuing bank.

The $250 million revolving credit facility contains a provision which reduces the availability under the credit facility by the negative mark-to-market exposure for hedging transactions with credit facility lenders or their energy trading affiliates. The reduction in availability limits the amount that SPPC can borrow or use for letters of credit and would require that SPPC prepay any amount in excess of that limitation. The amount of the reduction is calculated by SPPC on a monthly basis, and after calculating such reduction, the SPPC Credit Agreement provides that the availability under the revolving credit facility to SPPC shall not be less than 50% of the total commitments thereunder.

The SPPC Credit Agreement contains one financial maintenance covenant that requires SPPC to maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. In the event that SPPC did not meet the financial maintenance covenant or there is an event of default, the SPPC Credit Agreement would restrict dividends to NVE. Moreover, so long as SPPC’s senior secured debt remains rated investment grade by S&P and Moody’s (in each case, with a stable or better outlook), a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would not be a condition to the availability of credit und er the facility. In the event that SPPC’s senior secured debt rating were rated below investment grade by either S&P or Moody’s, or investment grade by either S&P or Moody’s but with a negative outlook, a representation concerning no material adverse change in SPPC’s business, assets, property or financial condition would be a condition to borrowing under the revolving credit facility.

Factors Affecting Liquidity

Ability to Issue Debt

SPPC’s ability to issue debt is impacted by certain factors such as financing authority from the PUCN, financial covenants in its financing agreements and its revolving credit facility agreement, and the terms of certain NVE debt. As of March 31, 2010, the most restrictive of the factors below is the PUCN authority. Based on this restriction, SPPC may issue up to $350 million of long term debt securities, and maintain a credit facility of up to $600 million. However, depending on NVE’s or NPC’s issuance of long-term debt or the use of Utilities’ revolving credit facilities, the PUCN authority may not remain the most restrictive factor. The factors affecting SPPC’s ability to issue debt are further detailed below.

a.	Financing authority from the PUCN - As of March 31, 2010, SPPC has financing authority from the PUCN to issue (1) additional long term debt of up to $350 million for the three-year period ending December 31, 2012, (2) ongoing authority to maintain a revolving credit facility of up to $600 million, and (3) authority to refinance approximately $348 million of long-term debt securities.

b.	Financial covenants within SPPC’s financing agreements – As stated in Financing Transactions above, SPPC’s revolving credit facility agreement, dated November 2005, has been replaced with a new $250 million revolving credit agreement. Under the $250 million revolving credit facility, SPPC must maintain a ratio of consolidated indebtedness to consolidated capital, determined as of the last day of each fiscal quarter, not to exceed 0.68 to 1. Based on March 31, 2010 financial statements, SPPC was in compliance with this covenant and could incur up to $855 million of additional indebtedness.

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	All other financial covenants contained in SPPC’s revolving credit facility and its financing agreements are suspended, as SPPC’s senior secured debt is rated investment grade. However, if SPPC’s senior secured debt ratings fall below investment grade by either Moody’s or S&P, SPPC would again be subject to the limitations under these additional covenants; and

c.	Financial covenants within NVE’s financing agreements – As discussed in NVE’s Ability to Issue Debt, SPPC is also subject to NVE’s cap on additional consolidated indebtedness of $1.6 billion.

Ability to Issue General and Refunding Mortgage Securities

To the extent that SPPC has the ability to issue debt under the most restrictive covenants in its financing agreements and has financing authority to do so from the PUCN, SPPC’s ability to issue secured debt is still limited by the amount of bondable property or retired bonds that can be used to issue debt under SPPC’s General and Refunding Mortgage Indenture (“Indenture”).

The Indenture creates a lien on substantially all of SPPC’s properties in Nevada. As of March 31, 2010, $1.7 billion of SPPC’s General and Refunding Mortgage Securities were outstanding. SPPC had the capacity to issue $606 million of General and Refunding Mortgage Securities as of March 31, 2010. That amount is determined on the basis of:

1.	70% of net utility property additions;
2.	The principal amount of retired General and Refunding Mortgage Securities; and/or
3.	The principal amount of first mortgage bonds retired after October 2001.

Property additions include plant in service and specific assets in CWIP. The amount of bond capacity listed above does not include eligible property in CWIP.

SPPC also has the ability to release property from the lien of the mortgage indenture on the basis of net property additions, cash and/or retired bonds. To the extent SPPC releases property from the lien of SPPC’s Indenture, it will reduce the amount of securities issuable under the Indenture.

Credit Ratings

SPPC’s senior secured debt is rated investment grade by three Nationally Recognized Statistical Rating Organizations: Fitch, Moody’s and S&P. DBRS is no longer covering NVE and the Utilities. As of March 31, 2010, the ratings are as follows:

		Rating Agency
		Fitch	Moody’s	S&P
SPPC	Sr. Secured Debt	BBB-*	Baa3*	BBB*

* Investment grade

S&P’s and Moody’s rating outlook for SPPC is Stable. Fitch’s rating outlook is Positive.

Energy Supplier Matters

With respect to SPPC’s contracts for purchased power, SPPC purchases and sells electricity with counterparties under the WSPP agreement, an industry standard contract that SPPC uses as a member of the WSPP. The WSPP contract is posted on the WSPP website.

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Under these contracts, a material adverse change (e.g., a credit rating downgrade) in SPPC may allow the counterparty to request adequate financial assurance, which, if not provided within three business days, could cause a default. Most contracts and confirmations for purchased power have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery in response to requests for financial assurance. A default must be declared within 30 days of the event, giving rise to the default becoming known. A default will result in a termination payment equal to the present value of the net gains and losses for the entire remaining term of all contracts between the parties aggregated to a single liquidated amount due within three business days following the date the notice of termination is received. The mark-to-market value, which is substantially based on quoted market prices, can be used to roughly approximate the termination payment and benefit at any point in time. Under the net mark-to-market value as of March 31, 2010 for all suppliers continuing to provide power under a WSPP agreement no amounts would be due to or from SPPC. These contracts qualify for the normal purchases scope exception as defined by the Derivatives and Hedging Topic of the FASC, and as such, are not required to be mark-to-market on the balance sheet. Refer to Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, for further discussion.

Gas Supplier Matters

With respect to the purchase and sale of natural gas, SPPC uses several types of standard industry contracts. The natural gas contract terms and conditions are more varied than the electric contracts. Consequently, some of the contracts contain language similar to that found in the WSPP agreement and other agreements have unique provisions dealing with material adverse change, which primarily means a credit rating downgrade below investment grade. Forward physical gas supplies are purchased under index based pricing terms and as such do not carry forward mark-to-market exposure. Most contracts and confirmations for natural gas purchases have been modified or separate agreements have been made to either shorten the normal payment due date or require payment in advance of delivery. At the present time, no counterparties require payment in advance of delivery.

Financial Gas Hedges

SPPC enters into certain hedging contracts with various counterparties to manage the gas price risk inherent in purchased power and fuel contracts. As discussed under SPPC’s Financing Transactions, the availability under SPPC’s revolving credit facility is reduced by the amount of negative mark-to-market positions on hedging contracts with counterparties who are lenders to the revolving credit facility, provided that the reduction in availability under the revolving credit facility shall at no time exceed 50% of the total commitments then in effect under the revolving credit facility. As of May 4, 2010, the reduction to SPPC’s revolving credit facility was $25.2 million based on mark-to-market values as of April 30, 2010. Currently, SPPC only has hedging contracts with counterparties who are also lenders on the revolving credit facility; however, future contracts entered into with non-lenders may require SPPC to post cash collateral in the event of a credit rating downgrade. Finally, as of October 2009, SPPC has suspended its hedging program as such expect its exposure to negative mark-to-market positions to decline.

Cross Default Provisions

None of the financing agreements of SPPC contains a cross-default provision that would result in an event of default by SPPC upon an event of default by NVE or NPC under any of its financing agreements. In addition, certain financing agreements of SPPC provide for an event of default if there is a failure under other financing agreements of SPPC to meet payment terms or to observe other covenants that would result in an acceleration of payments due. Most of these default provisions (other than ones relating to a failure to pay such other indebtedness when due) provide for a cure period of 30-60 days from the occurrence of a specified event during which time SPPC may rectify or correct the situation before it becomes an event of default.

REGULATORY PROCEEDINGS (UTILITIES)

NVE is a “holding company” under the Public Utility Holding Company Act of 2005 (PUHCA 2005). As a result, NVE and all of its subsidiaries (whether or not engaged in any energy related business) are required to maintain books, accounts and other records in accordance with FERC regulations and to make them available to the FERC, the PUCN and CPUC. In addition, the PUCN, CPUC, or the FERC have the authority to review allocations of costs of non-power goods and administrative services among NVE and its subsidiaries. The FERC has the authority generally to require that rates subject to its jurisdiction be just and reasonable and in this context would continue to be able to, among other things, review transactions between NVE, NPC and/or SPPC and/o r any other affiliated company.

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The Utilities are subject to the jurisdiction of the PUCN and, in the case of SPPC, the CPUC with respect to rates, standards of service, siting of and necessity for generation and certain transmission facilities, accounting, issuance of securities and other matters with respect to electric and gas distribution and transmission operations. NPC and SPPC submit IRPs to the PUCN for approval.

Under federal law, the Utilities are subject to certain jurisdictional regulation, primarily by the FERC. The FERC has jurisdiction under the Federal Power Act with respect to rates, service, interconnection, accounting and other matters in connection with the Utilities’ sale of electricity for resale and interstate transmission. The FERC also has jurisdiction over the natural gas pipeline companies from which the Utilities take service.

As a result of regulation, many of the fundamental business decisions of the Utilities, as well as the ROR they are permitted to earn on their utility assets, are subject to the approval of governmental agencies.

The Utilities are required to file annual electric and gas DEAA cases on March 1 as mandated by the 2007 Nevada Legislature, quarterly BTER Updates for the Utilities’ electric and gas departments, and triennial GRCs in Nevada. A DEAA case is filed to recover or refund any under or over collection of prior energy costs and the BTER Updates recover current energy costs. As of March 31, 2010, NPC’s and SPPC’s balance sheets included approximately $40.1 million and credits of $118.6 million, respectively, of deferred energy costs of which $56.9 million and credits of $108.8 million had been previously approved for collection over various periods. The remaining amounts will be requested in future DEAA filings. Refer to Note 3, Regulatory Actions of the Condensed Notes to Financi al Statements. A GRC filing is to set rates to recover operation and maintenance expenses, depreciation, taxes and provide a return on invested capital.

Rate case applications filed in 2009 and 2010, as well as other regulatory matters such as, the Utilities’ IRPs and subsequent amendments, other Nevada matters, California matters and FERC matters, are discussed in more detail in Note 3, Regulatory Actions, of the Condensed Notes to Financial Statements, and in the 2009 Form 10-K.

RECENT PRONOUNCEMENTS

See Note 1, Summary of Significant Accounting Policies, of the Condensed Notes to Financial Statements, for discussion of accounting policies and recent pronouncements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

As of March 31, 2010, NVE, NPC and SPPC have evaluated their risk related to financial instruments whose values are subject to market sensitivity. Such instruments are fixed and variable rate debt. The tables below do not include the interest rate swap entered into in 2009 and discussed further in Note 6, Derivatives and Hedging Activities, of the Condensed Notes to Financial Statements, as the amount is considered immaterial. Fair market value is determined using quoted market price for the same or similar issues or on the current rates offered for debt of the same remaining maturities (dollars in thousands).

	March 31, 2010
	Expected Maturity Date
																					Fair
	2010		2011			2012			2013			2014			Thereafter			Total			Value
Long-Term Debt
NVE
Fixed Rate	$	-	$	-		$	63,670		$	-		$	230,039		$	191,500		$	485,209		$	495,056
Average Interest Rate		-		-			7.80	%					8.63	%		6.75	%		7.78	%

NPC
Fixed Rate	$	-	$	364,000		$	130,000		$	-		$	125,000		$	2,717,050		$	3,336,050		$	3,590,974
Average Interest Rate		-		8.14	%		6.50	%		-			7.38	%		6.50	%		6.72	%
Variable Rate	$	-	$	-		$	-		$	230,000		$	-		$	173,775		$	403,775		$	403,775
Average Interest Rate		-		-			-			0.99	%		-			0.67	%		0 .85	%

SPPC
Fixed Rate	$	-	$	-		$	100,000		$	250,000		$	-		$	701,742		$	1,051,742		$	1,135,913
Average Interest Rate		-		-			6.25	%		5.45	%		-			6.27	%		6.07	%
Variable Rate	$	-	$	-		$	-		$	-		$	-		$	214,675		$	214,675		$	214,675
Average Interest Rate		-		-			-			-			-			0.64	%		0.64	%

Total Debt	$	-	$	364,000		$	293,670		$	480,000		$	355,039		$	3,998,742		$	5,491,451		$	5,840,393

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Commodity Price Risk

See the 2009 Form 10-K, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, for a discussion of Commodity Price Risk. No material changes in commodity risk have occurred since December 31, 2009.

Credit Risk

The Utilities monitor and manage credit risk with their trading counterparties. Credit risk is defined as the possibility that counterparty to one or more contracts will be unable or unwilling to fulfill its financial or physical obligations to the Utilities because of the counterparty’s financial condition. The Utilities’ credit risk associated with trading counterparties was approximately $62.9 million as of March 31, 2010, which compares to balances of $73.2 million at December 31, 2009. The decrease from December 31, 2009 is primarily due to the decrease in prices of natural gas and power during the first quarter of 2010.

ITEM 4 and 4T. CONTROLS AND PROCEDURES

(a)	Evaluation of disclosure controls and procedures.

NVE, NPC and SPPC’s principal executive officers and principal financial officers, based on their evaluation of the registrants’ disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) have concluded that, as of March 31, 2010, the registrants’ disclosure controls and procedures were effective.

(b)	Change in internal controls over financial reporting.

There were no changes in internal controls over financial reporting in the first quarter of 2010 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

NPC and SPPC

Western United States Energy Crisis Proceedings before the FERC

FERC 206 complaints

In December 2001, the Utilities filed ten complaints with the FERC against various power suppliers, including Enron, under Section 206 of the Federal Power Act seeking price reduction of forward wholesale power purchase contracts entered into prior to the FERC mandated price caps imposed in June 2001 in reaction to the Western United States energy crisis. The Utilities contested the amounts paid for power actually delivered as well as termination claims for undelivered power against terminating suppliers.

In June 2003, the FERC dismissed the Utilities’ Section 206 complaints, stating that the Utilities had failed to satisfy their burden of proof under the strict public interest standard. In July 2003, the Utilities filed a petition for rehearing, but the FERC reaffirmed its June decision (“July decision”). The Utilities appealed this decision to the Ninth Circuit. In December 2006, a three judge panel of the Ninth Circuit overturned the FERC’s July decision and remanded the case back to the FERC for application of factors that the Ninth Circuit outlines in its decision. In May 2007, American Electric Power Service Corporation, Allegheny Energy Supply Company and other interested parties filed petitions for certiorari (“Petitions”) with the U.S. Supreme Court seeking review of the Ninth Circuit’s decision. The Utilities, together with other parties and the FERC, filed their opposition to these Petitions in August 2007. In September 2007, the U.S. Supreme Court granted certiorari. In June 2008, the U.S. Supreme Court rejected the Ninth Circuit’s reasoning in reversing the FERC but nonetheless found that the FERC’s order was defective and should be reversed for other reasons. The case was remanded to the FERC.

The FERC established a formal settlement discussion protocol for bilateral settlement discussions with other respondents, including Allegheny Energy Supply Company, American Electric Power Service Corporation and BP Energy, and stayed the case pending settlement discussions. The Utilities, together with other interested parties including the Nevada BCP, have settled and resolved all claims against BP Energy (“BP Settlement”). On August 25, 2009, the BP Settlement received final approval by the FERC, under which BP Energy was ordered to settle with NPC for an immaterial amount in return for NPC and the BCP’s release of all claims against BP Energy. On November 19, 2009, the Utilities, together with other interested parties, executed a settlement agreement with American Electric Po wer Service Corporation (“AEP Settlement”). On December 23, 2009, the AEP Settlement received final approval by the FERC, under which AEP was ordered to settle with the Utilities for an immaterial amount in return for a release of all claims by the Utilities and BCP against AEP. This amount was received in February 2010 from AEP in fulfillment of its

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obligations under the settlement agreement. The Utilities had previously negotiated settlements with Duke Energy Trading and Marketing, Morgan Stanley Capital Group, El Paso Merchant Energy, now known as El Paso Marketing L.P., Calpine Energy Services and Enron. The Utilities continue discussions under FERC settlement procedures with Allegheny Energy Supply Company. Management cannot predict the timing or outcome of a decision in this matter.

Other Legal Matters

NVE and its subsidiaries, through the course of their normal business operations, are currently involved in a number of other legal actions, none of which has had or, in the opinion of management, is expected to have a significant impact on their financial positions or results of operations. See Note 8, Commitments and Contingencies, of the Condensed Notes to Financial Statements, for further discussion of other legal matters.

ITEM 1A. RISK FACTORS

For the purposes of this section, the terms “we,” “us” and “our” refer to NVE on a consolidated basis (including NPC and SPPC). The following information updates, and should be read in conjunction with, the information disclosed in Item 1A, “Risk Factors,” of our 2009 Form 10-K. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that are not presently known or that we currently believe to be less significant may also adversely affect us.

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in NVE’s, NPC’s and SPPC’s 2009 Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 5. OTHER INFORMATION

The following information was not required to be disclosed on Form 8-K during the period covered by this Form 10-Q, but is instead being included to update the Registrants’ environmental disclosure in Part I, Item 1, of the 2009 Form 10-K, under the caption “Federal Environmental Laws, Regulations and Regulatory Initiatives”.

Regulatory Developments Pertaining to Climate Change

On April 1, 2010, the EPA and the National Highway Traffic Safety Administration (NHTSA) released their final Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (Motor Vehicle Rule). The standards set the first standards on carbon dioxide (CO2) and other greenhouse gas (GHG) emissions from certain cars and trucks.

By regulating mobile sources under the Clean Air Act, the Rule may also trigger an increase in permitting requirements, including emission limits on new and modified stationary sources, under the Act. Specifically, when it takes effect on January 2, 2011, the rule may trigger Prevention of Significant Deterioration (PSD) and Title V permitting requirements for several million stationary sources. EPA will address whether, and if so, when and how stationary sources may be subject to PSD because of GHG emissions in its “Tailoring Rule,” 74 Fed. Reg. 55291, which was proposed on October 27, 2009, and is expected to be finalized later this Spring. We note that new energy and carbon legislative proposals are also currently pending in Congress and, if such bills were passed, could supersede EPA pr oposals to regulate carbon associated with electric utility stationary sources.

While the Utilities cannot predict the final form these regulations or bills will take or the specific cost implication to our stationary facilities at this time, the Utilities continue to closely monitor developments.

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ITEM 6.EXHIBITS

(a)	Exhibits filed with this Form 10-Q:

(10) NV Energy, Inc.:

10.1

Assistance Agreement dated March 12, 2010 between the U.S. Department of Energy and NV Energy, Inc.

(12) NV Energy, Inc.:

12.1

Statement regarding computation of Ratios of Earnings to Fixed Charges.

Nevada Power Company:

12.2

Statement regarding computation of Ratios of Earnings to Fixed Charges.

Sierra Pacific Power Company:

12.3

Statement regarding computation of Ratios of Earnings to Fixed Charges.

(31) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

31.1		Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.3		Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4		Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.5		Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6		Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) NV Energy, Inc., Nevada Power Company and Sierra Pacific Power Company

32.1		Certification of Principal Executive Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Principal Executive Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.3		Certification of Principal Executive Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4		Certification of Principal Financial Officer of NV Energy, Inc. Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.5		Certification of Principal Financial Officer of Nevada Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6		Certification of Principal Financial Officer of Sierra Pacific Power Company Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.


	NV Energy, Inc.
	(Registrant)


Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

	Nevada Power Company d/b/a NV Energy
	(Registrant)


Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

	Sierra Pacific Power Company d/b/a NV Energy
	(Registrant)

Date: May 5, 2010	By:	/s/ E. Kevin Bethel
		E. Kevin Bethel
		Interim Chief Financial Officer
		(Principal Financial Officer)

Table of Contents

EX-10.1 2 exhibit10-1.htm EXHIBIT 10.1 exhibit10-1.htm

NOT SPECIFIED /OTHER

ASSISTANCE AGREEMENT
1. Award No. DE-OE0000205	2. Modification No. 002	3. Effective Date 03/12/2010	4. CFDA No. 81.122

5. Awarded To

NV ENERGY, INC.

Attn: Michael W Yackira, CEO

6226 W SAHARA AVE

LAS VEGAS NV 891463060

6. Sponsoring Office

Elec. Delivery & Reliability (FORS) U.S. Department of Energy

Office of Elec. Delivery & Energy Reliabil

Forrestal Building

1000 Independence Avenue, SW

Washington DC 20585

7. Period of Performance

12/24/2009

through

12/24/2014

8. Type of Agreement

x Grant

o Cooperative Agreement

o Other

9. Authority

31 USC 6304

10. Purchase Request or Funding Document No.

10OE000351

11. Remittance Address

NV ENERGY, INC.

Attn: Michael W Yackira, CEO

6226 W SAHARA AVE

LAS VEGAS NV 891463060

12. Total Amount

Govt. Share :

$137,877,906.00

Cost Share :

$137,877,906.00

Total :

$275,755,812.00

13. Funds Obligated

This action: $0.00

Total : $137,877,906.00

14. Principal Investigator

15. Program Manager

Donald W. MacDonald

Phone: 202-586-3583

16. Administrator

Office of HQ PS (HQ)

U.S. Department of Energy

Office of Headquarters Procurement

MA-64

1000 Independence Ave., S.W. Washington DC 20585

17. Submit Payment Requests To OR for HQ U.S. Department of Energy Oak Ridge Financial Service Center P.O. Box 4937 Oak Ridge TN 37831	18. Paying Office OR for HQ U.S. Department of Energy Oak Ridge Financial Service Center P.O. Box 4937 Oak Ridge TN 37831	19. Submit Reports To See Attachment B
20. Accounting and Appropriation Data 89-0910-0328
21. Research Title and/or Description of Project ADVANCED SERVICE DELIVERY

For the Recipient		For the United States of America
22. Signature of Person Authorized to Sign /s/ Michael W Yackira		25. Signature of Grants/Agreements Officer /s/ Donna C. Williams
23. Name and Title Michael W. Yackira President & CEO	24. Date Signed 3/12/10	26. Name of Officer Donna C. Williams	27. Date Signed 3-12-10

NOT SPECIFIED /OTHER

NOT SPECIFIED /OTHER
CONTINUATION SHEET	REFERENCE NO. OF DOCUMENT BEING CONTINUED DE-OE0000205/002	PAGE OF 2 2
NAME OF OFFEROR OR CONTRACTOR
NV ENERGY, INC.

ITEM NO. (A)	SUPPLIES/SERVICES (B)	QUANTITY (C)	UNIT (D)	UNIT PRICE (E)	AMOUNT (F)
	DUNS Number: 121809347 The purpose of this amendment is to definitize the Limited Authority Agreement dated December 24, 2009. As such the special terms and conditions of December 24, 2009 are deleted in their entirety and replaced in their entirety with the Special Terms and Conditions attached hereto. The Project Description for this Grant, as contained in the Application submitted in response to Funding Opportunity Announcement Number DE-FOA-0000058, is Incorporated by Reference together with the following attachment: Attachment A, SF-424A - Budget Information for Non-Construction Programs Attachment B, DOE F 4600.2 - Federal Assistance Reporting Checklist Attachment C, Intellectual Property Provisions (NRD-1003) Nonresearch and Development Attachment D, National Policy Assurances to be Incorporated as Award Terms Attachment E, Statement of Project Objectives ASAP: NO Extent Competed: COMPETED Davis-Bacon Act: NO Fund: 05846 Appr Year: 2009 Allottee: 60 Report Entity: 302931 Object Class: 25500 Program: 3123742 Project: 2006000 WFO: 0000000 Local Use: 0000000 TAS Agency: 89 TAS Account: 0328
JULY 2004

NOT SPECIFIED /OTHER

For Official Use Only

1.	RESOLUTION OF CONFLICTING CONDITIONS……………………………………………………………….....................................................................................................	2
2.	AWARD PROJECT PERIOD AND BUDGET PERIOD………………………………………………………….....................................................................................................	2
3.	PAYMENT PROCEDURES – REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDER INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS)…………………......................................................................................................................................................................................................	2
4.	MAXIMUM OBLIGATION………………………………………………………………………………..................................................................................................................	2
5.	COST SHARING FFRDC’S NOT INVOLVED…………………………………………………………………........................................................................................................	3
6.	REBUDGETING AND RECOVERY OF INDIRECT COSTS – REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS…………………………………………..	3
7.	PRE-AWARD COSTS (As Applicable)……………………………………………………………………………..................................................................................................	3
8.	USE OF PROGRAM INCOME – COST SHARING…………………………………………………………...........................................................................................................	3
9.	STATEMENT OF FEDERAL STEWARDSHIP………………………………………………………………….....................................................................................................	3
10.	SITE VISITS……………………………………………………………………………………………………….........................................................................................................	4
11.	REPORTING REQUIREMENTS………………………………………………………………………………............................................................................................................	4
12.	PUBLICATIONS……………………………………………………………………………………………………......................................................................................................	4
13.	FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS……………………………………………………......................................................................................................	4
14.	LOBBYING RESTRICTIONS…………………………………………………………………………………….........................................................................................................	4
15.	NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS…………………………………………	4
16.	PROPERTY………………………………………………………………………………………………………….......................................................................................................	5
17.	INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP……………………………………………………….............................................................................................................	5
18.	NATIONAL ENVIRONMENTAL POLICY ACT (NEPA) REQUIREMENTS………………………………….....................................................................................................	5
19.	FINAL INCURRED COST AUDIT………………………………………………………………………………........................................................................................................	6
20.	SPECIAL PROVISIONS RELATING TO WORK FUNDED UNDER AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009 (MAR 2009)....…………………	6
21.	REPORTING AND REGISTRATION REQUIREMENTS UNDER SECTION 1512 OF THE RECOVERY ACT……………………………………………………………….	9
22.	REQUIRED USE OF AMERICAN IRON, STEEL, AND MANUFACTURED GOODS -- SECTION 1605 OF THE AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009…………………………...........................................................................................................................................................................................................................	10
23.	REQUIRED USE OF AMERICAN IRON, STEEL, AND MANUFACTURED GOODS (COVERED UNDER INTERNATIONAL AGREEMENTS)—SECTION 1605 OF THE AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009………………………………………………………………………………….......................................	12
24.	WAGE RATE REQUIREMENTS UNDER SECTION 1606 OF THE RECOVERY ACT (As Applicable)……....................................................................................................	15
25.	RECOVERY ACT TRANSACTIONS LISTED IN SCHEDULE OF EXPENDITURES OF FEDERAL AWARDS AND RECIPIENT RESPONSIBILITIES FOR INFORMING SUBRECIPIENTS……………….............................................................................................................................................................................................................	15
26.	DAVIS BACON ACT AND CONTRACT WORK HOURS AND SAFETY STANDARDS ACT (NOV 2009) (If Applicable)………………………………………………	16
27.	GOVERNMENT INSIGHT………………………………………………………………………………………….......................................................................................................	23
28.	NO COST EXTENSION – REQUIREMENT FOR TIMELY DELIVERABLES………………………………….....................................................................................................	24
29.	FAILURE TO RECEIVE OR RECISSION OF REGULATORY AND OTHER REQUIRED PROJECT APPROVALS…………………………………………………………..	24
30.	PROJECT DELIVERABLES……………………………………………………………………………………….........................................................................................................	24
31.	ADVANCE UNDERSTANDING FOR FEDERAL INCOME TAX TREATMENT……………………………......................................................................................................	30

For Official Use Only

1.	RESOLUTION OF CONFLICTING CONDITIONS

Any apparent inconsistency between Federal statutes and regulations and the terms and conditions contained in this award must be referred to the DOE Award Administrator for guidance.

2.	AWARD PROJECT PERIOD AND BUDGET PERIOD

The Period of Performance for this Award is sixty (60) months from the effective date. The project start date will be March 12, 2010. Project implementation shall not exceed thirty-six (36) months. The balance of the Period of Performance will be for data collection activities.

3.	PAYMENT PROCEDURES -REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDER INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS)

a. Method of Payment. Payment will be made by reimbursement through ACH.

b. Requesting Reimbursement. Requests for reimbursements must be made electronically through Department of Energy's Oak Ridge Financial Service Center (ORFSC) VIPERS. To access and use VIPERS, you must enroll at https://finweb.oro.doe.gov/vipers.htm. Detailed instructions on how to enroll are provided on the web site.

You must submit a Standard Form (SF) 270, "Request for Advance or Reimbursement" at https://finweb.oro.doe.gov/vipers.htm and attach a file containing appropriate supporting documentation. The file attachment must show the total federal share claimed on the SF 270, the non-federal share claimed for the billing period, and cumulative expenditures to date (both Federal and non-Federal) for each of the following categories: salaries/wages and fringe benefits; equipment; travel; participant/training support costs, if any; other direct costs, including subawards/contracts; and indirect costs.

c. Timing of submittals. Submittal of the SF 270 should coincide with your normal billing pattern, but not more frequently than every two weeks. Requests for reimbursement must be limited to the amount of disbursements made during the billing period for the federal share of direct project costs and the proportionate share of any allowable indirect costs incurred during that billing period.

d. Adjusting payment requests for available cash. You must disburse any funds that are available from repayments to and interest earned on a revolving fund, program income, rebates, refunds, contract settlements, audit recoveries, credits, discounts, and interest earned on any of those funds before requesting additional cash payments from DOE.

e. Payments. The DOE approving official will approve the invoice as soon as practicable but not later than 30 days after your request is received, unless the billing is improper. Upon receipt of an invoice payment authorization from the DOE approving official, the ORFSC will disburse payment to you. You may check the status of your payments at the VIPER web site. All payments are made by electronic funds transfer to the bank account identified on the ACH Vendor/Miscellaneous Payment Enrollment Form (SF 3881) that you filed.

4.	MAXIMUM OBLIGATION

The maximum obligation of the DOE is limited to the amount shown on the Agreement Face Page. You are not obligated to continue performance of the project beyond the total amount obligated and your pro rata share of the project costs.

For Official Use Only

5.	COST SHARING FFRDC’S NOT INVOLVED

Total Estimated Project Cost is the sum of the Government share and Recipient share of the estimated project costs. The Recipient's cost share must come from non-Federal sources unless otherwise allowed by law. By accepting federal funds under this award, you agree that you are liable for your percentage share of total allowable project costs, even if the project is terminated early or is not funded to its completion. This cost is shared as follows:

Government Share	Recipient Share	Total Estimated Cost
$ / %	$ / %
$137,877,906/ 50%	$137,877,906/ 50%	$275,755,812

If you discover that you may be unable to provide cost sharing of at least the amount identified in paragraph a of this article, you should immediately provide written notification to the DOE Award Administrator indicating whether you will continue or phase out the project. If you plan to continue the project, the notification must describe how replacement cost sharing will be secured.

c.	You must maintain records of all project costs that you claim as cost sharing, including in-kind costs, as well as records of costs to be paid by DOE. Such records are subject to audit.

d.	Failure to provide the cost sharing required by this Clause may result in the subsequent recovery by DOE of some or all the funds provided under the award.

6.	REBUDGETING AND RECOVERY OF INDIRECT COSTS – REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS

a. If actual allowable indirect costs are less than those budgeted and funded under the award, you may use the difference to pay additional allowable direct costs during the project period. If at the completion of the award the Government's share of total allowable costs (i.e., direct and indirect), is less than the total costs reimbursed, you must refund the difference.

b. Recipients are expected to manage their indirect costs. DOE will not amend an award to provide additional funds for changes in indirect cost rates. DOE recognizes that the inability to obtain full reimbursement for indirect costs means the Recipient must absorb the under recovery. Such under recovery may be allocated as part of the organization's required cost sharing.

7.	PRE-AWARD COSTS (As Applicable)

Any work performed prior to the effective date of award stated on the Agreement Face Page is done at the recipient's risk. You are able to recoup costs incurred on or after August 6, 2009, that are otherwise allowable. All pre-award costs must be in accordance with the applicable Federal Cost principles referenced in 10 C.F.R. 600.

8.	USE OF PROGRAM INCOME – COST SHARING

If you earn program income during the project period as a result of this award, you may use the program income to meet your cost sharing requirement.

9.	STATEMENT OF FEDERAL STEWARDSHIP

DOE will exercise Federal stewardship in overseeing the project activities performed under this award. Stewardship activities include, but are not limited to, conducting site visits; reviewing performance and financial reports; providing technical assistance and/or temporary intervention in unusual circumstances to correct deficiencies which develop during the project; assuring compliance with terms and conditions; and reviewing technical performance after project completion to ensure that the award objectives have been accomplished.

For Official Use Only

10.	SITE VISITS

DOE's authorized representatives have the right to make site visits at reasonable times to review project accomplishments and management control systems and to provide technical assistance, if required. You must provide, and must require your subawardees to provide, reasonable access to facilities, office space, resources, and assistance for the safety and convenience of the government representatives in the performance of their duties. All site visits and evaluations must be performed in a manner that does not unduly interfere with or delay the work.

The DOE will be provided reasonable access to Recipient facilities to verify the installation, configuration, and operational status of the components, devices, facilities, and systems being installed under this award. The DOE shall request access reasonably in advance and shall be accompanied by representative(s) of the Recipient.

11.	REPORTING REQUIREMENTS

The reporting requirements for this award are identified on the Federal Assistance Reporting Checklist, DOE F 4600.2, attached to this award. Failure to comply with these reporting requirements is considered a material noncompliance with the terms of the award. Noncompliance may result in withholding of future payments, suspension, or termination of the current award. A willful failure to perform, a history of failure to perform, or unsatisfactory performance may also result in a debarment action to preclude future awards by Federal agencies.

12.	PUBLICATIONS

If you publish or otherwise make publicly available the results of the work conducted under the award, an acknowledgment of Federal support and a disclaimer must appear in the publication of any material, whether copyrighted or not, based on or developed under this project, as follows:

Acknowledgment: "This material is based upon work supported by the Department of Energy under Award Number(s) [Enter the award number(s)]."

Disclaimer: "This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United Stat es Government or any agency thereof."

13.	FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS

You must obtain any required permits and comply with applicable federal, state, and municipal laws, codes, and regulations for work performed under this award.

14.	LOBBYING RESTRICTIONS

By accepting funds under this award, you agree that none of the funds obligated on the award shall be expended, directly or indirectly, to influence congressional action on any legislation or appropriation matters pending before Congress, other than to communicate to Members of Congress as described in 18 U.S.C. 1913. This restriction is in addition to those prescribed elsewhere in statute and regulation.

15.	NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS

It is the sense of the Congress that, to the greatest extent practicable, all equipment and products purchased with funds made available under this award should be American-made.

For Official Use Only

16.

PROPERTY

Real property and equipment acquired by the Recipient shall be subject to the rules set forth in 10 CFR 600.321.

Consistent with the goals and objectives of this project, the Recipient may continue to use real property and equipment purchased in whole or in part with Federal funds under this award for its authorized purpose beyond the Period of Performance without obligation to make payment to DOE to extinguish DOE's interest to such property as described in 10 CFR 600.321, subject to the following: (a) the Recipient continues to utilize such property for the objectives of the project as set forth in the Statement of Project Objectives; (b) DOE retains the right to periodically ask for, and the Recipient agrees to provide, reasonable information concerning the use and condition of the property; and (c) the Recipient follows the property disposition rules set forth in 10 CFR 600.321 if the property is no longer used by the Recipient for the objective s of the project, and the fair market value of property exceeds $5,000.

Once the per unit fair market value of the property is less than $5,000, pursuant to 10 CFR 600.321(f)(l)(i), DOE's interest in the property shall be extinguished and Recipient shall have no further obligation to the DOE with respect to the property.

Consistent with the 10 C.F.R. §§ 600.132(a), 600.134(c), and 600.321(b)(2), a recipient may request that the DOE contracting officer consider approving encumbrance of real property and equipment purchased in whole or in part with Federal funds under the award.

17.	INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP

a. You shall immediately notify the DOE of the occurrence of any of the following events: (i) you or your parent's filing of a voluntary case seeking liquidation or reorganization under the Bankruptcy Act; (ii) your consent to the institution of an involuntary case under the Bankruptcy Act against you or your parent; (iii) the filing of any similar proceeding for or against you or your parent, or its consent to, the dissolution, winding-up or readjustment of your debts, appointment of a receiver, conservator, trustee, or other officer with similar powers over you, under any other applicable state or federal law; or (iv) your insolvency due to your inability to pay your debts generally as they become due.

b. Such notification shall be in writing and shall: (i) specifically set out the details of the occurrence of an event referenced in paragraph a; (ii) provide the facts surrounding that event; and (iii) provide the impact such event will have on the project being funded by this award.

c. Upon the occurrence of any of the four events described in the first paragraph, DOE reserves the right to conduct a review of your award to determine your compliance with the required elements of the award (including such items as cost share, progress towards technical project objectives, and submission of required reports). If the DOE review determines that there are significant deficiencies or concerns with your performance under the award, DOE reserves the right to impose additional requirements, as needed to institute payment controls.

d. Failure of the Recipient to comply with this provision may be considered a material noncompliance of this financial assistance award by the Contracting Officer.

18.	NATIONAL ENVIRONMENTAL POLICY ACT (NEPA) REQUIREMENTS

The project proposed and approved by DOE as detailed in this award is categorically excluded from National Environmental Policy Act (NEPA) requirements. However, if the project changes or is

For Official Use Only

supplemented your work associated with the new activity is restricted from taking any action using Federal funds, which would have an adverse effect on the environment or limit the choice of reasonable alternatives prior to DOE providing either a NEPA clearance or a final NEPA decision regarding this project.

If you move forward with activities that are not authorized for federal funding by the DOE Contracting Officer in advance of the final NEPA decision, you are doing so at risk of not receiving federal funding and such costs may not be recognized as allowable cost share.

19.	FINAL INCURRED COST AUDIT

In accordance with 10 CFR 600, DOE reserves the right to initiate a final incurred cost audit on this award. If the audit has not been performed or completed prior to the closeout of the award, DOE retains the right to recover an appropriate amount after fully considering the recommendations on disallowed costs resulting from the final audit.

20.	SPECIAL PROVISIONS RELATING TO WORK FUNDED UNDER AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009 (MAR 2009)

Preamble

The American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, (Recovery Act) was enacted to preserve and create jobs and promote economic recovery, assist those most impacted by the recession, provide investments needed to increase economic efficiency by spurring technological advances in science and health, invest in transportation, environmental protection, and other infrastructure that will provide long-term economic benefits, stabilize State and local government budgets, in order to minimize and avoid reductions in essential services and counterproductive State and local tax increases. Recipients shall use grant funds in a manner that maximizes job creation and economic benefit.

The Recipient shall comply with all terms and conditions in the Recovery Act relating generally to governance, accountability, transparency, data collection and resources as specified in Act itself and as discussed below.

Recipients should begin planning activities for their first tier subrecipients, including obtaining a DUNS number (or updating the existing DUNS record), and registering with the Central Contractor Registration (CCR).

Be advised that Recovery Act funds can be used in conjunction with other funding as necessary to complete projects, but tracking and reporting must be separate to meet the reporting requirements of the Recovery Act and related guidance. For projects funded by sources other than the Recovery Act, Contractors must keep separate records for Recovery Act funds and to ensure those records comply with the requirements of the Act.

The Government has not fully developed the implementing instructions of the Recovery Act, particularly concerning specific procedural requirements for the new reporting requirements. The Recipient will be provided these details as they become available. The Recipient must comply with all requirements of the Act. If the Recipient believes there is any inconsistency between ARRA requirements and current award terms and conditions, the issues will be referred to the Contracting Officer for reconciliation.

Definitions

For purposes of this clause, Covered Funds means funds expended or obligated from appropriations under the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5. Covered Funds will have special accounting codes and will be identified as Recovery Act funds in the grant, cooperative agreement or TIA and/or modification using Recovery Act funds. Covered Funds must be reimbursed by September 30, 2015.

For Official Use Only

Non-Federal employer means any employer with respect to covered funds --the contractor, subcontractor, grantee, or Recipient, as the case may be, if the contractor, subcontractor, grantee, or Recipient is an employer; and any professional membership organization, certification of other professional body, any agent or licensee of the Federal government, or any person acting directly or indirectly in the interest of an employer receiving covered funds; or with respect to covered funds received by a State or local government, the State or local government receiving the funds and any contractor or subcontractor receiving the funds and any contractor or subcontractor of the State or local government; and does not mean any department, agency, or other entity of the federal government.

Recipient means any entity that receives Recovery Act funds directly from the Federal government (including Recovery Act funds received through grant, loan, or contract) other than an individual and includes a State that receives Recovery Act Funds.

Special Provisions

A.	Flow Down Requirement

Recipients must include these special terms and conditions in any subaward.

B.	Segregation of Costs

Recipients must segregate the obligations and expenditures related to funding under the Recovery Act. Financial and accounting systems should be revised as necessary to segregate, track and maintain these funds apart and separate from other revenue streams. No part of the funds from the Recovery Act shall be commingled with any other funds or used for a purpose other than that of making payments for costs allowable for Recovery Act projects.

C.	Prohibition on Use of Funds

None of the funds provided under this agreement derived from the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, may be used by any State or local government, or any private entity, for any casino or other gambling establishment, aquarium, zoo, golf course, or swimming pool.

D.	Access to Records

With respect to each financial assistance agreement awarded utilizing at least some of the funds appropriated or otherwise made available by the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, any representative of an appropriate inspector general appointed under section 3 or 8G of the Inspector General Act of 1988 (5 U.S.C. App.) or of the Comptroller General is authorized --

(1)	to examine any records of the contractor or grantee, any of its subcontractors or subgrantees, or any State or local agency administering such contract that pertain to, and involve transactions that relate to, the subcontract, subcontract, grant, or subgrant; and

(2)	to interview any officer or employee of the contractor, grantee, subgrantee, or agency regarding such transactions.

E.	Publication

An application may contain technical data and other data, including trade secrets and/or privileged or confidential information, which the applicant does not want disclosed to the public or used by the Government for any purpose other than the application. To protect such data, the applicant should specifically identify each page including each line or paragraph thereof containing the data to be protected and mark the cover sheet of the application with the following Notice as well as referring to the Notice on each page to which the Notice applies:

For Official Use Only

Notice of Restriction on Disclosure and Use of Data

The data contained in pages ----of this application have been submitted in confidence and contain trade secrets or proprietary information, and such data shall be used or disclosed only for evaluation purposes, provided that if this applicant receives an award as a result of or in connection with the submission of this application, DOE shall have the right to use or disclose the data here to the extent provided in the award. This restriction does not limit the Government's right to use or disclose data obtained without restriction from any source, including the applicant.

Information about this agreement will be published on the Internet and linked to the website www.recovery.gov, maintained by the Accountability and Transparency Board. The Board may exclude posting contractual or other information on the website on a case-by-case basis when necessary to protect national security or to protect information that is not subject to disclosure under sections 552 and 552aof title 5, United States Code.

F.	Protecting State and Local Government and Contractor Whistleblowers.

The requirements of Section 1553 of the Act are summarized below. They include, but are not limited to:

Prohibition on Reprisals: An employee of any non-Federal employer receiving covered funds under the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, may not be discharged, demoted, or otherwise discriminated against as a reprisal for disclosing, including a disclosure made in the ordinary course of an employee's duties, to the Accountability and Transparency Board, an inspector general, the Comptroller General, a member of Congress, a State or Federal regulatory or law enforcement agency, a person with supervisory authority over the employee (or other person working for the employer who has the authority to investigate, discover or terminate misconduct), a court or grand jury, the head of a Federal agency, or their representatives information that the employee believes is evidence of:

-gross mismanagement of an agency contract or grant relating to covered funds;

-a gross waste of covered funds;

-a substantial and specific danger to public health or safety related to the implementation or use of covered funds;

-an abuse of authority related to the implementation or use of covered funds; or

-as violation of law, rule, or regulation related to an agency contract (including the competition for or negotiation of a contract) or grant, awarded or issued relating to covered funds.

Agency Action: Not later than 30 days after receiving an inspector general report of an alleged reprisal, the head of the agency shall determine whether there is sufficient basis to conclude that the non-Federal employer has subjected the employee to a prohibited reprisal. The agency shall either issue an order denying relief in whole or in part or shall take one or more of the following actions:

-Order the employer to take affirmative action to abate the reprisal.

-Order the employer to reinstate the person to the position that the person held before the reprisal, together with compensation including back pay, compensatory damages, employment benefits, and other terms and conditions of employment that would apply to the person in that position if the reprisal had not been taken.

-Order the employer to pay the employee an amount equal to the aggregate amount of all costs and expenses (including attorneys' fees and expert witnesses' fees) that were reasonably incurred by the employee for or in connection with, bringing the complaint regarding the reprisal, as determined by the head of a court of competent jurisdiction.

Nonenforceablity of Certain Provisions Waiving Rights and remedies or Requiring Arbitration: Except as provided in a collective bargaining agreement, the rights and remedies provided to aggrieved employees by this section may not be waived by any agreement, policy, form, or condition of employment, including any predispute arbitration agreement. No predispute arbitration agreement shall be valid or enforceable if it requires arbitration of a dispute arising out of this section.

Requirement to Post Notice of Rights and Remedies: Any employer receiving covered funds under the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, shall post notice of the rights and remedies as required therein. (Refer to section 1535 of the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, www.Recovery.gov, for specific requirements of this section and prescribed language for the notices).

For Official Use Only

G.	"RESERVED"

H. False Claims Act

Recipient and sub-recipients shall promptly refer to the DOE or other appropriate Inspector General any credible evidence that a principal, employee, agent, contractor, sub-grantee, subcontractor or other person has submitted a false claim under the False Claims Act or has committed a criminal or civil violation of laws pertaining to fraud, conflict of interest, bribery, gratuity or similar misconduct involving those funds.

I. Information in Support of Recovery Act Reporting

Recipient may be required to submit backup documentation for expenditures of funds under the Recovery Act including such items as timecards and invoices. Recipient shall provide copies of backup documentation at the request of the Contracting Officer or designee.

J. Availability of Funds

Funds appropriated under the Recovery Act and obligated to this award are available for reimbursement of costs until September 30, 2015.

K. Additional Funding Distribution and Assurance of Appropriate Use of Funds (As Applicable)

Certification by Governor --Not later than April 3, 2009, for funds provided to any State or agency thereof by the American Reinvestment and Recovery Act of 2009, Pub. L. 111-5, the Governor of the State shall certify that: 1) the state will request and use funds provided by the Act; and 2) the funds will be used to create jobs and promote economic growth.

Acceptance by State Legislature --If funds provided to any State in any division of the Act are not accepted for use by the Governor, then acceptance by the State legislature, by means of the adoption of a concurrent resolution, shall be sufficient to provide funding to such State.

Distribution --After adoption of a State legislature's concurrent resolution, funding to the State will be for distribution to local governments, councils of government, public entities, and public-private entities within the State either by formula or at the State's discretion.

L. Certifications (As Applicable)

With respect to funds made available to State or local governments for infrastructure investments under the American Recovery and Reinvestment Act of 2009, Pub. L. 111-5, the Governor, mayor, or other chief executive, as appropriate, certified by acceptance of this award that the infrastructure investment has received the full review and vetting required by law and that the chief executive accepts responsibility that the infrastructure investment is an appropriate use of taxpayer dollars. Recipient shall provide an additional certification that includes a description of the investment, the estimated total cost, and the amount of covered funds to be used for posting on the Internet. A State or local agency may not receive infrastructure investment funding from funds made available by the Act unless this certification is made and posted.

21. REPORTING AND REGISTRATION REQUIREMENTS UNDER SECTION 1512 OF THE RECOVERY ACT

For Official Use Only

(a) This award requires the recipient to complete projects or activities which are funded under the American Recovery and Reinvestment Act of 2009 (Recovery Act) and to report on use of Recovery Act funds provided through this award. Information from these reports will be made available to the public.

(b) The reports are due no later than ten calendar days after each calendar quarter in which the recipient receives the assistance award funded in whole or in part by the Recovery Act.

(c) Recipients and their first-tier sub-recipients must maintain current registrations in the Central Contractor Registration (http://www.ccr.gov) at all times during which they have active federal awards funded with Recovery Act funds. A Dun and Bradstreet Data Universal Numbering System (DUNS) Number (http://www.dnb.com) is one of the requirements for registration in the Central Contractor Registration.

(d) The recipient shall report the information described in section 1512(c) of the Recovery Act using the reporting instructions and data elements that will be provided online at http://www.FederaIReporting.gov and ensure that any information that is pre-filled is corrected or updated as needed.

22. REQUIRED USE OF AMERICAN IRON, STEEL, AND MANUFACTURED GOODS -- SECTION 1605 OF THE AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009

(a) Definitions. As used in this award term and condition--

(1) Manufactured good means a good brought to the construction site for incorporation into the building or work that has been--

(i) Processed into a specific form and shape; or

(ii) Combined with other raw material to create a material that has different properties than the properties of the individual raw materials.

(2) Public building and public work means a public building of, and a public work of, a governmental entity (the United States; the District of Columbia; commonwealths, territories, and minor outlying islands of the United States; State and local governments; and multi-State, regional, or interstate entities which have governmental functions). These buildings and works may include, without limitation, bridges, dams, plants, highways, parkways, streets, subways, tunnels, sewers, mains, power lines, pumping stations, heavy generators, railways, airports, terminals, docks, piers, wharves, ways, lighthouses, buoys, jetties, breakwaters, levees, and canals, and the construction, alteration, maintenance, or repair of such buildings and works.

(3) Steel means an alloy that includes at least 50 percent iron, between .02 and 2 percent carbon, and may include other elements.

(b) Domestic preference. (1) This award term and condition implements Section 1605 of the American Recovery and Reinvestment Act of 2009 (Recovery Act) (Pub. L. 111--5), by requiring that all iron, steel, and manufactured goods used in the project are produced in the United States except as provided in paragraph (b)(3) and (b)(4) of this section and condition.

(2) This requirement does not apply to the material listed by the Federal Government as follows: "NONE"

(3) The award official may add other iron, steel, and/or manufactured goods to the list in paragraph (b)(2) of this section and condition if the Federal Government determines that--

(i) The cost of the domestic iron, steel, and/or manufactured goods would be unreasonable. The cost of domestic iron, steel, or manufactured goods used in the project is unreasonable when the cumulative cost of such material will increase the cost of the overall project by more than 25 percent;

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(ii) The iron, steel, and/or manufactured good is not produced, or manufactured in the United States in sufficient and reasonably available quantities and of a satisfactory quality; or

(iii) The application of the restriction of section 1605 of the Recovery Act would be inconsistent with the public interest.

(c) Request for determination of inapplicability of Section 1605 of the Recovery Act. (l)(i) Any recipient request to use foreign iron, steel, and/or manufactured goods in accordance with paragraph (b)(3) of this section shall include adequate information for Federal Government evaluation of the request, including--

(A) A description of the foreign and domestic iron, steel, and/or manufactured goods;

(B) Unit of measure;

(D) Cost;

(E) Time of delivery or availability;

(F) Location of the project;

(G) Name and address of the proposed supplier; and

(H) A detailed justification of the reason for use of foreign iron, steel, and/or manufactured goods cited in accordance with paragraph (b)(3) of this section.

(ii) A request based on unreasonable cost shall include a reasonable survey of the market and a completed cost comparison table in the format in paragraph (d) of this section.

(iii) The cost of iron, steel, and/or manufactured goods material shall include all delivery costs to the construction site and any applicable duty.

(iv) Any recipient request for a determination submitted after Recovery Act funds have been obligated for a project for construction, alteration, maintenance, or repair shall explain why the recipient could not reasonably foresee the need for such determination and could not have requested the determination before the funds were obligated. If the recipient does not submit a satisfactory explanation, the award official need not make a determination.

(2) lf the Federal Government determines after funds have been obligated for a project for construction, alteration, maintenance, or repair that an exception to section 1605 of the Recovery Act applies, the award official will amend the award to allow use of the foreign iron, steel, and/or relevant manufactured goods. When the basis for the exception is nonavailability or public interest, the amended award shall reflect adjustment of the award amount, redistribution of budgeted funds, and/or other actions taken to cover costs associated with acquiring or using the foreign iron, steel, and/or relevant manufactured goods. When the basis for the exception is the unreasonable cost of the domestic iron, steel, or manufactured goods, the award official shall adjust the award amount or redistribute budgeted funds by at least the differential est ablished in 2 CFR 176.110(a).

(3) Unless the Federal Government determines that an exception to section 1605 of the Recovery Act applies, use of foreign iron, steel, and/or manufactured goods is noncompliant with section 1605 of the American Recovery and Reinvestment Act.

(d) Data. To permit evaluation of requests under paragraph (b) of this section based on unreasonable cost, the Recipient shall include the following information and any applicable supporting data based on the survey of suppliers:

For Official Use Only

Foreign and Domestic Items Cost Comparison

Description Unit of measure Quantity Cost

(dollars)*

[List name, address, telephone number, email address, and contact for suppliers surveyed. Attach copy of response; if oral, attach summary.]

[Include other applicable supporting information.]

[*Include all delivery costs to the construction site.]

23. REQUIRED USE OF AMERICAN IRON, STEEL, AND MANUFACTURED GOODS (COVERED UNDER INTERNATIONAL AGREEMENTS)--SECTION 1605 OF THE AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009

(a)	Definitions. As used in this award term and condition--

Designated country --(1) A World Trade Organization Government Procurement Agreement country (Aruba, Austria, Belgium, Bulgaria, Canada, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hong Kong, Hungary, Iceland, Ireland, Israel, Italy, Japan, Korea (Republic of), Latvia, Liechtenstein, Lithuania, Luxembourg, Malta, Netherlands, Norway, Poland, Portugal, Romania, Singapore, Slovak Republic, Slovenia, Spain, Sweden, Switzerland, and United Kingdom;

(2) A Free Trade Agreement (FTA) country (Australia, Bahrain, Canada, Chile, Costa Rica, Dominican Republic, EI Salvador, Guatemala, Honduras, Israel, Mexico, Morocco, Nicaragua, Oman, Peru, or Singapore); or

(3) A United States-European Communities Exchange of Letters (May 15, 1995) country: Austria, Belgium, Bulgaria, Cyprus, Czech Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Poland, Portugal, Romania, Slovak Republic, Slovenia, Spain, Sweden, and United Kingdom. Designated country iron, steel, and/or manufactured goods --( 1) Is wholly the growth, product, or manufacture of a designated country; or

(2) In the case of a manufactured good that consist in whole or in part of materials from another country, has been substantially transformed in a designated country into a new and different manufactured good distinct from the materials from which it was transformed.

Domestic iron, steel, and/or manufactured good --(1) Is wholly the growth, product, or manufacture of the United States; or

(2) In the case of a manufactured good that consists in whole or in part of materials from another country, has been substantially transformed in the United States into a new and different manufactured good distinct from the materials from which it was transformed. There is no requirement with regard to the origin of components or subcomponents in manufactured goods or products, as long as the manufacture of the goods occurs in the United States.

Foreign iron, steel, and/or manufactured good means iron, steel and/or manufactured good that is not domestic or designated country iron, steel, and/or manufactured good.

For Official Use Only

Manufactured good means a good brought to the construction site for incorporation into the building or work that has been--

(1) Processed into a specific form and shape; or

(2) Combined with other raw material to create a material that has different properties than the properties of the individual raw materials.

Public building and public work means a public building of, and a public work of, a governmental entity (the United States; the District of Columbia; commonwealths, territories, and minor outlying islands of the United States; State and local governments; and multi-State, regional, or interstate entities which have governmental functions). These buildings and works may include, without limitation, bridges, dams, plants, highways, parkways, streets, subways, tunnels, sewers, mains, power lines, pumping stations, heavy generators, railways, airports, terminals, docks, piers, wharves, ways, lighthouses, buoys, jetties, breakwaters, levees, and canals, and the construction, alteration, maintenance, or repair of such buildings and works.

Steel means an alloy that includes at least 50 percent iron, between .02 and 2 percent carbon, and may include other elements.

(b) Iron, steel, and manufactured goods. (1) The award term and condition described in this section implements--

(i) Section 1605(a) of the American Recovery and Reinvestment Act of 2009 (Pub. L. 111--5) (Recovery Act), by requiring that all iron, steel, and manufactured goods used in the project are produced in the United States; and

(ii) Section 1605(d), which requires application of the Buy American requirement in a manner consistent with U.S. obligations under international agreements. The restrictions of section 1605 of the Recovery Act do not apply to designated country iron, steel, and/or manufactured goods. The Buy American requirement in section 1605 shall not be applied where the iron, steel or manufactured goods used in the project are from a Party to an international agreement that obligates the recipient to treat the goods and services of that Party the same as domestic goods and services. This obligation shall only apply to projects with an estimated value of $7,443,000 or more.

(2) The recipient shall use only domestic or designated country iron, steel, and manufactured goods in performing the work funded in whole or part with this award, except as provided in paragraphs (b)(3) and (b)(4) of this section.

(3) The requirement in paragraph (b)(2) of this section does not apply to the iron, steel, and manufactured goods listed by the Federal Government as follows:

-----None -----

(4) The award official may add other iron, steel, and manufactured goods to the list in paragraph (b)(3) of this section if the Federal Government determines that--

(i) The cost of domestic iron, steel, and/or manufactured goods would be unreasonable. The cost of domestic iron, steel, and/or manufactured goods used in the project is unreasonable when the cumulative cost of such material will increase the overall cost of the project by more than 25 percent;

(ii) The iron, steel, and/or manufactured good is not produced, or manufactured in the United States in sufficient and reasonably available commercial quantities of a satisfactory quality; or

(iii)The application of the restriction of section 1605 of the Recovery Act would be inconsistent with the public interest.

For Official Use Only

(c) Request for determination of inapplicability of section 1605 of the Recovery Act or the Buy American Act. (l)(i) Any recipient request to use foreign iron, steel, and/or manufactured goods in accordance with paragraph (b)(4) of this section shall include adequate information for Federal Government evaluation of the request, including--

(A) A description of the foreign and domestic iron, steel, and/or manufactured goods;

(B) Unit of measure;

(D) Cost;

(E) Time of delivery or availability;

(F) Location of the project;

(G) Name and address of the proposed supplier; and

(H)A detailed justification of the reason for use of foreign iron, steel, and/or manufactured goods cited in accordance with paragraph (b)(4) of this section.

(ii) A request based on unreasonable cost shall include a reasonable survey of the market and a completed cost comparison table in the format in paragraph (d) of this section.

(iii) The cost of iron, steel, or manufactured goods shall include all delivery costs to the construction site and any applicable duty.

(2) If the Federal Government determines after funds have been obligated for a project for construction, alteration, maintenance, or repair that an exception to section 1605 of the Recovery Act applies, the award official will amend the award to allow use of the foreign iron, steel, and/or relevant manufactured goods. When the basis for the exception is nonavailability or public interest, the amended award shall reflect adjustment of the award amount, redistribution of budgeted funds, and/or other appropriate actions taken to cover costs associated with acquiring or using the foreign iron, steel, and/or relevant manufactured goods.. When the basis for the exception is the unreasonable cost of the domestic iron, steel, or manufactured goods, the award official shall adjust the award amount or redistribute budgeted funds, as appropriate, by at least the differential established in 2 CFR 176.110(a).

(3) Unless the Federal Government determines that an exception to section 1605 of the Recovery Act applies, use of foreign iron, steel, and/or manufactured goods other than designated country iron, steel, and/or manufactured goods is noncompliant with the applicable Act.

(d) Data. To permit evaluation of requests under paragraph (b) of this section based on unreasonable cost, the applicant shall include the following information and any applicable supporting data based on the survey of suppliers:

Foreign and Domestic Items Cost Comparison

Description Unit of measure Quantity Cost

(dollars)*

For Official Use Only

[List name, address, telephone number, email address, and contact for suppliers surveyed. Attach copy of response; if oral, attach summary.]

[Include other applicable supporting information.]

[*Include all delivery costs to the construction site.]

24. WAGE RATE REQUIREMENTS UNDER SECTION 1606 OF THE RECOVERY ACT (As Applicable)

(a) Section 1606 of the Recovery Act requires that all laborers and mechanics employed by contractors and subcontractors on projects funded directly by or assisted in whole or in part by and through the Federal Government pursuant to the Recovery Act shall be paid wages at rates not less than those prevailing on projects of a character similar in the locality as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code.

Pursuant to Reorganization Plan No. 14 and the Copeland Act, 40 U.S.C. 3145, the Department of Labor has issued regulations at 29 CFR parts 1,3, and 5 to implement the Davis-Bacon and related Acts. Regulations in 29 CFR 5.5 instruct agencies concerning application of the standard Davis-Bacon contract clauses set forth in that section. Federal agencies providing grants, cooperative agreements, and loans under the Recovery Act shall ensure that the standard Davis-Bacon contract clauses found in 29 CFR 5.5(a) are incorporated in any resultant covered contracts that are in excess of $2,000 for construction, alteration or repair (including painting and decorating).

(b) For additional guidance on the wage rate requirements of section 1606, contact your awarding agency. Recipients of grants, cooperative agreements and loans should direct their initial inquiries concerning the application of Davis-Bacon requirements to a particular federally assisted project to the Federal agency funding the project. The Secretary of Labor retains final coverage authority under Reorganization Plan Number 14.

25. RECOVERY ACT TRANSACTIONS LISTED IN SCHEDULE OF EXPENDITURES OF FEDERAL AWARDS AND RECIPIENT RESPONSIBILITIES FOR INFORMING SUBRECIPIENTS

(a) To maximize the transparency and accountability of funds authorized under the American Recovery and Reinvestment Act of 2009 (Pub. L. 111--5) (Recovery Act) as required by Congress and in accordance with 2 CFR 215.21 "Uniform Administrative Requirements for Grants and Agreements" and OMB Circular A--102 Common Rules provisions, recipients agree to maintain records that identify adequately the source and application of Recovery Act funds. OMB Circular A--102 is available at http://www.whitehouse.gov/omb/circulars/a102/al02.html.

(b) For recipients covered by the Single Audit Act Amendments of 1996 and OMB Circular A--133, "Audits of States, Local Governments, and Non-Profit Organizations," recipients agree to separately identify the expenditures for Federal awards under the Recovery Act on the Schedule of Expenditures of Federal Awards (SEFA) and the Data Collection Form (SF--SAC) required by OMB Circular A--133. OMB Circular A--133 is available at http://www.whitehouse.gov/omb/circulars/a133/a133.html.This shall be accomplished by identifying expenditures for Federal awards made under the Recovery Act separately on the SEFA, and as separate rows under Item 9 of Part III on the SF--SAC by CFDA number, and inclusion of the prefix "ARRA-" in identifying the name of the Federal program on the SEFA and as the first characters in Item 9d of Part III on the SF—SA C.

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(c) Recipients agree to separately identify to each subrecipient, and document at the time of subaward and at the time of disbursement of funds, the Federal award number, CFDA number, and amount of Recovery Act funds. When a recipient awards Recovery Act funds for an existing program, the information furnished to subrecipients shall distinguish the subawards of incremental Recovery Act funds from regular subawards under the existing program.

(d) Recipients agree to require their subrecipients to include on their SEFA information to specifically identify Recovery Act funding similar to the requirements for the Recipient SEFA described above. This information is needed to allow the Recipient to properly monitor subrecipient expenditure of ARRA funds as well as oversight by the Federal awarding agencies, Offices of Inspector General and the Government Accountability Office.

26. DAVIS BACON ACT AND CONTRACT WORK HOURS AND SAFETY STANDARDS ACT (NOV 2009) (If Applicable)

Definitions: For purposes of this clause, Clause 27, Davis Bacon Act and Contract Work Hours and Safety Standards Act, the following definitions are applicable:

(1) "Award" means any grant, cooperative agreement or technology investment agreement made with Recovery Act funds by the Department of Energy (DOE) to a Recipient. Such Award must require compliance with the labor standards clauses and wage rate requirements of the Davis-Bacon Act (DBA) for work performed by all laborers and mechanics employed by Recipients (other than a unit of State or local government whose own employees perform the construction) Subrecipients, Contractors, and subcontractors.

(2) "Contractor" means an entity that enters into a Contract. For purposes of these clauses, Contractor shall include (as applicable) prime contractors, Recipients, Subrecipients, and Recipients' or Subrecipients' contractors, subcontractors, and lower-tier subcontractors. "Contractor" does not mean a unit of State or local government where construction is performed by its own employees."

(3) "Contract" means a contract executed by a Recipient, Subrecipient, prime contractor, or any tier subcontractor for construction, alteration, or repair. It may also mean (as applicable) (i) financial assistance instruments such as grants, cooperative agreements, technology investment agreements, and loans; and, (ii) Sub awards, contracts and subcontracts issued under financial assistance agreements. "Contract" does not mean a financial assistance instrument with a unit of State or local government where construction is performed by its own employees.

(4) "Contracting Officer" means the DOE official authorized to execute an Award on behalf of DOE and who is responsible for the business management and non-program aspects of the financial assistance process.

(5) "Recipient" means any entity other than an individual that receives an Award of Federal funds in the form of a grant, cooperative agreement, or technology investment agreement directly from the Federal Government and is financially accountable for the use of any DOE funds or property, and is legally responsible for carrying out the terms and conditions of the program and Award.

(6) "Subaward" means an award of financial assistance in the form of money, or property in lieu of money, made under an award by a Recipient to an eligible Subrecipient or by a Subrecipient to a lower-tier subrecipient. The term includes financial assistance when provided by any legal agreement, even if the agreement is called a contract, but does not include the Recipient’s procurement of goods and services to carry out the program nor does it include any form of assistance which is excluded from the definition of “Award” above.

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(7) "Subrecipient" means a non-Federal entity that expends Federal funds received from a Recipient to carry out a Federal program, but does not include an individual that is a beneficiary of such a program.

(a) Davis Bacon Act

(1) Minimum wages.

(i) All laborers and mechanics employed or working upon the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), will be paid unconditionally and not less often than once a week, and, without subsequent deduction or rebate on any account (except such payroll deductions as are permitted by regulations issued by the Secretary of Labor under the Copeland Act (29 CFR part 3)), the full amount of wages and bona fide fringe benefits (or cash equivalents thereof) due at time of payment computed at rates not less than those contained in the wage determination of the Secretary of Labor regardless of any contractual relationship which may be alleged to exist between the Contractor and such laborers and mechanics.

Contributions made or costs reasonably anticipated for bona fide fringe benefits under section 1(b)(2) of the Davis-Bacon Act on behalf of laborers or mechanics are considered wages paid to such laborers or mechanics, subject to the provisions of paragraph (a)(I)(iv) of this section; also, regular contributions made or costs incurred for more than a weekly period (but not less often than quarterly) under plans, funds, or programs which cover the particular weekly period, are deemed to be constructively made or incurred during such weekly period. Such laborers and mechanics shall be paid the appropriate wage rate and fringe benefits on the wage determination for the classification of work actually performed, without regard to skill, except as provided in § 5.5(a)(4). Laborers or mechanics performing work in more than one c lassification may be compensated at the rate specified for each classification for the time actually worked therein, provided that the employer's payroll records accurately set forth the time spent in each classification in which work is performed. The wage determination (including any additional classification and wage rates conformed under paragraph (a)(1)(ii) of this section) and the Davis-Bacon poster (WH-1321) shall be posted at all times by the Contractor and its subcontractors at the site of the work in a prominent and accessible place where it can be easily seen by the workers.

(ii)(A) The Contracting Officer shall require that any class of laborers or mechanics, including helpers, which is not listed in the wage determination and which is to be employed under the Contract shall be classified in conformance with the wage determination. The Contracting Officer shall approve an additional classification and wage rate and fringe benefits therefore only when the following criteria have been met:

(1) The work to be performed by the classification requested is not performed by a classification in the wage determination;

(2) The classification is utilized in the area by the construction industry; and

(3) The proposed wage rate, including any bona fide fringe benefits, bears a reasonable relationship to the wage rates contained in the wage determination.

(B) If the Contractor and the laborers and mechanics to be employed in the classification (if known), or their representatives, and the Contracting Officer agree on the classification and wage rate (including the amount designated for fringe benefits where appropriate), a report of the action taken shall be sent by the contracting officer to the Administrator of the Wage and Hour Division, U.S. Department of Labor, Washington, DC 20210. The Administrator, or an authorized representative, will approve, modify, or disapprove every additional classification action within 30 days of receipt and so advise the Contracting Officer or will notify the Contracting Officer within the 30-day period that additional time is necessary.

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(C) In the event the Contractor, the laborers or mechanics to be employed in the classification or their representatives, and the Contracting Officer do not agree on the proposed classification and wage rate (including the amount designated for fringe benefits, where appropriate), the Contracting Officer shall refer the questions, including the views of all interested parties and the recommendation of the Contracting Officer, to the Administrator for determination. The Administrator, or an authorized representative, will issue a determination within 30 days of receipt and so advise the Contracting Officer or will notify the Contracting Officer within the 30day period that additional time is necessary.

(D) The wage rate (including fringe benefits where appropriate) determined pursuant to paragraphs (a)(l)(ii)(B) or (C) of this section, shall be paid to all workers performing work in the classification under this Contract from the first day on which work is performed in the classification.

(iii) Whenever the minimum wage rate prescribed in the Contract for a class of laborers or mechanics includes a fringe benefit which is not expressed as an hourly rate, the Contractor shall either pay the benefit as stated in the wage determination or shall pay another bona fide fringe benefit or an hourly cash equivalent thereof.

(iv) If the Contractor does not make payments to a trustee or other third person, the Contractor may consider as part of the wages of any laborer or mechanic the amount of any costs reasonably anticipated in providing bona fide fringe benefits under a plan or program, provided that the Secretary of Labor has found, upon the written request of the Contractor, that the applicable standards of the Davis-Bacon Act have been met. The Secretary of Labor may require the Contractor to set aside in a separate account assets for the meeting of obligations under the plan or program.

(2) Withholding. The Department of Energy or the Recipient or Subrecipient shall upon its own action or upon written request of an authorized representative of the Department of Labor withhold or cause to be withheld from the Contractor under this Contract or any other Federal contract with the same prime contractor, or any other federally-assisted contract subject to Davis Bacon prevailing wage requirements, which is held by the same prime contractor, so much of the accrued payments or advances as may be considered necessary to pay laborers and mechanics, including apprentices, trainees, and helpers, employed by the Contractor or any subcontractor the full amount of wages required by the Contract. In the event of failure to pay any laborer or mechanic, including any apprentice, trainee, or helper, employed or working on the site of the work (or under the United States Housing Act of 1937 or under the Housing Act of 1949 in the construction or development of the project), all or part of the wages required by the Contract, the Department of Energy, Recipient, or Subrecipient, may, after written notice to the Contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds until such violations have ceased.

(3) Payrolls and basic records.

(i) Payrolls and basic records relating thereto shall be maintained by the Contractor during the course of the work and preserved for a period of three years thereafter for all laborers and mechanics working at the site of the work (or under the United States Housing Act of 1937, or under the Housing Act of 1949, in the construction or development of the project). Such records shall contain the name, address, and social security number of each such worker, his or her correct classification, hourly rates of wages paid (including rates of contributions or costs anticipated for bona fide fringe

For Official Use Only

benefits or cash equivalents thereof of the types described in section 1(b)(2)(B) of the Davis-Bacon Act), daily and weekly number of hours worked, deductions made, and actual wages paid. Whenever the Secretary of Labor has found under 29 CFR 5.5(a)(1)(iv) that the wages of any laborer or mechanic include the amount of any costs reasonably anticipated in providing benefits under a plan or program described in section 1(b)(2)(B) of the Davis-Bacon Act, the Contractor shall maintain records which show that the commitment to provide such benefits is enforceable, that the plan or program is financially responsible, and that the plan or program has been communicated in writing to the laborers or mechanics affected, and records which show the costs anticipated or the actual cost incurred in providing such benefits. Contractors emplo ying apprentices or trainees under approved programs shall maintain written evidence of the registration of apprenticeship programs and certification of trainee programs, the registration of the apprentices and trainees, and the ratios and wage rates prescribed in the applicable programs.

(ii) (A) The Contractor shall submit weekly for each week in which any Contract work is performed a copy of all payrolls to the Department of Energy if the agency is a party to the Contract, but if the agency is not such a party, the Contractor will submit the payrolls to the Recipient or Subrecipient (as applicable), applicant, sponsor, or owner, as the case may be, for transmission to the Department of Energy. The payrolls submitted shall set out accurately and completely all of the information required to be maintained under 29 CFR 5.5(a)(3)(i), except that full social security numbers and home addresses shall not be included on weekly transmittals. Instead, the payrolls shall only need to include an individually identifying number for each employee (e.g., the last four digits of the employee's social security number). The required weekly payroll information may be submitted in any form desired. Optional Form WH-347 is available for this purpose from the Wage and Hour Division Web site at http://www.dol.gov/esa/whd/forms/wh347instr.htm or its successor site. The prime Contractor is responsible for the submission of copies of payrolls by all subcontractors. Contractors and subcontractors shall maintain the full social security number and current address of each covered worker, and shall provide them upon request to the Department of Energy if the agency is a party to the Contract, but if the agency is not such a party, the Contractor will submit them to the Recipient or Subrecipient (as applicable), applicant, sponsor, or owner, as the case may be, for transmission to the Department of Energy, the Contractor, or the Wage and Hour Division of the Department of Labor for purposes of an investigation or audit of compliance with prevailing wage requirements. It is not a violation of this section for a prime contractor to require a subcontractor to provide addresses and social security numbers to the pri me contractor for its own records, without weekly submission to the sponsoring government agency (or the Recipient or Subrecipient (as applicable), applicant, sponsor, or owner).

(B) Each payroll submitted shall be accompanied by a "Statement of Compliance," signed by the Contractor or subcontractor or his or her agent who pays or supervises the payment of the persons employed under the Contract and shall certify the following:

(1) That the payroll for the payroll period contains the information required to be provided under § 5.5 (a)(3)(ii) of Regulations, 29 CFR part 5, the appropriate information is being maintained under § 5.5 (a)(3)(i) of Regulations, 29 CFR part 5, and that such information is correct and complete;

(2) That each laborer or mechanic (including each helper, apprentice, and trainee) employed on the Contract during the payroll period has been paid the full weekly wages earned, without rebate, either directly or indirectly, and that no deductions have been made either directly or indirectly from the full wages

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earned, other than permissible deductions as set forth in Regulations, 29 CFR part 3;

(3) That each laborer or mechanic has been paid not less than the applicable wage rates and fringe benefits or cash equivalents for the classification of work performed, as specified in the applicable wage determination incorporated into the Contract.

(C) The weekly submission of a properly executed certification set forth on the reverse side of Optional Form WH-347 shall satisfy the requirement for submission of the "Statement of Compliance" required by paragraph (a)(3)(ii)(B) of this section.

(D) The falsification of any of the above certifications may subject the Contractor or subcontractor to civil or criminal prosecution under section 1001 of title 18 and section 3729 of title 31 of the United States Code.

(iii) The Contractor or subcontractor shall make the records required under paragraph (a)(3)(i) of this section available for inspection, copying, or transcription by authorized representatives of the Department of Energy or the Department of Labor, and shall permit such representatives to interview employees during working hours on the job. If the Contractor or subcontractor fails to submit the required records or to make them available, the Federal agency may, after written notice to the Contractor, sponsor, applicant, or owner, take such action as may be necessary to cause the suspension of any further payment, advance, or guarantee of funds. Furthermore, failure to submit the required records upon request or to make such records available may be grounds for debarment action pursuant to 29 CFR 5.12.

(4) Apprentices and trainees

(i) Apprentices. Apprentices will be permitted to work at less than the predetermined rate for the work they performed when they are employed pursuant to and individually registered in a bona fide apprenticeship program registered with the U.S. Department of Labor, Employment and Training Administration, Office of Apprenticeship Training, Employer and Labor Services, or with a State Apprenticeship Agency recognized by the Office, or if a person is employed in his or her first 90 days of probationary employment as an apprentice in such an apprenticeship program, who is not individually registered in the program, but who has been certified by the Office of Apprenticeship Training, Employer and Labor Services or a State Apprenticeship Agency (where appropriate) to be eligible for probationary employment as an apprentice. The allowable ratio of apprentices to journeymen on the job site in any craft classification shall not be greater than the ratio permitted to the Contractor as to the entire work force under the registered program. Any worker listed on a payroll at an apprentice wage rate, who is not registered or otherwise employed as stated above, shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any apprentice performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. Where a Contractor is performing construction on a project in a locality other than that in which its program is registered, the ratios and wage rates (expressed in percentages of the journeyman's hourly rate) specified in the Contractor's or subcontractor's registered program shall be observed. Every apprentice must be paid at not less than the rate specified in the registered program for the apprentice's level of progress, expressed as a percentage of the journeymen hourly rate specified in the applicable wage determination. Apprentices shall be paid fringe benefits in accordance with the provisions of the apprenticeship program. If the apprenticeship program does not specify fringe benefits, apprentices must be paid the full amount of fringe benefits listed on the wage determination for the applicable classification. If the Administrator determines that a different practice prevails for the applicable apprentice classification, fringes shall be paid in accordance with that determination. In the event the Office of Apprenticeship Training, Employer and Labor

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Services, or a State Apprenticeship Agency recognized by the Office, withdraws approval of an apprenticeship program, the Contractor will no longer be permitted to utilize apprentices at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

(ii) Trainees. Except as provided in 29 CFR 5.16, trainees will not be permitted to work at less than the predetermined rate for the work performed unless they are employed pursuant to and individually registered in a program which has received prior approval, evidenced by formal certification by the U.S. Department of Labor, Employment and Training Administration. The ratio of trainees to journeymen on the job site shall not be greater than permitted under the plan approved by the Employment and Training Administration. Every trainee must be paid at not less than the rate specified in the approved program for the trainee's level of progress, expressed as a percentage of the journeyman hourly rate specified in the applicable wage determination. Trainees shall be paid fringe benefits in accordance with the provisions of the trainee progra m. If the trainee program does not mention fringe benefits, trainees shall be paid the full amount of fringe benefits listed on the wage determination unless the Administrator of the Wage and Hour Division determines that there is an apprenticeship program associated with the corresponding journeyman wage rate on the wage determination which provides for less than full fringe benefits for apprentices. Any employee listed on the payroll at a trainee rate who is not registered and participating in a training plan approved by the Employment and Training Administration shall be paid not less than the applicable wage rate on the wage determination for the classification of work actually performed. In addition, any trainee performing work on the job site in excess of the ratio permitted under the registered program shall be paid not less than the applicable wage rate on the wage determination for the work actually performed. In the event the Employment and Training Administration withdraws approval of a training p rogram, the Contractor will no longer be permitted to utilize trainees at less than the applicable predetermined rate for the work performed until an acceptable program is approved.

(iii) Equal employment opportunity. The utilization of apprentices, trainees, and journeymen under this part shall be in conformity with the equal employment opportunity requirements of Executive Order 11246, as amended and 29 CFR part 30.

(5) Compliance with Copeland Act requirements. The Contractor shall comply with the requirements of29 CFR part 3, which are incorporated by reference in this Contract.

(6) Contracts and Subcontracts. The Recipient, Subrecipient, the Recipient's, and Subrecipient's contractors and subcontractor shall insert in any Contracts the clauses contained herein in(a)(l) through (10) and such other clauses as the Department of Energy may by appropriate instructions require, and also a clause requiring the subcontractors to include these clauses in any lower tier subcontracts. The Recipient shall be responsible for the compliance by any subcontractor or lower tier subcontractor with all of the paragraphs in this clause.

(7) Contract termination: debarment. A breach of the Contract clauses in 29 CFR 5.5 may be grounds for termination of the Contract, and for debarment as a contractor and a subcontractor as provided in 29 CFR 5.12.

(8) Compliance with Davis-Bacon and Related Act requirements. All rulings and interpretations of the Davis-Bacon and Related Acts contained in 29 CFR parts 1,3, and 5 are herein incorporated by reference in this Contract.

(9) Disputes concerning labor standards. Disputes arising out of the labor standards provisions of this Contract shall not be subject to the general disputes clause of this Contract. Such disputes shall be resolved in accordance with the procedures of the Department of Labor set forth in 29 CFR parts 5, 6, and 7. Disputes within the meaning of this clause include disputes between the Recipient, Subrecipient, the Contractor (or any of its subcontractors), and the contracting agency, the U.S. Department of Labor, or the employees or their representatives.

(10) Certification of eligibility.

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(i) By entering into this Contract, the Contractor certifies that neither it (nor he or she) nor any person or firm who has an interest in the Contractor's firm is a person or firm ineligible to be awarded Government contracts by virtue of section 3(a) of the Davis-Bacon Act or 29 CFR 5.I2(a)(1).

(ii) No part of this Contract shall be subcontracted to any person or firm ineligible for award of a Government contract by virtue ofsection3(a) of the Davis-Bacon Act or 29 CFR5.12(a)(1).

(iii) The penalty for making false statements is prescribed in the U.S. Criminal Code, 18 U.S.C. 1001.

(b) Contract Work Hours and Safety Standards Act. As used in this paragraph, the terms laborers and mechanics include watchmen and guards.

(1) Overtime requirements. No Contractor or subcontractor contracting for any part of the Contract work which may require or involve the employment of laborers or mechanics shall require or permit any such laborer or mechanic in any workweek in which he or she is employed on such work to work in excess of forty hours in such workweek unless such laborer or mechanic receives compensation at a rate not less than one and one-halftimes the basic rate of pay for all hours worked in excess of forty hours in such workweek.

(2)Violation; liability for unpaid wages; liquidated damages. In the event of any violation of the clause set forth in paragraph (b)(I) of this section, the Contractor and any subcontractor responsible therefore shall be liable for the unpaid wages. In addition, such Contractor and subcontractor shall be liable to the United States (in the case of work done under contract for the District of Columbia or a territory, to such District or to such territory), for liquidated damages. Such liquidated damages shall be computed with respect to each individual laborer or mechanic, including watchmen and guards, employed in violation of the clause set forth in paragraph (b)(I) of this section, in the sum of $10 for each calendar day on which such individual was required or permitted to work in excess of the standard workweek of forty hours without payment of the overtime wages required by the clause set forth in paragraph (b)(I) of this section.

(3) Withholding for unpaid wages and liquidated damages. The Department of Energy or the Recipient or Subrecipient shall upon its own action or upon written request of an authorized representative of the Department of Labor withhold or cause to be withheld, from any moneys payable on account of work performed by the Contractor or subcontractor under any such contract or any other Federal contract with the same prime Contractor, or any other federally-assisted contract subject to the Contract Work Hours and Safety Standards Act, which is held by the same prime contractor, such sums as may be determined to be necessary to satisfy any liabilities of such Contractor or subcontractor for unpaid wages and liquidated damages as provided in the clause set forth in paragraph (b)(2) of this section.

(4) Contracts and Subcontracts~ The Recipient, Subrecipient, and Recipient's and Subrecipient's contractor or subcontractor shall insert in any Contracts, the clauses set forth in paragraph (b)(1) through (4) of this section and also a clause requiring the subcontractors to include these clauses in any lower tier subcontracts. The Recipient shall be responsible for compliance by any subcontractor or lower tier subcontractor with the clauses set forth in paragraphs (b)(1) through (4) of this section.

(5) The Contractor or subcontractor shall maintain payrolls and basic payroll records during the course of the work and shall preserve them for a period of three years from the completion of the Contract for all laborers and mechanics, including guards and watchmen, working on the Contract. Such records shall contain the name and address of each such employee, social security number, correct classifications, hourly rates of wages paid, daily and weekly number of hours worked, deductions made, and actual wages paid. The records to be maintained under this paragraph shall be made available by the Contractor or subcontractor for inspection, copying, or transcription by authorized representatives of the Department of Energy and the Department of Labor, and the Contractor or subcontractor will permit such representatives to interview employee s during working hours on the job.

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(1) On behalf of the Department of Energy (DOE), Recipient shall perform the following functions:

(a) Obtain, maintain, and monitor all DBA certified payroll records submitted by the Subrecipients and Contractors at any tier under this Award;

(b) Review all DBA certified payroll records for compliance with DBA requirements, including applicable DOL wage determinations;

(c) Notify DOE of any non-compliance with DBA requirements by Subrecipients or Contractors at any tier, including any non-compliances identified as the result of reviews performed pursuant to paragraph (b) above;

(d) Address any Subrecipient and any Contractor DBA non-compliance issues; if DBA non-compliance issues cannot be resolved in a timely manner, forward complaints, summary of investigations and all relevant information to DOE;

(e) Provide DOE with detailed information regarding the resolution of any DBA non-compliance issues;

(f) Perform services in support of DOE investigations of complaints filed regarding noncompliance by Subrecipients and Contractors with DBA requirements;

(g) Perform audit services as necessary to ensure compliance by Subrecipients and Contractors with DBA requirements and as requested by the Contracting Officer; and

(h) Provide copies of all records upon request by DOE or DOL in a timely manner.

(2) All records maintained on behalf of the DOE in accordance with paragraph (1) above are federal government (DOE) owned records. DOE or an authorized representative shall be granted access to the records at all times.

(3) In the event of, and in response to any Freedom of Information Act, 5 U.S.C. 552, requests submitted to DOE, Recipient shall provide such records to DOE within 5 business days of receipt of a request from DOE.

27. GOVERNMENT INSIGHT

DOE and the Recipient are bound to each other by a duty of good faith and best effort to achieve the goals of the Project. DOE and the Recipient agree to provide early notification to each other of problems or issues which may arise in the performance of this Project, and to work collaboratively to resolve problems.

The Recipient is responsible for the overall Project, including execution, technical and project management, reporting, financial and administrative matters.

In recognition of the significance of this Project to the nation's energy infrastructure and energy agenda the Recipient agrees to provide additional access to project related information. The DOE Program Manager or their designee will be provided access, on a non-interference basis, to technical and project status meetings or tests via telephone or in person to better understand the progress and challenges of the Project. DOE may participate in meetings, reviews, and tests and may provide input and comment but has no right of approval or direction. The Recipient shall notify the DOE Program Manager of meetings, reviews, or tests and provide related documents reasonably in advance to permit insight. The Recipient is not expected to delay any aspect of performance to accommodate DOE insight.

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DOE federal employees are subject to the provisions of the Trade Secrets Act. If DOE contractor support personnel participate they shall be subject to appropriate obligations of confidentiality to DOE.

28. NO COST EXTENSION -REQUIREMENT FOR TIMELY DELIVERABLES

In recognition of the significance of this Project to the nation's energy infrastructure and energy agenda the DOE requests any extension to the Project period be coordinated in advance, in writing, with the cognizant DOE Contracting Officer. The Recipient is requested to provide a proposed end date, the reason for the extension, an explanation how the Project will be completed by the proposed end date, a positive statement that the available funding on the award is adequate to complete the Project, and a positive statement that all Project costs will be submitted to DOE in sufficient time to allow for payment no later than September 30, 2015.

If DOE agrees with the need for an extension and the request is fully supported the Contracting Officer shall issue a modification to the award with the revised project period.

The Recipient does have the right to unilaterally extend the award one time for up to one year. However, any one-time, no cost extension will not change the requirements for deliverables or milestone dates unless agreed to in writing by DOE.

29. FAILURE TO RECEIVE OR RECISSION OF REGULATORY AND OTHER REQUIRED PROJECT APPROVALS

In the event the project fails to secure required approval(s) from a Public Utility Commission or similar regulatory or other body required to grant approvals for the project to proceed, or prior approvals are rescinded, the Recipient shall immediately notify the DOE Contracting Officer and Technical Project Officer. In addition, the Recipient shall immediately halt project work on the portion of the project that was subject to required approval(s). Within three working days of the notification of such event, the DOE Contracting Officer and Technical Project Officer shall initiate an examination, with the Recipient, of the impact of the withheld or withdrawn approvals on the project's objectives. This review shall include, but is not limited to, the Recipient's continued ability to provide their cost share; the ability to meet the project 's technical objectives; the ability of the project to complete data and metrics objectives, including agreed to consumer behavior studies; the ability of the project to complete work on schedule. Upon completion of the examination of the impact, the Contracting Officer will issue direction as to whether the project shall proceed as planned, proceed in a modified form or be terminated. If the project is modified or terminated, the recipient will not be liable for repayment of DOE funds received and reimbursed. Further, if the project is modified or terminated, DOE shall maintain its responsibility to pay its share of all allowable project costs incurred by the recipient but not yet submitted for reimbursement to DOE through the date of termination. The DOE will have the unilateral right to deobligate any federal funds over and above those required to meet our reduced obligation.

30. PROJECT DELIVERABLES

A. CYBER SECURITY PLAN

The Recipient is required to submit to the DOE Technical Project Officer, a plan for how it will address cyber security requirements. Failure to submit an acceptable cyber security plan within a reasonable time frame may result in termination of the award. In addition, failure to effectively implement the DOE approved cyber security plan may result in termination of the award.

The cyber security plan shall describe the Recipient's approach to detect, prevent, communicate with regard to, respond to, or recover from system security incidents. The plan shall address the following areas from both a technical and a management (organizational) perspective:

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•	Risk Assessment (focusing on vulnerabilities and impact);

•	Risk Mitigation (focusing on vulnerabilities and impact);

•	Standards;

•	Quality Assurance;

•	Impact on Overall Grid Security.

This plan shall be consistent with the cyber security approach provided in the proposal, modified or enhanced as necessary to address any issues identified by DOE during negotiations. The plan is to be submitted within 30 calendar days of the date the Contracting Officer signs the award agreement. Thereafter, the Contracting Officer will provide approval or non-approval with comments. If the Recipient is required to resubmit its plan, the revised plan is due within 15workingdays of receipt of DOE's comments.

B. PROJECT EXECUTION PLAN

The Recipient is required to submit to the DOE Technical Project Officer a draft Project Execution Plan (PEP) within 30 calendar days of the date the Contracting Officer signs the award agreement and a final PEP within 60 days of the date the Contracting Officer signs the award agreement in the format outlined below. The elements of the Project Execution Plan should be consistent with the Management Plan, Project Schedule, and Risk Management discussions contained in the Recipient's proposal in the application submitted in response to Funding Opportunity Announcement Number DE-FOA-0000058 and with the detailed budget submission.

The intent of the Project Execution Plan is to provide the DOE with appropriate understanding and insight into the approach and methodology the Recipient will use to manage the project to successful completion. The Recipient is expected to use a set of tailored project management tools and techniques in the management of their projects. It will also provide the baseline against which the Recipient will provide status of progress on project execution. This clause is not intended to limit or restrict the Recipient's ability to implement any management systems or controls deemed necessary for the management of the project, except as otherwise provided by law or this agreement.

The PEP provided to DOE will contain the following items:

•	A description of the project including the end product or end result being accomplished

•	Work Breakdown Structure (WBS) to Level 2, with dictionary

•	Integrated Schedule

•	Performance Measurement Baseline (PMB)

•	A Listing of Major Project Milestones tied to the WBS and PMB

•	The Project Responsibility Assignment Matrix for the WBS

•	Project Risk Management Plan

The methodology and approach used to meet the various requirements listed in the PEP should be tailored appropriately in consideration of the complexity, cost, and risks of each project. Requirements must be addressed to the extent necessary and practical for managing the project. Tailoring may involve consolidation of decisions, documentation, substituting equivalent documents, or concurrency of processes. Tailoring does not imply the omission of essential elements.

All of the PEP elements or an equivalent will be required for all projects, but their initial character/attributes and subsequent implementation can vary based on project size.

A common structure for reporting the current status of SGIG projects will be used to deliver project status and assessment information to DOE. SGIG projects will provide the following data. These data will be compiled into status reports to assist DOE in its reporting requirements under the Recovery Act.

The Recipient shall use the following template to submit the Project Execution Plan Template;

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Section 1 -Cover and Signature Pages

1.1 Cover Page

The cover page should include the .title of the document, document control number, project name, project number, site name, document date, restrictions or classification (as applicable), and any appropriate disclaimers.

1.2 Revisions Page

All revision numbers and associated dates should be captured along with the date the document was approved.

1.3 Signature Page

The signature page(only one page in length) is the second page and should contain the following:

•	Project name and number

•

Site name

•

Date

•	Restrictions or classification

•	Approval authority

•	Signature block for the primary author

1.4 Table of Contents

The document table of contents should include lists of tables and figures.

1.5 Acronyms List

The list should include acronyms used in the document and their definitions.

Section 2 -Main Body

2.1 Introduction

In this section, the awardee should briefly describe the PEP and the major participants involved in the project. Example text is provided below.

This document is the Project Execution Plan (PEP)for the name of SGIG Project. It sets forth roles and responsibilities, project baselines, and project risks.

This PEP will be updated as required and reviewed at least annually until the project is complete.

2.2 Project Description

Provide a summary-level description of the project, including:

•	Project objectives

•	Major system components and their functions

•	Major project assumptions and uncertainties

2.3 Management Structure

The project organization should be described, including an organization chart that identifies the various participants, their roles and responsibilities, interfaces and reporting relationships. If certain vendors or contractors have not yet been chosen, identify their roles in a generic fashion.

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Section 3 –Tailoring Strategy

This section should document how the PEP requirements will be met through a tailored application of project management and project controls.

Tailoring is a flexible approach that allows appropriate levels of effort or analytical rigor to be used in fulfilling all requirements. Tailoring does not mean waiving requirements, nor does it imply the omission of essential elements in the acquisition process.

Section 4 -Project Baseline

4.1 Performance Management Baseline (PMB)

The PMB is a time-phased budget plan for accomplishing work, against which performance is measured. It includes the budgets assigned to scheduled control accounts and the applicable indirect budgets. The PMB should represent the monetized value of all work expected to be accomplished under the project. It represents the Budgeted Cost of Work Scheduled (BCWS) element in the online web-based Project Management Reporting System.

Technical performance parameters and deliverables should define key features of the project and how it/they will perform when completed at Project Close Out including characteristics (quantity, size, etc.), functions, requirements, or the design basis that, if changed, would have a major impact on system or facility performance. It includes all costs for both Federal and recipient.

4.1.1 Work Breakdown Structure (WBS) and WBS Dictionary

The WBS is the product-oriented grouping of project elements that organize and define the total scope of the project. A WBS Dictionary is a listing of WBS elements with a short description of the work scope content in each element. The Dictionary helps ensure consistent understanding and use of the WBS elements among all of the WBS users.

Provide WBS Level 2 and WBS Dictionary listing of work breakdown structure elements with a short description of the work scope content in each element. For the purposes of the PEP due to DOE, WBS Levell should be the project that the SGIG grant is funding, e.g., Smart Grid West Virginia.

4.1.2 Integrated Schedule

The integrated schedule should display duration and linkages of the various tasks required to accomplish the project and should display the project's critical path. Preferentially the integrated schedule will be provided as a Gantt chart with the task identified and planned start and completion dates listed.

4.2 List of Major Project Milestones

Provide a list of the major project milestones. Examples of the types of major milestones could be the completion of design for communications architecture, initiation of Phase I meter installation, and receipt of state Public Utilities Commission (PUC) approval. The list should describe the milestone and the planned milestone date. If using an early start/late start milestone planning approach, identify which date.

4.3 Project Responsibility Assignment Matrix

The Project Responsibility Assignment Matrix allocates responsibility for accomplishment of the outcome of a specific element identified in the WBS to a specific individual.

Section 5 -Project Risk Management/Oversight

5.1. Risk Management

A Risk Management Plan (RMP) should be prepared to identify and manage those events that could threaten the project's success. The RMP should describe the policies and practices for managing risk

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and a summary of the results of your risk analysis. The identification, evaluation, associated handling strategy or action, and the ultimate disposition of each risk should be documented.

To the extent that it covers these factors, the risk management section of your proposal can be used as the RMP.

At a minimum, the RMP should comprise a table that provides the following risk event information

Event ID

No.

Event Title

Event Description

Likelihood

Occurrence

Event Consequence

Handling Strategy

Cost/Schedule Impact

Comments

C. METRICS AND BENEFITS REPORTING PLAN

The Recipient is required to develop and implement a plan for the collection and reporting of project related metrics and benefits, as stated in the Smart Grid Investment Grant (SGIG) Funding Opportunity Announcement (DE-FOA-000058). This information will be used by DOE to assess the impact of smart grid technology deployed by the SGIG program. More information on the types of metrics and benefits DOE is interested in examining are provided in the "Guidebook for ARRA Smart Grid Program Metrics and Benefits" (Guidebook), dated December 7, 2009. The Recipient is encouraged to work collaboratively with DOE to seek guidance and clarification regarding questions in completing its Metrics and Benefits Reporting Plan.

1. Plan Outline

The Recipient shall be responsible for developing and submitting a Metrics and Benefits Plan that is consistent with its SGIG proposal and provides a sufficiently detailed description of how metrics information will be developed and reported to DOE. The Metrics and Benefits Plan shall include at a minimum the following information:

·	Discussion of Project Metrics and Benefits:

o	An identification with pertinent descriptions of the specific build and impact metrics that will be reported to DOE. The metrics will apply to the total project supported both by DOE and cost-shared funds. These metrics are described in more detail in Appendix A of the Guidebook.

Sufficient information so that build metrics can be correlated with numbers and types of customers (i.e., residential, commercial, industrial), the extent of service area covered, and how funding is allocated against equipment, as well as with other related build metrics (e.g., type of dynamic pricing program correlated with metering features). Build metrics will include the numbers and types of jobs created.

o	A description of the types of data, including their characteristics (e.g., frequency of measurement, units), and the calculations used to derive impact metrics. Assumptions or ranges of input values used should be provided.

o	A description of how impact metrics would lead to benefits with recommendations for how benefits would be quantitatively estimated.

o	Baseline values for each build and impact metric, including the basis and methods applied for calculating baseline information (e.g., application of normalization, averaging or forecasting approaches).

·	Implementation:

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o	Provide a schedule showing how the reporting of build and impact metrics coincides with the deployment of smart grid technology and key decision milestones (e.g., implementation of approved dynamic pricing tariffs).

o	Present approaches for collaboration between DOE and the Recipient (including representative organizations) to discuss key issues and share valuable information derived from the project.

·	Reporting:

o	Present the schedule for reporting build and impact metrics and benefits, as specified in Attachment B, Federal Assistance Reporting Checklist and Instructions.

2. Consistency and Data Quality

DOE expects to work collaboratively with the Recipient to develop consistency and quality in the methods used to calculate metrics and develop appropriate baselines. It is the Recipient's responsibility to collect and assemble data required to produce the metrics and benefits. In addition, the Recipient shall be available to answer questions DOE may have regarding how the metrics were developed.

3. Plan Development and Submittal

Within 60 days following the award of a grant, the Recipient is required to submit to DOE a draft Metrics and Benefits Reporting Plan. The Recipient is encouraged to work collaboratively with DOE to seek guidance and clarification regarding questions in completing the Metrics and Benefits Reporting Plan. The Recipient shall submit a draft final Metrics and Benefits Reporting Plan within 30 days following the receipt of written comments from DOE. The draft final plan will be considered final once approved by DOE.

D. CONSUMER BEHAVIOR STUDY PLAN

Special Note: This clause only applies to recipients who proposed in their application submitted in response to the Funding Opportunity Announcement Number DE-FOA-0000058 to conduct a consumer behavior study with control and randomized treatment groups. Recipients may opt out of this program after discussion with their Technical Project Officer.

Recipients who proposed conducting a consumer behavior study with control and randomized treatment groups, as stated in the Smart Grid Investment Grant (SGIG) Funding Opportunity Announcement (DEFOA-000058) are required to develop and implement a plan to carefully evaluate the behavior of consumers with respect to the dynamic pricing of electricity rates. More information on the approach recommended for these studies, including the types of data that would be made available, is provided in Appendix D of the "Guidebook for ARRA Smart Grid Program Metrics and Benefits" (Guidebook), dated December 7, 2009, as amended from time to time.

Within 90 days following the award of a grant, the Recipient is required to submit to DOE a Consumer Behavior Study Plan. In addition, the Recipient is required to submit interim and final Evaluation Reports (Attachment B, Federal Assistance Reporting Checklist and Instructions). The Recipient is encouraged to work closely with DOE in developing this plan, as well as throughout the study period. DOE expects that final submitted Consumer Behavior Study Plan shall be consistent with the requirements of the SGIG FOA, and adhere to well-established and theoretically appropriate methods.

1. Plan Outline

The Recipient is responsible for developing and submitting a Consumer Behavior Study Plan consistent with its SGIG proposal and provide a more detailed description of how the dynamic pricing

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with randomization component of its project will be designed, implemented, evaluated, and reported to DOE. The Consumer Behavior Study Plan shall include at a minimum the following:

·	Project Design:

o	Identify key research questions to be addressed in the project;

o	Describe how the project will be marketed to customers and how customers will participate (e.g., opt-in, opt-out, randomly assigned);

o	Describe the target population and sample and how it will be stratified and developed;

o	Describe control and treatment groups that will be represented (e.g., pricing, technology, education) and how customers will be assigned to each group (e.g., opt-in, opt-out, randomly assigned) based on desired levels of confidence and precision within the analysis;

o	Describe the specific rate design(s) that will be tested and controlled for, as well as what price levels will be used;

o	Describe specific enabling technologies, if any, that will be tested and controlled for;

o	Describe the specific feedback information approaches and/or methods, if any, that will be tested and controlled for;

Describe customer characteristic information that will be collected from each participant (see Appendix D of the Guidebook for minimum requirements) and methods that will be used to collect this information (e.g., field survey, utility customer database). Stipulate if this information will be reported to DOE at the customer level or the customer-cohort level. If results are reported at the customer-cohort level, the Recipient shall ensure that cohort level data has at least three customers in each "cell."

·	Implementation:

o	Provide a milestone schedule for the implementation phase of the project, including expected dates for obtaining regulatory approval and for submitting the draft Evaluation Report, as specified in Attachment B, Federal Assistance Reporting Checklist and Instructions;

o	Describe how the target sample will be maintained throughout the duration of the project;

o	Describe the data collection process that will be required for the evaluation.

·	Evaluation:

o	Describe methodology that will be used to evaluate the key research questions;

o	Describe data requirements to complete the evaluation;

o	Describe what kinds of information will be reported as an output from the evaluation.

·	Data Reporting:

o	Describe the frequency of reporting with respect to the Consumer Behavior Study Plan, Interim and Final Evaluation Reports, and data, as specified in Attachment B, Federal Assistance Reporting Checklist and Instructions.

2. Regulatory Approval Process

Where required, the Recipient shall seek approval from the applicable regulatory authority and/or oversight body to implement the dynamic pricing with randomization project.

If the Recipient receives approval from the applicable regulatory body and/or oversight board for the dynamic pricing with randomization project consistent with what is specified in the approved Consumer Behavior Study Plan, the study may proceed under current funding levels.

31. ADVANCE UNDERSTANDING FOR FEDERAL INCOME TAX TREATMENT

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The Recipient and the Department of Energy (DOE) understand that the Recipient’s project scope, budget and project execution plan are based on the assumption that the Smart Grid Investment Grant (SGIG) funds provided by DOE will be considered nontaxable income under Internal Revenue Code (IRC) 118(a). As of the date of this Agreement, the Internal Revenue Service (“IRS”) has not yet issued guidance or otherwise made a determination regarding the applicability of IRC 118(a) under the SGIG program. For this reason and so that the Recipient is not prejudiced by an IRS determination following the execution of this Agreement, the process set out below will be followed in the circumstances described:

(A) In the event the IRS declines to issue guidance by May 1, 2010 providing that some or all of SGIG grant funds may be treated as nontaxable income under IRC 118(a) under the terms and conditions of this Agreement, Recipient may elect to reopen this Agreement for negotiation as provided for below.

(B) In the event IRS determines that terms and conditions which differ from those contained in this Agreement would permit all or some of the SGIG funds to be treated as nontaxable income and in the event DOE offers to modify the standard terms and conditions for other SGIG recipients in order to cause all or some portion of the SGIG grant funds to be treated by IRS as nontaxable capital contributions, the DOE Contracting Officer shall notify the Recipient of the proposed modification(s).

(C) Within the earliest of (i) thirty calendar days after delivery of a notification by DOE that the IRS has advised that the IRS has declined to issue guidance providing that some or all of SGIG grant funds may be treated as nontaxable income under IRC 118(a); (ii) fourteen calendar days after the date of notice from the Contracting Officer of a modification of the Agreement provided for in (B) above to support treatment as nontaxable capital contributions; or (iii) by May 14, 2010 if IRS has failed to issue guidance by May 1, 2010, the Recipient shall notify the DOE Contracting Officer and Technical Project Officer as to whether the Recipient elects (1) to proceed with the project as planned, or (2) to reopen this Agreement (including the scope of the project) for negotiation to reflect impacts to the project. If Recipient elects to reo pen this Agreement for negotiations, DOE and Recipient shall dedicate authorized representatives to negotiate in good faith.

(D) If the parties have not satisfactorily concluded negotiations after a period of sixty calendar days: (i) DOE may elect to terminate such negotiations; (ii) Recipient may elect to terminate such negotiations and may, but shall not be required to, terminate this Agreement in its entirety in accordance with 10 C.F.R. § 600.351(a) (3). If the project is modified or terminated pursuant to this Provision of the Agreement, allowable costs will not include costs incurred after the effective date of the termination and the Recipient authorizes DOE to deobligate amounts in excess of the amounts incurred at the effective date of the termination. In the event of modification of the project scope or termination of the Agreement pursuant to this Provision, DOE shall have no liability for any termination costs. If the project is modified or ter minated pursuant to this Section 31, Recipient shall not be liable for repayment of DOE funds received that are otherwise allowable through the date of such modification or termination.

Applicant Name: NV Energy

Award Number: DE-FOA-0000058

Attachment A

Budget Information - Non Construction Programs

Section A - Budget Summary
		Estimated Unobligated Funds		New or Revised Budget
Grant Program Function or Activity (a)	Catalog of Federal Domestic Assistance Number (b)	Federal (c)	Non-Federal (d)	Federal (e)	Non-Federal (f)	Total (g)
1. Smart Grid Investment Grant (ARRA)	81.122	n/a	n/a	$137,877,906	$137,877,906	$275,755,813
2.						$0
3.						$0
4.						$0
5. Totals		$0	$0	$137,877,906	$137,877,906	$275,755,813
Section B - Budget Categories
		Grant Program, Function or Activity
6. Object Class Categories		(1) Smart Grid Investment Grant	(2)	(3)	(4)	Total (5)
a. Personnel		$11,273,887				$11,273,887
b. Fringe Benefits		$10,750,057				$10,750,057
c. Travel		$0				$0
d. Equipment		$15,197,836				$15,197,836
e. Supplies		$158,922,295				$158,922,295
f. Contractual		$71,445,959				$71,445,959
g. Construction		$0				$0
h. Other		$0				$0
i. Total Direct Charges (sum of 6a-6h)		$267,590,035	$0	$0	$0	$267,590,035
j. Indirect Charges		$8,165,778				$8,165,778
k. Totals (sum of 6i-6j) *		$275,755,813	$0	$0	$0	$275,755,813

7. Program Income		n/a				$0

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Section C - Non-Federal Resources
(a) Grant Program		(b) Applicant	(c) State	(d) Other Sources	(e) Totals
8. Smart Grid Investment Grant (ARRA)		$137,877,906	$0	$0	$137,877,906
9.					$0
10					$0
11.					$0
12. Total (sum of lines 8-11)		$137,877,906	$0	$0	$137,877,906
Section D - Forecasted Cash Needs
	Total for 1st Year	1st Quarter	2nd Quarter	3rd Quarter	4th quarter
13. Federal	$18,271,361	$4,567,840	$4,567,840	$4,567,840	$4,567,840
14. Non-Federal	$18,271,361	$4,567,840	$4,567,840	$4,567,840	$4,567,840
15. Total (sum of lines 13 and 14)	$36,542,721	$9,135,680	$9,135,680	$9,135,680	$9,135,680
Section E - Budget Estimates of Federal Funds Needed for Balance of the Project
		Future Funding Periods (Years)
(a) Grant Program		(b) First (2010)	(c) Second (2011)	(d) Third (2012)	(e) Fourth
16. Smart Grid investment Grant (ARRA)		$18,271,361	$62,623,448	$56,983,098	n/a
17.
18.
19.
20. Total (sum of lines 16-19)		$18,271,361	$62,623,448	$56,983,098	$0
Section F - Other Budget Information
21. Direct Charges n/a		22. Indirect Charges	n/a
23. Remarks This Budget Information file addresses total costs for NVE during entirety of the project. * Advanced Service Delivery project gas costs, amounting to $25,496,142, are not included

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Instructions for the SF-424A

Public Reporting Burden for this collection of information is estimated to average 3.0 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Please do not return your completed form to the Office of Management and Budget, send it to the address provided by the sponsoring agency.

General Instructions

This form is designed so that application can be made for funds from one or more grant programs. In preparing the budget, adhere to any existing Federal grantor agency guidelines which prescribe how and whether budgeted amounts should be separately shown for different functions or activities within the program. For some programs, grantor agencies may require budgets to be separately shown by function or activity. For other programs, grantor agencies may require a breakdown by function or activity. Sections A, B, C, and D should include budget estimates for the whole project except when applying for assistance which requires Federal authorization in annual or other funding period increments. In the later case, Sections A, B, C, and D should provide the budget for the first budget period (usually a year) and Section E should present the nee d for Federal assistance in the subsequent budget periods. All applications should contain a breakdown by the object class categories shown in Lines a-k of Section B.

Section A. Budget Summary Lines 1-4 Columns (a) and (b)

For applications pertaining to a single Federal grant program (Federal Domestic Assistance Catalog number) and not requiring a functional or activity breakdown, enter on Line 1 under Column (a) the catalog program title and the catalog number in Column (b).

For applications pertaining to a single program requiring budget amounts by multiple functions or activities, enter the name of each activity or function on each line in Column (a), and enter the catalog number in Column (b). For applications pertaining to multiple programs where none of the programs require a breakdown by function or activity, enter the catalog program title on each line in Column (a) and the respective catalog number on each line in Column (b).

For applications pertaining to multiple programs where one or more programs require a breakdown by function or activity, prepare a separate sheet for each program requiring the breakdown. Additional sheets should be used when one form does not provide adequate space for all breakdown of data required. However, when more than one sheet is used, the first page should provide the summary totals by programs.

Lines 1-4, Columns (c) through (g)

For new applications, leave Columns (c) and (d) blank. For each line entry in Columns (a) and (b), enter in Columns (e), (f), and (g) the appropriate amounts of funds needed to support the project for the first funding period (usually a year).

For continuing grant program applications, submit these forms before the end of each funding period as required by the grantor agency. Enter in Columns (c) and (d) the estimated amounts of funds which will remain unobligated at the end of the grant funding period only if the Federal grantor agency instructions provide for this. Otherwise, leave these columns blank. Enter in columns (e) and (f) the amounts of funds needed for the upcoming period. The amount(s) in Column (g) should be the sum of amounts in Columns (e) and (f).

For supplemental grants and changes to existing grants, do not use Columns (c) and (d). Enter in Column (e) the amount of the increase or decrease of Federal funds and enter in Column (f) the amount of the increase or decrease of non-Federal funds. In Column (g) enter the new total budgeted amount (Federal and non-Federal) which includes the total previous authorized budgeted amounts plus or minus, as appropriate, the amounts shown in Columns (e) and (f). The amount(s) in Column (g) should not equal the sum of amounts in Columns (e) and (f).

Line 5—Show the totals for all columns used.

Section B. Budget Categories

In the column headings (a) through (4), enter the titles of the same programs, functions, and activities shown on Lines 1-4, Column (a), Section A. When additional sheets are prepared for Section A, provide similar column headings on each sheet. For each program, function or activity, fill in the total requirements for funds (both Federal and non-Federal) by object class categories.

Lines 6a-i—Show the totals of Lines 6a to 6h in each column.

Line 6j—Show the amount of indirect cost.

Line 6k—Enter the total of amounts on Lines 6i and 6j For all applications for new grants and continuation grants the total amount in column (5), Line 6k, should be the same as the total amount shown in Section A, Column (g), Line 5. For supplemental grants and changes to grants, the total amount of the increase or decrease as shown in Columns (1)-(4), Line 6k should be the same as the sum of the amounts in Section A, Columns (e) and (f) on Line 5.

Line 7—Enter the estimated amount of income, if any, expected to be generated from this project. Do not add or subtract this amount from the total project amount. Show under the program narrative statement the nature and source of income. The estimated amount of program income may be considered by the federal grantor agency in determining the total amount of the grant.

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Section C. Non-Federal Resources

Lines 8-11—Enter amounts of non-Federal resources that will be used on the grant. If in-kind contributions are included, provide a brief explanation on a separate sheet.

Column (a)—Enter the program titles identical to Column (a), Section A. A breakdown by function or activity is not necessary.

Column (b)—Enter the contribution to be made by the applicant.

Column (c)—Enter the amount of the State's cash and in-kind contribution if the applicant is not a State or State agency. Applicants which are a State or State agencies should leave this column blank.

Column (d)—Enter the amount of cash and in-kind contributions to be made from all other sources.

Column (e)—Enter totals of Columns (b), (c), and (d).

Line 12—Enter the total for each of Columns (b)-(e). The amount in Column (e) should be equal to the amount on Line 5, Column (f) Section A.

Section D. Forecasted Cash Needs

Line 13—Enter the amount of cash needed by quarter from the grantor agency during the first year.

Line 14—Enter the amount of cash from all other sources needed by quarter during the first year.

Line 15—Enter the totals of amounts on Lines 13 and 14.

Section E. Budget Estimates of Federal Funds Needed for Balance of the Project

Lines 16-19—Enter in Column (a) the same grant program titles shown in Column

(a), Section A. A breakdown by function or activity is not necessary. For new applications and continuation grant applications, enter in the proper columns amounts of Federal funds which will be needed to complete the program or project over the succeeding funding periods (usually in years). This section need not be completed for revisions (amendments, changes, or supplements) to funds for the current year of existing grants.

If more than four lines are needed to list the program titles, submit additional schedules as necessary.

Line 20—Enter the total for each of the Columns (b)-(e). When additional schedules are prepared for this Section, annotate accordingly and show the overall totals on this line.

Section F. Other Budget Information

Line 21—Use this space to explain amounts for individual direct object-class cost categories that may appear to be out of the ordinary or to explain the details as required by the Federal grantor agency.

Line 22—Enter the type of indirect rate (provisional, predetermined, final or fixed) that will be in effect during the funding period, the estimated amount of the base to which the rate is applied, and the total indirect expense.

Line 23—Provide any other explanations or comments deemed necessary.

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DOE F 4600.2	Attachment B
(2/09)	U.S. Department of Energy
All Other Editions Are Obsolete	FEDERAL ASSISTANCE REPORTING CHECKLIST

AND INSTRUCTIONS

1. Identification Number: DE-OE0000205		2. Program/Project Title: NV Energy, Inc. Smart Grid Advanced Service Delivery (ASD) Project
3. Recipient: NV Energy
4. Reporting Requirements:		Frequency	No. of Copies	Addressees
A. MANAGEMENT REPORTING x Progress Report x Special Status Report		M/Q A	1 1	Carrie N. Brown/ donald.macdonald@nuclear.energy.gov
B. SCIENTIFIC /TECHNICAL REPORTING (Reports/Products must be submitted with appropriate DOE F 241. The 241 forms are available at www.osti.gov/elink.)		Not Applicable		Carrie N. Brown donald.macdonald@nuclear.energy.gov
Report/Product £ Final Scientific/Technical Report £ Conference papers/proceedings* £ Software/Manual £ Other (see special instructions) *Scientific and technical conferences only	Form DOEF 241.3 DOEF 241.3 DOE F 241.4 DOE F 241.3			http://www.osti.gov/elink-2413 http://www.osti.gov/elink-2413 http://www.osti.gov/estsc/241-4pre.jsp
C. FINANCIAL REPORTING x SF-425 Federal Financial Report		Q	1	Carrie N. Brown/ donald.macdonald@nuclear.energy.gov
D. CLOSEOUT REPORTING £ Patent Certification x Property Certification £ Other		F	1	Carrie N. Brown/ donald.macdonald@nuclear.energy. gov Carrie N. Brown/ donald.macdonald@nuclear.energy. gov
E. OTHER REPORTING £ Annual Indirect Cost Proposal x Annual Inventory of Federally Owned Property, if any T Other - Recovery Act		Y Q, S, A	1 1	Carrie N. Brown/ donald.macdonald@nuclear.energy. gov
FREQUENCY CODES AND DUE DATES: A- Within 5 calendar days after events or as specified. F - Final; 90 calendar days after expiration or termination of the award. Y - Yearly; 90 days after the end of the reporting period. S - Semiannually; within 30 days after end of the reporting period. Q - Quarterly; within 30 days after end of the reporting period. M- Monthly

*A11 submissions to DOE shall be by e-mail.

5. Special Instructions:

Other Reporting:

Details regarding the data elements set forth below are provided in the "Guidebook for ARRA Smart Grid Program Metrics and Benefits", or Guidebook, dated December 7, 2009, provided separately.

A. Reporting of Cumulative Jobs Created/Retained

•

For the first six months of this award the Recipient must report the data specified in this section on a monthly basis beginning with the quarter of the effective date of the award. After the six month period the reporting frequency shall be quarterly unless the Office of Management and Budget authorizes continued monthly reporting.

•	Recipient will provide the data required in this section via a mutually agreed upon format and media to DOE.

•	Recipients will report the cumulative number of jobs directly created or retained by project and activity or contract. Recipients will be required to report these direct jobs numbers by labor categories, as provided below:

•

Managers

•

Engineers

•

Computer-related Occupations

•

Environmental and Social Scientists

•

Construction, Electrical and Other Trades

•

Analysts,

•

Business Occupations

•

Recording, Scheduling, Computer Operator Occupations

•

A job created is a new position created and filled or an existing unfilled position that is filled as a result of the Recovery Act; a job retained is an existing position that would not have been continued to be filled were it not for Recovery Act funding. A job cannot be counted as both created and retained. Also, only compensated employment in the United States or outlying areas should be counted. See 74 FR 14824 for definitions.

•

The estimate of the number of jobs required by the Recovery Act should be expressed as "full-time equivalents" (FTE), which is calculated as total hours worked in jobs created or retained divided by the number of hours in a full-time schedule, defined here as 2,080 hours per calendar year. The FTE estimates must be reported cumulatively each calendar quarter.

•	Prime recipients of these grants must include in the aggregate number an estimate of jobs created and retained on projects and activities managed by their funding sub-recipients (including prime and sub-prime contractors).

•

Recipients will have the option to report on the employment impact on materials and equipment suppliers and central service providers (so-called "indirect" jobs). Employees who are not directly charged to Recovery Act supported projects/activities, who, nonetheless, provide critical indirect support are considered indirect jobs created/retained. Recipients will not be required to report on the employment impact on the local community ("induced" jobs).

•

The requirement for reporting jobs is based on a simple calculation used to avoid overstating the number of other than full-time, permanent jobs. This calculation converts part-time or temporary jobs into "full-time equivalent" (FTE) jobs. In order to perform the calculation, a recipient will need the total number of hours worked that are funded by the Recovery Act by category and the total number of hours worked for the entire project by labor category. The number of hours in a full-time schedule for a quarter will equal 520 (one-quarter of 2,080).

The two formulas for reporting Cumulative Jobs Created/Retained are represented as:

"Cumulative Recovery Act Funded Hours Worked (qtr l...n)" divided by

"cumulative hours in a full-time schedule"

"Cumulative Total Project Hours Worked (qtr l...n)" divided by

"cumulative hours in a full-time schedule"

B. Reporting Requirements for Metrics and Benefits

The recipient is required to report Build Metrics on a quarterly basis and Impact Metrics and Benefits on a semi-annual basis following the award date. Baseline data will be provided as specified within the Metrics and Benefits Reporting Plan. The recipient will provide this information in a mutually agreed upon format and media to a location identified by DOE.

C. Reporting Requirements for Consumer Behavior Studies

Special Note: This section only applies to recipients who proposed in their application submitted in response to the Funding Opportunity Announcement Number DE-FOA-0000058 to conduct a consumer behavior study with control and randomized treatment groups

C.1 Evaluation Reports

Participating recipients shall submit a comprehensive interim Evaluation Report, within 360 days following commencement of the Consumer Behavior Study, and a final Evaluation report at completion of the study, as specified in the Consumer Behavior Study Plan. Participating recipients shall submit a draft of both the interim and final Evaluation Reports to DOE and make a good faith effort to address issues raised by DOE in the final version of the Evaluation Reports. The Evaluation Reports shall include at a minimum:

1.	Overview of the project, including its goals;

2.	Description of how the project was designed and implemented to achieve these goals;

3.	Synopsis of the evaluation framework and methodology; and

4.	Summary of the results and lessons learned.

The Final Evaluation Report will be made available to the public; confidential information should not be included. C.2 Provision of Project Data

The recipient shall be responsible for submitting comprehensive data that was used, or served as the foundation, for the analysis of the dynamic pricing with randomization project, as defined within the Consumer Behavior Study Plan. Please refer to Appendix D of the Guidebook. The recipient will provide customer-level data in a mutually agreed upon formal and media to DOE, or an entity designated by DOE (e.g. a national laboratory). It is expected that the data provided to DOE shall have gone through the necessary quality assurance processes internal to the recipient in order to ensure the data is accurate and complete. This data shall be consistent with requirements outlined in the final submitted Consumer Behavior Study Plan.

The data will be publicly available for subsequent analysis and evaluation for those interested in assessing and better understanding the impacts that dynamic pricing enabled by the smart grid can have on customer behavior. The identity of specific customers shall not be included with the data. To protect customer confidentiality, masked customer identifiers shall be provided for individual customers.

It is expected that the data will include at a minimum the following data elements for each customer: 1) hourly interval data for electric consumption, tariff pricing (i.e., retail rate level in effect), and weather; 2) customer characteristics (as described in Appendix D of the Guidebook); and 3) hourly electricity usage data for 12-18 months prior to the dynamic pricing project.

Federal Assistance Reporting Instructions (2/09)

A. MANAGEMENT REPORTING

Progress Report

The Progress Report must provide a concise narrative assessment of the status of work and include the following information and any other information identified under Special Instructions on the Federal Assistance Reporting Checklist. The Recipient must report data specified in this section monthly for the first six months of the award and quarterly thereafter unless the monthly frequency is approved by the Office of Management and Budget. The Recipient will provide the data required in the Progress Report via an e-mail or mutually agreed upon format and media.

1. The DOE award number and name of the recipient.

2. The project title and name of the project director/principal investigator.

Date of report and period covered by the report.

A comparison of the actual accomplishments with the goals and objectives established for the period and reasons why the established goals were not met.

A discussion of what was accomplished under these goals during this reporting period, including major activities, significant results, major findings or conclusions, key outcomes or other achievements. This section should not contain any proprietary data or other information not subject to public release. If such information is important to reporting progress, do not include the information, but include a note in the report advising the reader to contact the Principal Investigator or the Project Director for further information.

6. Any changes in approach or aims and reasons for change. Remember significant changes to the objectives and scope require prior approval by the contracting officer.

7. Actual or anticipated problems or delays and actions taken or planned to resolve them.

8. Any absence or changes of key personnel or changes in consortium/teaming arrangement.

9. A description of any product produced or technology transfer activities accomplished during this reporting period, such as:

A.	Publications (list journal name, volume, issue); conference papers; or other public releases of results.

B.	Web site or other Internet sites that reflect the results of this project.

C. Networks or collaborations fostered.

10. The receipient will provide monthly project execution data in a mutually agreed upon format and media to DOE. It is expected that the dataset provided to DOE shall have gone through the necessary quality assurance processes internal to the recipient in order to ensure the data is accurate and complete.

A. Project Value Management System (PVMS) Reporting --The input of PVMS data described below will be required. PVMS reporting will be at the Project Level.

Field		Definition/Metrics	Field Type
ACWP	Actual Cost of Work Performed	The cost actually incurred for the work accomplished during the month.	Input
BCWP	Budgeted Cost of Work Performed	Sum of all budgets for all completed work and the completed portions of ongoing work. Total budget for the scope that was actually accomplished during the month.	Input
BCWS	Budgeted Cost of Work Scheduled	Planned accomplishment established in performance measurement baseline.	Input
ETC	Estimate to Complete	Current estimate for the remaining project scope. This is the estimate for all remaining work excluding contingencies.	Input
BAC	Budget at Completion	Sum of all budgets allocated to a project excluding management reserve.	Input

B. Risk Management Data Reporting - Recipients will submit updates of the Risk Management Plan (RMP) to DOE in the event of changes to the risk profile data required as part of the Project Execution Plan (PEP).

Special Status Report

The recipient must report the following events by e-mail as soon as possible after they occur:

1. Developments that have a significant favorable impact on the project.

2. Problems, delays, or adverse conditions which materially impair the recipient's ability to meet the objectives of the award or which may require DOE to respond to questions relating to such events from the public. The recipient must report any of the following incidents and include the anticipated impact and remedial action to be taken to correct or resolve the problem/condition:

a.	Any single fatality or injuries requiring hospitalization of five or more individuals.

b.	Any significant environmental permit violation.

c.	Any verbal or written Notice of Violation or any Environmental, Safety, and Health statutes.

d.	Any incident which causes a significant process or hazard control system failure.

e.	Any event which is anticipated to cause a significant schedule slippage or cost increase.

f.	Any damage to Government-owned equipment in excess of $50,000.

g.	Any other incident that has the potential for high visibility in the media.

B. SCIENTIFIC/TECHNICAL REPORTS - Not applicable to this award.

Final Scientific/Technical Report

Content. The final scientific/technical report must include the following information and any other information identified under Special Instructions on the Federal Assistance Reporting Checklist:

Identify the DOE award number; name of recipient; project title; name of project director/principal investigator; and consortium/teaming members.

Display prominently on the cover of the report any authorized distribution limitation notices, such as patentable material or protected data. Reports delivered without such notices may be deemed to have been furnished with unlimited rights, and the Government assumes no liability for the disclosure, use or reproduction of such reports.

Provide an executive summary, which includes a discussion of 1) how the research adds to the understanding of the area investigated; 2) the technical effectiveness and economic feasibility of the methods or techniques investigated or demonstrated; or 3) how the project is otherwise of benefit to the public. The discussion should be a minimum of one paragraph and written in terms understandable by an educated layman.

Provide a comparison of the actual accomplishments with the goals and objectives of the project.

Summarize project activities for the entire period of funding, including original hypotheses, approaches used, problems encountered and departure from planned methodology, and an assessment of their impact on the project results. Include, if applicable, facts, figures, analyses, and assumptions used during the life of the project to support the conclusions.

Identify products developed under the award and technology transfer activities, such as:

a. Publications (list journal name, volume, issue), conference papers, or other public releases of results;

b. Web site or other internet sites that reflect the results of this project;

c. Networks or collaborations fostered;

d. Technologies/Techniques;

e. Inventions/Patent Applications, licensing agreements; and

f. Other products, such as data or databases, physical collections, audio or video, software or netware, models, educational aid or curricula, instruments or equipment.

For projects involving computer modeling, provide the following information with the final report:

a. Model description, key assumptions, version, source and intended use;

b. Performance criteria for the model related to the intended use;

c. Test results to demonstrate the model performance criteria were met (e.g., code verification/validation, sensitivity analyses, history matching with lab or field data, as appropriate);

d. Theory behind the model, expressed in non-mathematical terms;

e. Mathematics to be used, including formulas and calculation methods;

f. Whether or not the theory and mathematical algorithms were peer reviewed, and, if so, include a summary of theoretical strengths and weaknesses;

g. Hardware requirements; and

h. Documentation (e.g., users guide, model code).

Electronic Submission. The final scientific/technical report must be submitted electronically-via the DOE Energy Link System (E-Link) accessed at http://www.osti.gov/elink-2413.

Electronic Format. Reports must be submitted in the ADOBE PORTABLE DOCUMENT FORMAT (PDF) and be one integrated PDF file that contains all text, tables, diagrams, photographs, schematic, graphs, and charts.

Submittal Form. The report must be accompanied by a completed electronic version of DOE Form 241.3, "U.S. Department of Energy (DOE), Announcement of Scientific and Technical Information (STI)." You can complete, upload, and submit the DOE F 241.3 online via E-Link. You are encouraged not to submit patentable material or protected data in these reports, but if there is such material or data in the report, you must: (1) clearly identify patentable or protected data on each page of the report; (2) identify such material on the cover of the report; and (3) mark the appropriate block in Section K of the DOE F 241.3. Reports must not contain any limited rights data (proprietary data), classified information, information subject to export control classification, or other info rmation not subject to release. Protected data is specific technical data, first produced in the performance of the award that is protected from public release for a period of time by the terms of the award agreement.

Protected Personally Identifiable Information (PII). Management Reports must not contain any Protected PII. PII is any information about an individual which can be used to distinguish or trace an individual's identity. Some information that is considered to be PII is available in public sources such as telephone books, public websites, university listings, etc. This type of information is considered to be Public PII and includes, for example, first and last name, address, work telephone number, e-mail address, home telephone number, and general educational credentials. In contrast,

Protected PII is defined as an individual’s first name or first initial and last name in combination with any one or more of types of information, including, but not limited to, social security number, passport number, credit card numbers, clearances, bank numbers, biometrics, date and place of birth, mother’s maiden name, criminal, medical and financial records, educational transcripts, etc.

Conference Papers/Proceedings

Content: The recipient must submit a copy of any conference papers/proceedings, with the following information: (1) Name of conference; (2) Location of conference; (3) Date of conference; and (4) Conference sponsor.

Electronic Submission. Scientific/technical conference paper/proceedings must be submitted· electronically-via the DOE Energy Link System (E-Link) at http://www.osti.gov/elink-2413. Non-scientific/technical conference papers/proceedings must be sent to the URL listed on the Reporting Checklist.

Electronic Format. Conference papers/proceedings must be submitted in the ADOBE PORTABLE DOCUMENT FORMAT (PDF) and be one integrated PDF file that contains all text, tables, diagrams, photographs, schematic, graphs, and charts.

Submittal Form. Scientific/technical conference papers/proceedings must be accompanied by a completed DOE Form 241.3. The form and instructions are available on E-Link at http://www.osti.gov/elink-2413.This form is not required for non-scientific or non-technical conference papers or proceedings.

Software/Manual_Not applicable to this award.

Content. Unless otherwise specified in the award, the following must be delivered: source code, the executable object code and the minimum support documentation needed by a competent user to understand and use the software and to be able to modify the software in subsequent development efforts.

Electronic Submission. Submissions may be submitted electronically-via the DOE Energy Link System (E-Link) at http://www.osti.gov/estsc/241-4pre.jsp. They may also be submitted via regular mail to:

Energy Science and Technology Software Center

P.O. Box 1020

Oak Ridge, TN 37831

Submittal Form. Each software deliverable and its manual must be accompanied by a completed DOE Form 241.4 “Announcement of U.S. Department of Energy Computer Software." The form and instructions are available on E-Link at http://www.osti.gov/estsc/241-4pre.jsp.

C. FINANCIAL REPORTING

Recipients must complete the SF-425 as identified on the Reporting Checklist in accordance with the report instructions. A fillable version of the form is available at http://www.whitehouse.gov/omb/grants/grants_forms.aspx.

D. CLOSEOUT REPORTS

Final Invention and Patent Report - Not applicable to this award.

The recipient must provide a DOE Form 2050.11, “PATENT CERTIFICATION.” This form is available at http://www.directives.doe.gov/pdfs/forms/2050-11.pdf and http://management.energy.gov/business_doe/business_forms.htm.

Property Certification

The recipient must provide the Property Certification, including the required inventories of non-exempt property, located at http://management.energy.gov/business doe/business forms. htm.

E. OTHER REPORTING

Annual Indirect Cost Proposal and Reconciliation

Requirement. In accordance with the applicable cost principles, the recipient must submit an annual indirect cost proposal, reconciled to its financial statements, within six months after the close of the fiscal year, unless the award is based on a predetermined or fixed indirect rate(s), or a fixed amount for indirect or facilities and administration (F&A) costs.

Cognizant Agency. The recipient must submit its annual indirect cost proposal directly to the cognizant agency for negotiating and approving indirect costs.

Annual Inventory of Federally Owned Property

Requirement. If at any time during the award the recipient is provided Government-furnished property or acquires property with project funds and the award specifies that the property vests in the Federal Government (i.e. federally owned property), the recipient must submit an annual inventory of this property no later than October 30th of each calendar year, to cover an annual reporting period ending on the preceding September 30th .

Content of Inventory. The inventory must include a description of the property, tag number, acquisition date, location of property, and acquisition cost, if purchased with project funds. The report must list all federally owned property, including property located at subcontractor's facilities or other locations.

Attachment C

Intellectual Property Provisions

Nonresearch and Development

For all recipient organizations, the following intellectual property provisions shall apply:

(a)	Recipients may copyright any work that is subject to copyright and was developed under an award. DOE reserves a royalty-free, nonexclusive and irrevocable right to reproduce, publish or otherwise use the work for Federal purposes and to authorize others to do so.

(b)	The DOE has the right to: (l) obtain, reproduce, publish or otherwise use the data first produced under an award; and (2) authorize others to receive, reproduce, publish or otherwise use such data for Federal purposes.

Nonprofit organizations are additionally subject to the intellectual property requirements set forth at 10 CFR 600.136(d).

For certain "impact metrics" data which Recipients are required to report pursuant to Attachment B, Federal Assistance Reporting Checklist, Section 5.B (Special Instructions - Other Reporting, Reporting Requirements for Metrics and Benefits), Recipients may mark such data, as set forth below, as "Commercially Valuable Smart Grid Data", and shall deliver such data to the National Renewable Energy Laboratory (NREL), and not to DOE.

COMMERCIALLY VALUABLE SMART GRID DATA

Recipient agrees to deliver to the National Renewable Energy Laboratory (NREL) all "impact metrics" data as described in the Guidebook for ARRA Smart Grid Program Metrics and Benefits, dated Dec. 7, 2009, as amended from time to time, to be submitted by the Recipient in accordance with its Metrics and Benefits Reporting Plan as required pursuant to Attachment B, Federal Assistance Reporting Checklist, Section 5.B (Special Instructions - Other Reporting, Reporting Requirements for Metrics and Benefits), of this agreement.

Based on information identified above that has been and will be provided by Recipient, the parties agree that the data required to be delivered to NREL under this clause has commercial value and its disclosure would cause competitive harm to the commercial value or use of the data.

In accordance with 10 C.F.R. 1004.3(e), Recipient shall mark any such data to be delivered to NREL with the following legend:

"Commercially Valuable Smart Grid Technical Data and Information. Withhold from Disclosure under 10 C.F.R. 1004.3(e). The use of this data by NREL is governed by the provisions of the DOE grant. Unless compelled by a court of competent jurisdiction, there may be no public release of this data to the public without the written consent of the Recipient and DOE. Aggregate data that does not identify company-specific impact metric information may be released as set forth in the grant."

Other information required to be delivered, but not covered under this Commercially Valuable Smart Grid Data clause, shall be delivered in accordance with Attachment B, Federal Assistance Reporting Checklist and Instructions, to this agreement.

Attachment D

NATIONAL POLICY ASSURANCES TO BE INCORPORATED AS AWARD TERMS

(August 2008)

To the extent that a term does not apply to a particular type of activity or award, it is self-deleting.

I. Nondiscrimination Policies

You must comply with applicable provisions of the following national policies prohibiting discrimination:

1 On the basis of race, color, or national origin, in Title VI of the Civil Rights Act of 1964 (42 U.S.C. 2000d et seq.), as implemented by DOE regulations at 10 CFR part 1040;

2 On the basis of sex or blindness, in Title IX of the Education Amendments of 1972 (20 U.S.C. 1681 et seq.), as implemented by DOE regulations at 10 CFR parts 1041 and 1042;

3 On the basis of age, in the Age Discrimination Act of 1975 (42 U.S.C.61 01 et seq.), as implemented by Department of Health and Human Services regulations at 45 CFR part 90 and DOE regulations at 10 CFR part 1040;

4 On the basis of disability, in Section 504 of the Rehabilitation Act of 1973 (29 U.S.C. 794), as implemented by Department of Justice regulations at 28 CFR part 41 and DOE regulations at 10 CFR part 1041;

5 On the basis of race, color, national origin, religion, disability, familial status, and sex under Title VIII of the Civil Rights Act (42 U.S.C. 3601 et seq.) as implemented by the Department of Housing and Urban Development at 24 CFR part 100; and

6 On the basis of disability in the Architectural Barriers Act of 1968 (42 U.S.C. 4151 et seq.) for the design, construction, and alteration of buildings and facilities financed with Federal funds.

II. Environmental Policies

You must:

1 Comply with applicable provisions of the Clean Air Act (42 U.S.C.7401, et. seq.) and Clean Water Act (33 U.S.C. 1251, et. seq.), as implemented by Executive Order 11738 [3 CFR, 1971-1975 Comp., p. 799] and Environmental Protection Agency rules at 40 CFR part 32, Subpart J.

2 Immediately identify to us, as the awarding agency, any potential impact that you find this award may have on:

a. The quality of the human environment, including wetlands, and provide any help we may need to comply with the National Environmental Policy Act (NEPA, at 42 U.S.C. 4321 et. seq.) and assist us to prepare Environmental Impact Statements or other environmental documentation. In such cases, you may take no action that will have an adverse environmental impact (e.g., physical disturbance of a site such as breaking of ground) or limit the choice of reasonable alternatives until we provide written notification of Federal compliance with NEPA, as implemented by DOE at 10 CFR part 1021.

b. Flood-prone areas, and provide any help we may need to comply with the National Flood Insurance Act of 1968 and Flood Disaster Protection Act of 1973 (42 U.S.C. 4001 et. seq.), which required flood insurance, when available, for Federally assisted construction or acquisition in flood-prone areas, as implemented by DOE at 10 CFR part 1022.

c. Use of land and water resources of coastal zones, and provide any help we may need to comply with the Coastal Zone Management Act of 1972 (16 U.S.C. 1451, et. seq.).

d. Coastal barriers along the Atlantic and Gulf coasts and Great Lakes' shores, and provide help we may need to comply with the Coastal Barriers Resource Act (16 U.S.C. 3501 et. seq.), concerning preservation of barrier resources.

e. Any existing or proposed component of the National Wild and Scenic Rivers system, and provide any help we may need to comply with the Wild and Scenic Rivers Act of 1968 (16 U.S.C. 1271 et seq.).

f. Underground sources of drinking water in areas that have an aquifer that is the sole or principal drinking water source, and provide any help we may need to comply with the Safe Drinking Water Act (42 U.S.C. 300h-3).

3 Comply with applicable provisions of the Lead-Based Paint Poisoning Prevention Act (42 U.S.C. 4821-4846), as implemented by the Department of Housing and Urban Development at 24 CFR part 35. The requirements concern lead-based paint in housing owned by the Federal Government or receiving Federal assistance.

4 Comply with section 6002 of the Resource Conservation and Recovery Act of 1976, as amended (42 U.S.C. 6962), and implementing regulations of the Environmental Protection Agency, 40 CFR Part 247, which require the purchase of recycled products by States or political subdiv'ision of States.

III. Live Organisms

1 Human research subjects. You must protect the rights and welfare of individuals that participate as human subjects in research under this award in accordance with the Common Federal Policy for the Protection of Human Subjects (45 CFR part 46), as implemented by DOE at 10 CFR part 745.

2 Animals and plants.

a. You must comply with applicable provisions of Department of Agriculture rules at 9 CFR parts 1-4 that implement the Laboratory Animal Welfare Act of 1966 (7 U.S.C. 2131-2156) and provide for humane transportation, handling, care, and treatment of animals used in research, experimentation, or testing under this award.

b. You must follow the guidelines in the National Academy of Sciences (NAS) Publication "Guide for the Care and Use of Laboratory Animals" (1996, which may be found currently at http://www.nap.edu/readingroom/books/labrats/) and comply with the Public Health Service Policy and Government principles Regarding the Care and use of animals (included as Appendix D to the NAS Guide).

c. You must immediately identify to us, as the awarding agency, any potential impact that you find this award may have on endangered species, as defined by the Endangered Species Act of 1973, as amended (“the Act,” 16 U.S.C. 1531-1543), and implementing regulations of the Departments of the Interior (50 CFR parts 10-24) and Commerce (50 CFR parts 217-227). You also must provide any help we may need to comply with 16 U.S.C. 1536(a)(2). This is not in lieu of responsibilities you have to comply with provisions of the Act that apply directly to you as a U.S. entity, independent of receiving this award.

IV. Other National Policies

1 Debarment and suspension. You must comply with requirements regarding debarment and suspension in Subpart C of 2 CFR parts 180 and 901.

2 Drug-free workplace. You must comply with drug-free workplace requirements in Subpart B of 10 CFR part 607, which implements sec. 5151-5160 of the Drug-Free Workplace Act of 1988 (Pub. L. 100-690, Title V, Subtitle D; 41 U.S.C. 701, et seq.).

3 Lobbying.

a. You must comply with the restrictions on lobbying in 31 U.S.C. l352, as implemented by DOE at 10 CFR part 601, and submit all disclosures required by that statute and regulation.

b. If you are a nonprofit organization described in section 501 (c)(4) of title 26, United States Code (the Internal Revenue Code of 1968), you may not engage in lobbying activities as defined in the Lobbying Disclosure Act of 1995 (2 U.S.C., Chapter 26). If we determine that you have engaged in lobbying activities, we will cease all payments to you under this and other awards and terminate the awards unilaterally for material failure to comply with the award terms and conditions. By submitting an application and accepting funds under this agreement, you assure that you are not an organization described in section 501 (c)(4) that has engaged in any lobbying activities described in the Lobbying Disclosure Act of 1995 (2 U.S.C. 1611).

c. You must comply with the prohibition in 18 U.S.C. 1913 on the use of Federal funds, absent express Congressional authorization, to pay directly or indirectly for any service, advertisement or other written matter, telephone communication, or other device intended to influence at any time a Member of Congress or official of any government concerning any legislation, law, policy, appropriation, or ratification.

4. Officials not to benefit. You must comply with the requirement that no member of Congress shall be admitted to any share or part of this agreement, or to any benefit arising from it, in accordance with 41 U.S.C. 22.

5 Hatch Act. If applicable, you must comply with the provisions of the Hatch Act (5 U.S.C. 1501-1508 and 7324-7326), as implemented by the Office of Personnel Management at 5 CFR part 151, which limits political activity of employees or officers of State or local governments whose employment is connected to an activity financed in whole or part with Federal funds.

6 Native American graves protection and repatriation. If you control or possess Native American remains and associated funerary objects, you must comply with the requirements of 43 CFR part 10, the Department of the Interior implementation of the Native

American Graves Protection and Repatriation Act of 1990 (25 U.S.C., chapter 32).

7 Fly America Act. You must comply with the International Air Transportation Fair Competitive Practices Act of 1974 (49 U.S.C. 40118), commonly referred to as the "Fly America Act," and implementing regulations at 41 CFR 301-10.131 through 301-10.143. The law and regulations require air transport of people or property to, from, between or within a country other than the United States, the cost of which is supported under this award, to be performed by or under a cost-sharing arrangement with a U.S. flag carrier, if service is available.

8. Use of United States-flag vessels.

a. Pursuant to Pub. L. 664 (43 U.S.C. 1241 (b)), at least 50 percent of any equipment, materials or commodities procured, contracted for or otherwise obtained with funds under this award, and which may be transported by ocean vessel, must be transported on privately owned United States-flag commercial vessels, if available.

b. Within 20 days following the date of loading for shipments originating within the United States or within 30 working days following the date of loading for shipments originating outside the United States, a legible copy of a rated, "on-board" commercial ocean bill-of-lading in English for each shipment of cargo described in paragraph 9.a of this section shall be furnished to both our award administrator (through you in the case of your contractor's bill-of-lading) and to the Division of National Cargo, Office of Market Development, Maritime Administration, Washington, DC 20590.

9 Research misconduct. You must comply with the government-wide policy on research misconduct issued by the Office of Science and Technology Policy (available in the Federal Register at 65 FR 76260, December 6, 2000, or on the Internet at www.ostp.gov), as implemented by DOE at 10 CFR part 733 and 10 CFR 600.31.

10 Requirements for an Institution of Higher Education Concerning Military recruiters and Reserve Officers Training Corps (ROTC).

a. As a condition for receiving funds under an award by the National Nuclear Security Administration of the Department of Energy, you agree that you are not an institution of higher education that has a policy or practice placing any of the restrictions specified in 10 U.S.C. 983. as implemented by 32 CFR part 216, on:

i. Maintenance, establishment, or operation of Senior ROTC units, or student participation in those units; or

ii. Military recruiters' access to campuses, students on campuses, or information about students.

b. If you are determined, using the procedures in 32 CFR part 216, to be such an institution of higher education during the period of performance of this award, we:

i. Will cease all payments to you of funds under this award and all other awards subject to the requirements in 32 CFR part 216; and

ii. May suspend or terminate those awards unilaterally for material failure to comply with the award terms and conditions.

11. Historic preservation. You must identify to us any:

a. Any property listed or eligible for listing on the National Register of Historic Places that will be affected by this award, and provide any help we may need, with respect to this award, to comply with Section 106 of the National Historic Preservation Act of 1966 (16 U.S.C. 470f), as implemented by the Advisory Council on Historic Preservation regulations at 36 CFR part 800 and Executive Order 11593, "Identification and Protection of Historic Properties," [3 CFR, 1971-1975 Comp., p. 559].

b. Potential under this award for irreparable loss or destruction of significant scientific, prehistorical, historical, or archeological data, and provide any help we may need, with respect to this award, to comply with the Archaeological and Historic Preservation Act of 1974 (16 U.S.C. 469a-l, et seq.).

12 Relocation and real property acquisition. You must comply with applicable provisions of 49 CFR part 24, which implements the Uniform Relocation Assistance and Real Property Acquisition Policies Act of 1970 (42 U.S.C. 4601, et seq.) and provides for fair and equitable treatment of persons displaced by federally assisted programs or persons whose property is acquired as a result of such programs.

13 Confidentiality of patient records. You must keep confidential any records that you maintain of the identity, diagnosis, prognosis, or treatment of any patient in connection with any program or activity relating to substance abuse education, prevention, training, treatment, or rehabilitation that is assisted directly or indirectly under this award, in accordance with 42 U.S.C. 290dd-2.

14 Constitution Day. You must comply with Public Law 108-447, Div. J, Title I, Sec. 111 (36 U.S.C. 106 note), which requires each educational institution receiving Federal funds in a Federal fiscal year to hold an educational program on the United States Constitution on September 17th during that year for the students served by the educational institution.

15 Trafficking in Persons

a. Provisions applicable to a recipient that is a private entity.

1. You as the recipient, your employees, subrecipients under this award, and subrecipients’ employees may not—

i. Engage in severe forms of trafficking in persons during the period of time that the award is in effect.

ii. Procure a commercial sex act during the period of time that the award is in effect; or

iii. Use forced labor in the performance of the award or subawards under the award.

2. We are the Federal awarding agency may unilaterally terminate this award, without penalty, if you or a subrecipient that is a private entity—

i. Is determined to have violated a prohibition in paragraph a.1 of this award term; or

ii. Has an employee who is determined by the agency official authorized to terminate the award to have violated a prohibition in paragraph a.1 of this award term through conduct that is either—

A. Associated with performance under this award; or

B. Imputed to you or the subrecipient using the standards and due process for imputing the conduct of an individual to an organization that are provided in 2 CFR part 180, "OMB Guidelines to Agencies on Govemmentwide Debarment and Suspension (Nonprocurement)," as implemented by our agency at 2 CFR part 901.

b. Provision applicable to a recipient other than a private entity. We as the Federal awarding agency may unilaterally terminate this award, without penalty, if a subrecipient that is a private entity-

1. Is determined to have violated an applicable prohibition in paragraph a.1 of this award term; or

2. Has an employee who is determined by the agency official authorized to terminate the award to have violated an applicable prohibition in paragraph a.1 of this award term through conduct that is either—

i. Associated with performance under this award; or

ii. Imputed to the subrecipient using the standards and due process for imputing the conduct of an individual to an organization that are provided in 2 CFR part 180, "OMB Guidelines to Agencies on Govemmentwide Debarment and Suspension (Nonprocurement)," as implemented by our agency at 2 CFR part 901.

c. Provisions applicable to any recipient.

1. You must inform us immediately of any information you receive from any source alleging a violation of a prohibition in paragraph a.1 of this award term.

2. Our right to terminate unilaterally that is described in paragraph a.2 or b. of this section:

i. Implements section 106(g) of the Trafficking Victims Protection Act of 2000 (TVPA), as amended (22 U.S.C. 7I04(g)), and

ii. Is in addition to all other remedies for noncompliance that are available to us under this award.

3.You must include the requirements of paragraph a.1 of this award term in any subaward you make to a private entity,

d. Definitions. For purposes of this award term:

1. "Employee" means either:

i. An individual employed by you or a subrecipient who is engaged in the performance of the project or program under this award; or

ii. Another person engaged in the performance of the project or program under this award and not compensated by you including, but not limited to, a volunteer or individual whose services are contributed by a third party as an in-kind contribution toward cost sharing or matching requirements.

2. "Forced labor" means labor obtained by any of the following methods: the recruitment, harboring, transportation, provision, or obtaining of a person for labor or services, through the use of force, fraud, or coercion for the purpose of subjection to involuntary servitude, peonage, debt bondage, or slavery.

3. "Private entity":

i. Means any entity other than a State, local government, Indian tribe, or foreign public entity, as those terms are defined in 2 CFR 175.25.

ii. Includes:

A. A nonprofit organization, including any nonprofit institution of higher education, hospital, or tribal organization other than one included in the definition of Indian tribe at 2 CFR 175.25(b).

B. A for-profit organization.

4. "Severe forms of trafficking in persons," "commercial sex act," and "coercion" have the meanings given at section 103 of the TVPA, as amended (22 U.S.C. 7102).

V. National Policy Requirements for Subawards.

Recipient responsibility. You must include in any subaward you make under this award the requirements of the national policy requirements in Sections I through IV of this document that apply, based on the type of subawardee organization and situation.

Attachment E

Statement of Project Objectives (SOPO):

NV Energy, Inc. Smart Grid Advanced Service Delivery (ASD) Project

A. Project Objectives

The objective of this project is to support the goal of the Smart Grid Investment Grant Funding Opportunity Announcement which is to accelerate the modernization of the nation's electric transmission, distribution, and delivery systems, and promote investments in smart grid technologies which increase flexibility, functionality, interoperability, cyber security, situational awareness and operational efficiency. An additional goal is to collect information from customers, distributors, and generators to understand how smart grid technologies may lead to reductions in demands and costs, increases energy efficiency, optimally allocates and matches demand and resources to meet that demand, and increases the reliability of the grid. The social benefits of a smart grid and energy storage technologies are reduced emissions, lower costs, increase d reliability, greater security and flexibility to accommodate new energy technologies, including renewable, intermittent and distributed sources.

B. Project Scope (Scope of Work)

The Scope of Work is in accordance with the Recipient's application submitted in response to the Smart Grid Investment Grant Program Funding Opportunity Announcement.

C. Tasks to be Performed

Tasks to be performed under this agreement are comprised of the actions and activities described in the Recipients proposal and the deliverables and reports defined elsewhere in the agreement.

EX-12.1 3 exhibit12-1.htm EXHIBIT 12.1 exhibit12-1.htm

EXHIBIT 12.1

NV ENERGY, INC.

RATIOS OF EARNINGS TO FIXED CHARGES

(Dollars in Thousands)

	Three Months Ended March 31,						Year Ended December 31,
	2010			2009			2009			2008			2007			2006			2005

EARNINGS AS DEFINED:

Net Income (Loss)	$	(1,721	)	$	(22,244	)	$	182,936		$	208,887		$	197,295		$	279,792		$	86,137
Income taxes (benefit)		1,256			(11,414	)		75,451			95,354			87,555			145,605			43,118
Fixed Charges		87,509			90,043			360,896			335,868			310,876			336,024			319,654
Capitalized Interest (allowance for borrowed funds used during construction)		(4,939	)		(5,146	)		(20,229	)		(29,527	)		(25,967	)		(17,119	)		(24,691	)
Preferred Stock Dividend Requirement		-			-			-			-			-			(3,602	)		(6,000	)
Total	$	82,105		$	51,239		$	599,054		$	610,582		$	569,759		$	740,700		$	418,218

FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)	$	87,509		$	90,043		$	360,896		$	335,868		$	310,876		$	332,422		$	313,654
Preferred Stock Dividend Requirement		-			-			-			-			-			3,602			6,000

Total	$	87,509		$	90,043		$	360,896		$	335,868		$	310,876		$	336,024		$	319,654

RATIO OF EARNINGS TO FIXED CHARGES								1.66			1.82			1.83			2.20			1.31

DEFICIENCY	$	5,404		$	38,804

(1)	Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income or (loss) adjusted for income taxes (benefits) and fixed charges excluding capitalized interest. For the years ended December 31, 2006 and 2005, “Earnings” represents net income or (loss) adjusted for pre-tax preferred stock dividend requirement of SPPC income taxes and fixed charges excluding capitalized interest. “Fixed charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized), the portion of rental expense deemed to be attributable to interest, and the pre-tax preferred stock dividend requirement of SPPC.

EX-12.2 4 exhibit12-2.htm EXHIBIT 12.2 exhibit12-2.htm

EXHIBIT 12.2

NEVADA POWER COMPANY

RATIOS OF EARNINGS TO FIXED CHARGES

(Dollars in Thousands)

	Three Months Ended March 31,						Year Ended December 31,
	2010			2009			2009			2008			2007			2006			2005

EARNINGS AS DEFINED:

Net Income (Loss)	$	(12,326	)	$	(35,151	)	$	134,284		$	151,431		$	165,694		$	224,540		$	132,734
Income taxes (benefit)		(4,119	)		(16,365	)		61,652			71,382			78,352			117,510			63,995
Fixed Charges		59,146			60,629			247,290			210,067			190,836			190,333			159,776
Capitalized Interest (allowance for borrowed funds used during construction)		(4,532	)		(4,562	)		(17,184	)		(20,063	)		(13,196	)		(11,614	)		(23,187	)

Total	$	38,169		$	4,551		$	426,042		$	412,817		$	421,686		$	520,769		$	333,318

FIXED CHARGES AS DEFINED:
Interest Expensed and Capitalized (1)	$	59,146		$	60,629		$	247,290		$	210,067		$	190,836		$	190,333		$	159,776
Preference Security Dividend Requirements
Total	$	59,146		$	60,629		$	247,290		$	210,067		$	190,836		$	190,333		$	159,776

RATIO OF EARNINGS TO FIXED CHARGES								1.72			1.97			2.21			2.74			2.09

DEFICIENCY	$	20,977		$	56,078

(1)	Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represents net income (or loss) adjusted for income taxes (benefits) and fixed charges excluding capitalized interest. “Fixed charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

EX-12.3 5 exhibit12-3.htm EXHIBIT 12.3 exhibit12-3.htm

EXHIBIT 12.3

SIERRA PACIFIC POWER COMPANY

RATIOS OF EARNINGS TO FIXED CHARGES

(Dollars in Thousands)

	Three Months Ended March 31,						Year ended December 31,
	2010			2009			2009			2008			2007			2006			2005

EARNINGS AS DEFINED:

Net Income	$	17,120		$	19,136		$	73,085		$	90,582		$	65,667		$	57,709		$	52,074
Income Taxes		7,676			9,286			31,225			37,603			26,009			27,829			28,379
Fixed Charges		18,700			19,751			74,955			84,478			75,655			79,093			72,652
Capitalized Interest (allowance for borrowed funds used during construction)		(407	)		(584	)		(3,044	)		(9,464	)		(12,771	)		(5,505	)		(1,504	)

Total	$	43,089		$	47,589		$	176,221		$	203,199		$	154,560		$	159,126		$	151,601

FIXED CHARGES AS DEFINED:	$	18,700		$	19,751		$	74,955		$	84,478		$	75,655		$	79,093		$	72,652
Interest Expensed and Capitalized (1)		-			-			-			-			-			-			-
Total	$	18,700		$	19,751		$	74,955		$	84,478		$	75,655		$	79,093		$	72,652

RATIO OF EARNINGS TO FIXED CHARGES		2.30			2.41			2.35			2.41			2.04			2.01			2.09

(1)	Includes amortization of premiums, discounts, and capitalized debt expense and interest component of rent expense.

For the purpose of calculating the ratios of earnings to fixed charges, “Earnings” represent net income before, solely with respect to the years ended December 31, 2006, 2005 and 2004, pre-tax preferred stock dividend requirement adjusted for income taxes and fixed charges excluding capitalized interest. “Fixed charges” represent the aggregate of interest charges on long-term debt (whether expensed or capitalized) and the portion of rental expense deemed attributable to interest.

EX-31.1 6 exhibit31-1.htm EXHIBIT 31.1 exhibit31-1.htm

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of NV Energy, Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

EX-31.2 7 exhibit31-2.htm EXHIBIT 31.2 exhibit31-2.htm

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Nevada Power Company (dba NV Energy);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.3 8 exhibit31-3.htm EXHIBIT 31.3 exhibit31-3.htm

EXHIBIT 31.3

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, Michael W. Yackira, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Sierra Pacific Power Company (dba NV Energy);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ Michael W. Yackira

Michael W. Yackira

Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

EX-31.4 9 exhibit31-4.htm EXHIBIT 31.4 exhibit31-4.htm

EXHIBIT 31.4

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

I, E. Kevin Bethel, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of NV Energy, Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

EX-31.5 10 exhibit31-5.htm EXHIBIT 31.5 exhibit31-5.htm

EXHIBIT 31.5

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, E. Kevin Bethel, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Nevada Power Company (dba NV Energy);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

EX-31.6 11 exhibit31-6.htm EXHIBIT 31.6 exhibit31-6.htm

EXHIBIT 31.6

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER REQUIRED BY

SECTION 302(A) OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

I, E. Kevin Bethel, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Sierra Pacific Power Company (dba NV Energy);

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

May 6, 2010

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

EX-32.1 12 exhibit32-1.htm EXHIBIT 32.1 exhibit32-1.htm

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

NV Energy, Inc.

(Principal Executive Officer)

May 6, 2010

This Certification accompanies this Report pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 and shall not, except to the extent required by the Sarbanes-Oxley Act of 2002, be deemed filed by the registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. Such certification will not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except to the extent the registrant specifically incorporates it by reference.

A signed original of this written statement required by Section 906 has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2 13 exhibit32-2.htm EXHIBIT 32.2 exhibit32-2.htm

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, President and Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

President and Chief Executive Officer

Nevada Power Company (dba NV Energy)

(Principal Executive Officer)

May 6, 2010

EX-32.3 14 exhibi32-3.htm EXHIBIT 32.3 exhibi32-3.htm

EXHIBIT 32.3

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, Michael W. Yackira, Chief Executive Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ Michael W. Yackira

Michael W. Yackira

Chief Executive Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Executive Officer)

May 6, 2010

EX-32.4 15 exhibit32-4.htm EXHIBIT 32.4 exhibit32-4.htm

EXHIBIT 32.4

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NV ENERGY, INC.

(“Registrant”)

In connection with this report of NV Energy, Inc. on Form 10-K, as amended by Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, Interim Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

NV Energy, Inc.

(Principal Financial Officer)

May 6, 2010

EX-32.5 16 exhibit32-5.htm EXHIBIT 32.5 exhibit32-5.htm

EXHIBIT 32.5

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

NEVADA POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Nevada Power Company (dba NV Energy) on Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, Interim Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

Nevada Power Company (dba NV Energy)

(Principal Financial Officer)

May 6, 2010

EX-32.6 17 exhibit32-6.htm EXHIBIT 32.6 exhibit32-6.htm

EXHIBIT 32.6

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

SIERRA PACIFIC POWER COMPANY (dba NV ENERGY)

(“Registrant”)

In connection with this report of Sierra Pacific Power Company (dba NV Energy) on Form 10-Q for the quarter ended March 31, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, E. Kevin Bethel, Interim Chief Financial Officer of registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

1.	This report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.	The information contained in this report fairly presents, in all material respects, the financial condition and results of operations of the registrant.

/s/ E. Kevin Bethel

E. Kevin Bethel

Interim Chief Financial Officer

Sierra Pacific Power Company (dba NV Energy)

(Principal Financial Officer)

May 6, 2010

-----END PRIVACY-ENHANCED MESSAGE-----

	Registrant, Address of	I.R.S. Employer
	Principal Executive Offices	Identification	State of
Commission File Number	and Telephone Number	Number	Incorporation

1-08788	NV ENERGY, INC.	88-0198358	Nevada
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

2-28348	NEVADA POWER COMPANY d/b/a	88-0420104	Nevada
	NV ENERGY
	6226 West Sahara Avenue
	Las Vegas, Nevada 89146
	(702) 402-5000

0-00508	SIERRA PACIFIC POWER COMPANY d/b/a	88-0044418	Nevada
	NV ENERGY
	P.O. Box 10100
	(6100 Neil Road)
	Reno, Nevada 89520-0400 (89511)
	(775) 834-4011

NV Energy, Inc.:	Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
Nevada Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
Sierra Pacific Power Company:	Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o

Class		Outstanding at April 30, 2010
Common Stock, $1.00 par value of NV Energy, Inc.		234,939,325 Shares

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)


	Three Months Ended
	March 31,
	2010			2009

OPERATING REVENUES	$	716,969		$	755,267

OPERATING EXPENSES:
Fuel for power generation		221,619			230,104
Purchased power		107,363			125,387
Gas purchased for resale		65,559			70,272
Deferred energy		17,566			45,635
Other operating expenses		109,106			114,677
Maintenance		25,729			34,400
Depreciation and amortization		80,948			78,048
Taxes other than income		16,173			14,647
Total Operating Expenses		644,063			713,170
OPERATING INCOME		72,906			42,097

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: 2010-$4,939, 2009-$5,146)		(80,064	)		(82,633	)
Interest income (expense) on regulatory items		(2,071	)		1,180
AFUDC-equity		5,953			6,218
Other income		5,877			5,058
Other expense		(3,066	)		(5,578	)
Total Other Income (Expense)		(73,371	)		(75,755	)
Loss Before Income Tax Expense		(465	)		(33,658	)

Income tax expense (benefit)		1,256			(11,414	)

NET LOSS	$	(1,721	)	$	(22,244	)

Amount per share basic and diluted - (Note 9)
Net loss per share basic and diluted	$	(0.01	)	$	(0.09	)

Weighted Average Shares of Common Stock Outstanding - basic and diluted		234,858,642			234,331,044
Dividends Declared Per Share of Common Stock	$	0.11		$	0.10

The accompanying notes are an integral part of the financial statements.

NV ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)
(Unaudited)


	March 31,		December 31,
	2010		2009
ASSETS

Current Assets:
Cash and cash equivalents	$	75,928	$	62,706
Accounts receivable less allowance for uncollectible accounts: 2010 - $30,755; 2009 - $32,341		338,111		400,911
Materials, supplies and fuel, at average cost		121,321		124,040
Risk management assets (Note 6)		10,687		27,558
Deferred income taxes		131,382		87,562
Other current assets		60,410		44,298
Total Current Assets		737,839		747,075

Utility Property:
Plant in service		10,900,591		10,833,622
Construction work-in-progress		807,177		716,128
Total		11,707,768		11,549,750
Less accumulated provision for depreciation		2,943,702		2,884,199
Total Utility Property, Net		8,764,066		8,665,551

Investments and other property, net		52,279		51,169

Deferred Charges and Other Assets:
Deferred energy (Note 3)		129,323		138,963
Regulatory assets		1,272,333		1,218,778
Regulatory asset for pension plans		261,100		264,892
Risk management assets (Note 6)		4,350		6,732
Other deferred charges and assets		173,096		173,145
Total Deferred Charges and Other Assets		1,840,202		1,802,510

Assets Held for Sale (Note 10)		149,139		147,158

TOTAL ASSETS	$	11,543,525	$	11,413,463



(Continued)

PART I – FINANCIAL INFORMATION
Acronyms & Terms			3

ITEM 1.	Financial Statements

	NV Energy, Inc.
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	4
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	5
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	7
	Nevada Power Company
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	8
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	9
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	11
	Sierra Pacific Power Company
		Consolidated Income Statements – Three Months Ended March 31, 2010 and 2009	12
		Consolidated Balance Sheet – March 31, 2010 and December 31, 2009	13
		Consolidated Statements of Cash Flows – Three Months Ended March 31, 2010 and 2009	15
	Condensed Notes to Financial Statements
		Note 1. Summary of Significant Accounting policies	16
		Note 2. Segment Information	17
		Note 3. Regulatory Actions	18
		Note 4. Long-Term Debt	19
		Note 5. Fair Value of Financial Instruments	20
		Note 6. Derivatives and Hedging Activities	20
		Note 7. Retirement Plan and Post-Retirement Benefits	23
		Note 8. Commitments and Contingencies	24
		Note 9. Earnings Per Share (NVE)	26
		Note 10. Assets Held for Sale	26
		Note 11. Subsequent Events	27

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		28

	NV Energy, Inc.		34
	Nevada Power Company		38
	Sierra Pacific Power Company		45

ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk		54

ITEM 4 and 4T.	Controls and Procedures		55

PART II – OTHER INFORMATION

ITEM 1.	Legal Proceedings		55
ITEM 1A.	Risk Factors		56
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		56
ITEM 3.	Defaults Upon Senior Securities		56
ITEM 5.	Other Information		56
ITEM 6.	Exhibits		57

Signature Page and Certifications			58

ACRONYMS AND TERMS
(The following common acronyms and terms are found in multiple locations within the document)

Acronym/Term		Meaning

2009 Form 10-K		NVE’s, NPC’s and SPPC’s Annual Report on Form 10-K, as amended by a Form 10-K/A, for the year ended December 31, 2009
AFUDC-debt		Allowance for Borrowed Funds Used During Construction
AFUDC-equity		Allowance for Equity Funds Used During Construction
ASD		Advanced Service Delivery
BCP		Bureau of Consumer Protection
BOD		Board of Directors
BTGR		Base Tariff General Rate
CalPeco		California Pacific Electric Company
Calpine		Calpine Corporation
Clark Generating Station		550 megawatt nominally rated William Clark Generating Station
CPUC		California Public Utilities Commission
CWIP		Construction Work-In-Progress
d/b/a		Doing business as
DBRS		Dominion Bond Rating Service
DEAA		Deferred Energy Accounting Adjustment
DOE		Department of Energy
DSM		Demand Side Management
Dth		Decatherm
EPA		Environmental Protection Agency
EPS		Earnings Per Share
FASB		Financial Accounting Standards Board
FASC		FASB Accounting Standards Codification
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings, Ltd.
GAAP		Generally Accepted Accounting Principles in the United States
GRC		General Rate Case
Harry Allen Generating Station		142 megawatt nominally rated Harry Allen Generating Station
Higgins Generating Station		598 megawatt nominally rated Walter M. Higgins, III Generating Station
IRP		Integrated Resource Plan
kV		Kilovolt
MMBtu		Million British Thermal Units
Mohave Generating Station		1,580 megawatt nominally rated Mohave Generating Station
Moody’s		Moody’s Investors Services, Inc.
MW		Megawatt
MWh		Megawatt hour
Navajo Generating Station		255 megawatt nominally rated Navajo Generating Station
NEICO		Nevada Electrical Investment Company
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NPC		Nevada Power Company d/b/a NV Energy
NPC Credit Agreement		$600 million Revolving Credit Facility entered into in April 2010 between NPC and Wells Fargo, N.A., as administrative agent for the lenders a party thereto
NPC’s Indenture		NPC’s General and Refunding Mortgage Indenture dated as of May 1, 2001, between NPC and the Bank of New York Mellon Trust Company N.A., as Trustee
NVE		NV Energy, Inc.
ON Line		250 mile 500 kV transmission line connecting NVE’s northern and southern service territories
PEC		Portfolio Energy Credit
Portfolio Standard		Renewable Energy Portfolio Standard
PUCN		Public Utilities Commission of Nevada
Reid Gardner Generating Station		325 megawatt nominally rated Reid Gardner Generating Station
ROR		Rate of Return
S&P		Standard & Poor’s
Salt River		Salt River Project
SEC		United States Securities and Exchange Commission
Silverhawk Generating Station		395 megawatt nominally rated Silverhawk Generating Station
SPPC		Sierra Pacific Power Company d/b/a NV Energy
SPPC Credit Agreement		$250 million Revolving Credit Facility entered into in April 2010 between SPPC and Bank of America, N.A., as administrative agent for the lenders a party thereto
SPPC’s Indenture		SPPC’s General and Refunding Mortgage Indenture, dated as of May 1, 2001, between SPPC and the Bank of New York Mellon Trust Company N.A., as Trustee
TMWA		Truckee Meadows Water Authority
Tracy Generating Station		541 megawatt nominally rated Frank A. Tracy Generating Station
U.S.		United States of America
Utilities		Nevada Power Company and Sierra Pacific Power Company
Valmy Generating Station		261 megawatt nominally rated Valmy Generating Station
WSPP		Western Systems Power Pool

NV ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

	For the Three Months Ended
	March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss	$	(1,721	)	$	(22,244	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		80,948			78,048
Deferred taxes and deferred investment tax credit		1,284			5,264
AFUDC-equity		(5,953	)		(6,218	)
Deferred energy		26,824			45,803
Other, net		21,206			16,836
Changes in certain assets and liabilities:
Accounts receivable		62,921			23,909
Materials, supplies and fuel		2,599			1,080
Other current assets		(16,113	)		(2,899	)
Accounts payable		(16,406	)		(41,216	)
Accrued retirement benefits		(4,767	)		(12,205	)
Other current liabilities		(19,100	)		(24,400	)
Risk management assets and liabilities		2,633			267
Other deferred assets		(921	)		(3,988	)
Other regulatory assets		(9,462	)		(11,251	)
Other deferred liabilities		(4,058	)		4,493
Net Cash from Operating Activities		119,914			51,279

CASH FLOWS USED BY INVESTING ACTIVITIES:
Additions to utility plant (excluding AFUDC-equity)		(200,046	)		(197,498	)
Proceeds from sale of asset		3,254			-
Customer advances for construction		(794	)		(3,260	)
Contributions in aid of construction		15,707			17,104
Investments and other property - net		(1,093	)		9
Net Cash used by Investing Activities		(182,972	)		(183,645	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		144,999			909,020
Retirement of long-term debt		(44,011	)		(695,100	)
Sale of Common Stock		1,124			818
Dividends paid		(25,832	)		(23,450	)
Net Cash from Financing Activities		76,280			191,288

Net Increase in Cash and Cash Equivalents		13,222			58,922
Beginning Balance in Cash and Cash Equivalents		62,706			54,359
Ending Balance in Cash and Cash Equivalents	$	75,928		$	113,281

Supplemental Disclosures of Cash Flow Information:
Cash paid during period for:
Interest	$	99,559		$	92,750
Significant non-cash transactions:
Accrued construction expenses as of March 31,	$	97,357		$	146,036
Capital lease obligations incurred	$	15,336		$	-

The accompanying notes are an integral part of the financial statements.

SIERRA PACIFIC POWER COMPANY
CONSOLIDATED INCOME STATEMENTS
(Dollars in Thousands)
(Unaudited)
	Three Months Ended
	March 31,
	2010			2009
OPERATING REVENUES:
Electric	$	209,981		$	237,738
Gas		80,020			80,993
Total Operating Revenues		290,001			318,731

OPERATING EXPENSES:
Fuel for power generation		65,504			76,042
Purchased power		36,136			37,181
Gas purchased for resale		65,559			70,272
Deferred energy - electric - net		(1,500	)		11,796
Deferred energy - gas - net		(397	)		(4,351	)
Other operating expenses		40,672			44,015
Maintenance		8,710			6,866
Depreciation and amortization		25,847			25,685
Taxes other than income		6,066			5,524
Total Operating Expenses		246,597			273,030
OPERATING INCOME		43,404			45,701

OTHER INCOME (EXPENSE):
Interest expense (net of AFUDC-debt: 2010-$407, 2009-$584)		(17,045	)		(17,927	)
Interest income (expense) on regulatory items		(2,040	)		(673	)
AFUDC-equity		591			597
Other income		1,755			2,715
Other expense		(1,869	)		(1,991	)
Total Other Income (Expense)		(18,608	)		(17,279	)
Income Before Income Tax Expense		24,796			28,422

Income tax expense		7,676			9,286

NET INCOME	$	17,120		$	19,136

The accompanying notes are an integral part of the financial statements.

	March 31, 2010
Description	NPC Electric			SPPC Electric			SPPC Gas			NVE Total

Nevada Deferred Energy
Cumulative Balance requested in 2010 DEAA	$	(98,726	)	$	(100,485	)	$	(16,996	)	$	(216,207	)
2010 Amortization		-			5,235			3,491			8,726
2010 Deferred Energy Over Collections (1)		(16,721	)		(7,069	)		(3,371	)		(27,161	)
Nevada Deferred Energy Balance at March 31, 2010 - Subtotal	$	(115,447	)	$	(102,319	)	$	(16,876	)	$	(234,642	)
Cumulative CPUC balance		-			632			-			632
Western Energy Crisis Rate Case (effective 6/07, 3 years)		11,204			-			-			11,204
Reinstatement of deferred energy (effective 6/07, 10 years)		144,383			-			-			144,383

Total	$	40,140		$	(101,687	)	$	(16,876	)	$	(78,423	)

Current Assets
Other deferred charges (2)		-			632			-			632
Deferred Assets
Deferred energy		129,323			-			-			129,323
Current Liabilities
Deferred energy		(89,183	)		(102,319	)		(16,876	)		(208,378	)
Total	$	40,140		$	(101,687	)	$	(16,876	)	$	(78,423	)

(1)	These deferred energy over collections are to be requested in March 2011 DEAA filings, and include PUCN ordered adjustments.
(2)	Refer to Note 10, Assets Held For Sale.

	NPC			SPPC		NVE Holding Co. and Other Subs.		NVE Consolidated
2010	$	3,069		$	-	$	-	$	3,069
2011		368,454			-		-		368,454
2012		134,822			100,000		63,670		298,492
2013		235,405			250,000		-		485,405
2014		128,513			-		230,039		358,552
		870,263			350,000		293,709		1,513,972
Thereafter		2,928,355			916,417		191,500		4,036,272
		3,798,618			1,266,417		485,209		5,550,244
Unamortized Premium (Discount) Amount		(11,713	)		15,446		434		4,167
Total	$	3,786,905		$	1,281,863	$	485,643	$	5,554,411