The Utilities are subject to the jurisdiction of the PUCN and in the case of SPPC in prior years, 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 distribution and transmission operations. However, on January 1, 2011, SPPC sold its California Assets, as discussed further in Note 15, Assets Held for Sale, and therefore is no longer subject to the jurisdiction of the CPUC. 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.

As a result of regulation, the Utilities are required to file annual electric and gas DEAA, EEIR and EEPR cases by March 1, and triennial GRCs. In addition, the Utilities may also file quarterly DEAA and BTER updates for the Utilities' electric and gas departments. Reference Note 1, Summary of Significant Accounting Policies for further discussion of the various rate components. Detailed below are Deferred Energy Costs which relate to the DEAA and BTER filings and further below are other regulatory assets and liabilities which primarily relate to the GRCs. Additionally, significant pending or settled rate cases are discussed below.

The following deferred energy amounts were included in the consolidated balance sheets as of December 31 for the years shown below (dollars in thousands):

				2012
			NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance authorized in 2012 DEAA		$	(262,845)	$	(177,336)	$	(56,422)	$	(29,087)
	2012 Amortization			293,185		185,339		78,601		29,245
	2012 Deferred Energy Over Collections⁽¹⁾			(182,221)		(109,121)		(54,872)		(18,228)
Deferred Energy Balance at December 31, 2012 - Subtotal			$	(151,881)	$	(101,118)	$	(32,693)	$	(18,070)
Reinstatement of deferred energy (effective 6/07, 10 years)				102,088		102,088		-		-
		Total Deferred Energy	$	(49,793)	$	970	$	(32,693)	$	(18,070)

Deferred Assets
	Deferred energy		$	87,072	$	87,072	$	-	$	-
Current Liabilities
	Deferred energy			(136,865)		(86,102)		(32,693)		(18,070)
		Total Net Deferred Energy	$	(49,793)	$	970	$	(32,693)	$	(18,070)


⁽¹⁾		These deferred energy over collections are subject to quarterly rate resets as discussed in Note 1, Summary of Significant Accounting Policies, Deferred Energy Accounting.

			2011
			NVE Total		NPC Electric		SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance authorized in 2011 DEAA		$	(334,102)	$	(189,032)	$	(115,955)	$	(29,115)
	2011 Amortization			247,489		120,340		104,909		22,240
	2011 Deferred Energy Over Collections⁽¹⁾			(173,466)		(106,022)		(45,291)		(22,153)
Deferred Energy Balance at December 31, 2011 - Subtotal			$	(260,079)	$	(174,714)	$	(56,337)	$	(29,028)
Reinstatement of deferred energy (effective 6/07, 10 years)				117,440		117,440		-		-
	Total Deferred Energy		$	(142,639)	$	(57,274)	$	(56,337)	$	(29,028)

Deferred Assets
	Deferred energy		$	102,525	$	102,525	$	-	$	-
Current Liabilities
	Deferred energy			(245,164)		(159,799)		(56,337)		(29,028)
		Total Net Deferred Energy	$	(142,639)	$	(57,274)	$	(56,337)	$	(29,028)

⁽¹⁾		Refer to "Settled Regulatory Actions" below for separate discussions regarding NPC and SPPC's 2012 DEAA rate filings.

As discussed in Note 1, Summary of Significant Accounting Policies, regulatory assets represent incurred costs that have been deferred because it is probable they will be recovered through future rates collected from customers. If at any time the incurred costs no longer meet these criteria, these costs are charged to earnings. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections, except for cost of removal which represents the cost of removing future electric and gas assets. Management regularly assesses whether the regulatory assets are probable of future recovery by considering actions of regulators, current laws related to regulation, applicable regulatory environment changes and the status of any current, pending or potential legislation. Detailed below are Other Regulatory Assets and Liabilities included in the balance sheet of NVE, NPC and SPPC and their current regulatory treatment as of December 31 (dollars in thousands):

		NVE
		OTHER REGULATORY ASSETS AND LIABILITIES

		As of December 31, 2012
		Remaining	Receiving Regulatory Recovery					Pending					As of
DESCRIPTION		Amortization	Earning a			Not Earning		Regulatory			2012		December 31, 2011
		Period	Return		(1)	a Return		Review			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	66,911		$	-	$	-		$	66,911	$	72,408
	Income taxes	Various		-			269,693		-			269,693		283,315
	Merger costs	Various thru 2046		-			257,185		-			257,185		268,668
	Lenzie Generating Station	2042		-			65,139		-			65,139		67,351
	Mohave Generating Station and deferred costs	2017		6,931			10,545		4,230			21,706		24,160
	Piñon Pine	Various thru 2029		25,805			3,837		-	⁽²⁾		29,642		34,393
	Asset retirement obligations			-			-		66,559			66,559		67,891
	Conservation programs	Various thru 2017		110,246			-		12,310	⁽²⁾		122,556		158,447
	EEPR	Various thru 2014		4,744			-		-	⁽³⁾		4,744		30,379
	EEIR	Various thru 2014		12,597			-		-			12,597		14,062
	Ely Energy Center	2017		-			19,503		34,359			53,862		57,966
	Legacy Meters			-			-		64,112	⁽²⁾		64,112		21,777
	Renewable energy programs	Various thru 2014		23,703			-		-	⁽²⁾		23,703		29,592
	Peabody coal costs			-			18,305		-			18,305		17,899
	Deferred Rate Increase	2013		8,550			-		-			8,550		12,177
	Other costs	Various thru 2031		21,451			17,745		8,308			47,504		57,643
	Subtotal		$	280,938		$	661,952	$	189,878	^{(2, 3)}	$	1,132,768	$	1,218,128
	Pensions			281,195			-		-			281,195		215,656
Total regulatory assets			$	562,133		$	661,952	$	189,878		$	1,413,963	$	1,433,784

Regulatory liabilities
	Cost of removal	Various	$	457,074		$	-	$	-		$	457,074	$	422,033
	Income taxes	Various		-			15,142		-			15,142		17,433
	Gain on property sales	2013		2,222			-		27,300			29,522		37,288
	EEPR	2014		34,727	(4)		-		-			34,727		-
	EEIR	2014		6,790	(4)		-		-			6,790		-
	Renewable energy programs	2014		460	(4)		-		-			460		1,046
	Other	Various thru 2043		5,400			-		1,572	⁽³⁾		6,972		8,459
Total regulatory liabilities			$	506,673		$	15,142	$	28,872		$	550,687	$	486,259

		NPC
		OTHER REGULATORY ASSETS AND LIABILITIES

		As of December 31, 2012
		Remaining	Receiving Regulatory Recovery					Pending					As of
DESCRIPTION		Amortization	Earning a			Not Earning		Regulatory			2012		December 31, 2011
		Period	Return		(1)	a Return		Review			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	37,821		$	-	$	-		$	37,821	$	39,958
	Income taxes	Various		-			169,211		-			169,211		178,060
	Merger costs	Various thru 2044		-			161,833		-			161,833		168,212
	Lenzie Generating Station	2042		-			65,139		-			65,139		67,351
	Mohave Generating Station and deferred costs	Various thru 2017		6,931			10,545		4,230	⁽²⁾		21,706		24,160
	Asset retirement obligations			-			-		58,368	⁽²⁾		58,368		60,797
	Conservation programs	Various thru 2017		99,671			-		7,511	⁽³⁾		107,182		133,889
	EEPR	Various thru 2014		4,174			-		-			4,174		25,250
	EEIR	Various thru 2014		9,302			-		-			9,302		12,342
	Ely Energy Center	2017		-			19,503		22,815	⁽²⁾		42,318		46,373
	Legacy Meters			-			-		61,420	⁽²⁾		61,420		21,777
	Renewable energy programs	Various thru 2014		9,495			-		-			9,495		10,694
	Peabody coal costs			-			18,305		-			18,305		17,899
	Deferred Rate Increase	2013		8,550			-		-			8,550		12,177
	Other costs	2017		9,578			14,319		5,292	^{(2, 3)}		29,189		34,050
	Subtotal		$	185,522		$	458,855	$	159,636		$	804,013	$	852,989
	Pensions			136,682			-		-			136,682		108,528
Total regulatory assets			$	322,204		$	458,855	$	159,636		$	940,695	$	961,517


Regulatory liabilities
	Cost of removal	Various	$	252,648		$	-	$	-		$	252,648	$	232,093
	Income taxes	Various		-			4,707		-			4,707		5,798
	Gain on property sales			-			-		27,300			27,300		32,844
	EEPR	2014		29,808	⁽⁴⁾		-		-			29,808		-
	EEIR	2014		6,790	⁽⁴⁾		-		-			6,790		-
	Other	Various thru 2018		639			-		1,508	⁽³⁾		2,147		4,216
Total regulatory liabilities			$	289,885		$	4,707	$	28,808		$	323,400	$	274,951

		SPPC
		OTHER REGULATORY ASSETS AND LIABILITIES

		As of December 31, 2012
		Remaining	Receiving Regulatory Recovery					Pending					As of
DESCRIPTION		Amortization	Earning a			Not Earning		Regulatory			2012		December 31, 2011
		Period	Return		(1)	a Return		Review			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	29,090		$	-	$	-		$	29,090	$	32,450
	Income taxes	Various		-			100,482		-			100,482		105,255
	Merger costs	Various thru 2046		-			95,352		-			95,352		100,456
	Piñon Pine	Various thru 2029		25,805			3,837		-			29,642		34,393
	Asset retirement obligations			-			-		8,191	⁽²⁾		8,191		7,094
	Conservation programs	Various thru 2013		10,575			-		4,799	⁽³⁾		15,374		24,558
	EEPR	Various thru 2014		570			-		-			570		5,129
	EEIR	Various thru 2014		3,295			-		-			3,295		1,720
	Renewable energy programs	Various thru 2014		14,208			-		-			14,208		18,898
	Ely Energy Center			-			-		11,544	⁽²⁾		11,544		11,593
	Legacy Meters			-			-		2,692	⁽²⁾		2,692		-
	Other costs	Various thru 2031		11,873			3,426		3,016	^{(2, 3)}		18,315		23,593
	Subtotal		$	95,416		$	203,097	$	30,242		$	328,755	$	365,139
	Pensions			140,268			-		-			140,268		104,159
Total regulatory assets			$	235,684		$	203,097	$	30,242		$	469,023	$	469,298


Regulatory liabilities
	Cost of removal	Various	$	204,426		$	-	$	-		$	204,426	$	189,940
	Income taxes	Various		-			10,435		-			10,435		11,635
	Gain on property sales	2013		2,222			-		-			2,222		4,444
	EEPR	2014		4,919	⁽⁴⁾		-		-			4,919		-
	Renewable energy programs	2014		460	⁽⁴⁾		-		-			460		-
	Other costs	Various thru 2043		4,761			-		64	⁽³⁾		4,825		5,289
Total regulatory liabilities			$	216,788		$	10,435	$	64		$	227,287	$	211,308

(1) Earning a return includes either a carrying charge on the asset/liability balance, or a return as a component of rate base.

(2) Pending regulatory treatment includes either amounts which have prior regulatory precedent or have been approved and are subject to prudency review.

(3) Assets which are allowed to earn a carrying charge until included in rates. Reference Note 1, Summary of Significant Accounting Policies, Equity Carrying Charges.

In March 2012, NPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011, to reset the TRED and REPR rate elements and to retire the unamortized balance of NPC's 2008 GRC deferred rate increase, as discussed below in NPC's 2010 DEAA. In September 2012, the PUCN issued its final order which resulted in an increase in revenue requirement, as disclosed in the table below, for the 2008 GRC deferred rate increase, REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.

Subsequent to filing NPC's DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in NPC's Annual Demand Side Management Update Report, requiring NPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow NPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, NPC filed an amended EEIR and EEPR rate request. In December 2012, the PUCN issued its final order which resulted in an overall decrease in revenue requirement in EEIR and EEPR, as disclosed in the table below.

The PUCN approvals of the 2012 DEAA, TRED, REPR, EEIR and EEPR filings include the following (dollars in millions):


					Authorized			Present			$ Change in
				Effective	Revenue			Revenue			Revenue
				Date	Requirement			Requirement		(3)	Requirement
Revenue Requirement Subject To Change:
		2008 GRC Deferred Rate Increase ⁽¹⁾		Oct. 2012	$	11.5		$	0.0		$	11.5
		REPR ⁽²⁾		Oct. 2012		37.4			8.5			28.9
		TRED ⁽²⁾		Oct. 2012		15.3			18.0			(2.7)
		EEPR Base ⁽²⁾		Jan. 2013		33.1			57.3			(24.2)
		EEPR Amortization ⁽²⁾		Jan. 2013		8.9			21.2			(12.3)
		EEIR Base		Jan. 2013		11.0			16.8			(5.8)
		EEIR Amortization		Jan. 2013		10.4	⁽¹⁾		4.8			5.6
			Total Revenue Requirement		$	127.6		$	126.6		$	1.0

	⁽¹⁾	This rate request represents revenues previously recorded as a result of NPC's 2008 GRC. As such, NPC will not record further
		revenue related to this rate component, but will collect such amounts from its customers. Refer to Regulatory Actions, NPC 2012
		DEAA, below for further discussion.
	⁽²⁾	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the
		revenues collected. As a result, such programs have no effect on Operating or Net Income.
	⁽³⁾	Represents present revenue requirement at the time of filing.

In June 2011, NPC filed its statutorily required triennial GRC and updated the filing in August 2011. The filing, as updated requested an ROE of 11.25% and ROR of 8.64% and an increase to general revenues of $249.9 million. The PUCN issued its order in December 2011, which resulted in the following significant items:

In March 2011, NPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR). In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $78.6 million. The PUCN authorized the refund and recovery of the following amounts (dollars in millions):


				Authorized			Present			$ Change in
			Effective	Revenue			Revenue			Revenue
			Date	Requirement			Requirement		(2)	Requirement
Revenue Requirement Subject To Change:
	DEAA		Oct. 2011	$	(188.9)		$	(101.0)		$	(87.9)
	REPR		Oct. 2011		8.6			29.8			(21.2)
	TRED		Oct. 2011		18.1			16.3			1.8
	EEPR Base		Oct. 2011		58.4			58.4			0.0
	EEPR Amortization		Oct. 2011		21.3			0.0			21.3
	EEIR Base		Oct. 2011		17.1			14.5			2.6
	EEIR Amortization		Oct. 2011		4.8	⁽¹⁾		0.0			4.8
		Total Revenue Requirement		$	(60.6)		$	18.0		$	(78.6)

⁽¹⁾	In accordance with Alternative Revenue Accounting, NPC recognized approximately $4.8 million in revenues pertaining to 2010.
	Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, NPC does not expect to record
	further revenue from this rate request; however, NPC does expect to collect approximately $4.8 million from its customers.
⁽²⁾	Represents present revenue requirement at the time of filing.

In March 2010, NPC filed an application to create a new DEAA rate. In its application, NPC requested to refund $102 million of deferred fuel and purchased power costs. Separately, NPC filed a petition to offset the NPC DEAA over collection (credit balance) of $102 million against the deferred BTGR debit balance of $95.8 million. The BTGR debit balance of $95.8 million was a result of NPC's 2008 GRC, which granted NPC approval to defer billings of its rate increase from July 1, 2009 to December 31, 2009 in a regulatory asset for which NPC recognized revenues in 2009. The PUCN consolidated both dockets for hearing purposes.

In September 2010, the PUCN accepted a stipulation for the DEAA and BTGR offset applications, which resulted in an overall revenue decrease of $9.2 million or 0.41% for the period October 1, 2010 through December 31, 2011.

NPC owns approximately 14% of the Mohave Generating Station. Southern California Edison is the operating partner of the Mohave Generating Station.

When operating, the Mohave Generating Station obtained all of its coal supply from a mine in northeast Arizona on lands of the Navajo Nation and the Hopi Tribe (the Tribes). This coal was delivered from the mine to the Mohave Generating Station by means of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the Tribes in the mine vicinity.

The Grand Canyon Trust and Sierra Club filed a lawsuit in the U.S. District Court, District of Nevada in February 1998 against the owners (including NPC) of the Mohave Generating Station, alleging violations of the Clean Air Act regarding emissions of sulfur dioxide and particulates. An additional plaintiff, National Parks and Conservation Association, later joined the suit. In 1999, the plant owners and plaintiffs filed a settlement with the court, which resulted in a consent decree, approved by the court in November 1999. The consent decree established emission limits for sulfur dioxide and opacity and required installation of air pollution controls for sulfur dioxide, nitrogen oxides, and particulate matter. Pursuant to the decree, the Mohave Generating Station Units 1 and 2 ceased operations as of January 2006 as the new emission limits were not met. Due to the lack of resolutions regarding continual availability of the coal and water supply with the Tribes, the Owners did not proceed with the consent decree.

In December 2005, the Owners of the Mohave Generating Station suspended operation, pending resolution of these issues. However, in June 2006, majority stake holder Southern California Edison announced it would no longer participate in the efforts to return the plant to service. As a result, NPC decided it is not economically feasible to continue its participation in the project. In September 2006, Salt River's co-tenancy agreement expired and the operating agreement between the Owners expired in July 2006. The Owners are discussing the negotiation of new agreements that would address the potential disposition of the assets and rights, title, interest and obligations in the Mohave Generating Station.

Included in other regulatory assets is approximately $6.9 million, which has been approved by the PUCN and included in rates. All other costs for Mohave Generating Station, including approximately $14.8 million of decommissioning costs were accumulated in other regulatory assets as incurred of which $10.5 million were approved by the PUCN, see the Other Regulatory Assets/Liabilities table above.

In June 2009, Southern California Edison announced that the Mohave Generating Station will be dismantled and its operating permits terminated following a December 2005 suspension of operations due to pending environmental matters. NPC believes it will continue to recover the costs for the Mohave Generating Station through the regulatory process and does not expect the dismantling of the plant to have a material impact on its financial condition.

In March 2012, SPPC filed an application for the PUCN to review fuel and purchased power transactions for the 12-month period ending December 31, 2011 and to reset the TRED and REPR rate elements. In September 2012, the PUCN issued its final order which resulted in an increase in revenue requirement, as outlined in the table below, for the REPR and TRED effective October 2012. Included in its September order are immaterial adjustments to deferred fuel and purchase power balances and a requirement to increase the REPR rate to include prospective customer incentives associated primarily with its solar rebate programs.

Subsequent to filing SPPC's DEAA, TRED, and REPR rate filings in March 2012, the PUCN issued a final order in SPPC's Annual Demand Side Management Update Report, requiring SPPC to revise all lighting-specific calculations used in the EEIR and EEPR rate applications. As a result, the parties agreed to bifurcate the EEIR and EEPR portions of the March filing to allow SPPC to amend the EEIR and EEPR rate requests using revised lighting-specific calculations and to hold a separate hearing on these components. In July 2012, SPPC filed an amended EEIR and EEPR rate request. In December 2012, the PUCN issued its final order which resulted in a decrease in revenue requirement for EEIR and EEPR, as outlined in the table below.

The PUCN approvals of the 2012 DEAA, TRED, REPR, EEIR and EEPR filings include the following (dollars in millions):


				Authorized		Present			$ Change in
			Effective	Revenue		Revenue			Revenue
			Date	Requirement		Requirement		(2)	Requirement
Revenue Requirement Subject To Change:
	REPR⁽¹⁾		Oct. 2012	$	43.3	$	38.5		$	4.8
	TRED⁽¹⁾		Oct. 2012		6.1		9.2			(3.1)
	EEPR Base⁽¹⁾		Jan. 2013		5.4		9.8			(4.4)
	EEPR Amortization⁽¹⁾		Jan. 2013		1.7		4.7			(3.0)
	EEIR Base		Jan. 2013		4.9		3.1			1.8
	EEIR Amortization		Jan. 2013		1.9		0.5			1.4
		Total Revenue Requirement		$	63.3	$	65.8		$	(2.5)

⁽¹⁾	Represents programs that require the Utilities to collect funds from customers for which the related costs are equal to the revenues
	collected. As a result, such programs have no effect on Operating or Net Income.
⁽²⁾	Represents present revenue requirement at the time of filing.

In March 2012, SPPC filed an application for the PUCN to review the physical gas, transportation and financial gas transactions that were recorded during the 12-month period ending December 31, 2011 and to reset the REPR. In September 2012, the PUCN issued its final order which resulted in an overall increase of $0.2 million that was effective October 1, 2012.

In March 2011, SPPC filed an application to establish a new DEAA to refund over-collected purchased power and fuel costs and reset or establish several other rate elements (TRED, REPR, EEIR and EEPR). In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of approximately $8.2 million. The PUCN authorized refund and recovery of the following amounts (dollars in millions):


				Authorized			Present			$ Change in
			Effective	Revenue			Revenue			Revenue
			Date	Requirement			Requirement		(2)	Requirement
Revenue Requirement Subject To Change:
	DEAA		Oct. 2011	$	(115.9)		$	(99.5)		$	(16.4)
	REPR		Oct. 2011		38.0			36.6			1.4
	TRED		Oct. 2011		9.1			7.9			1.2
	EEPR Base		Oct. 2011		9.7			9.7			0.0
	EEPR Amortization		Oct. 2011		4.6			0.0			4.6
	EEIR Base		Oct. 2011		3.1			2.6			0.5
	EEIR Amortization		Oct. 2011		0.5	⁽¹⁾		0.0			0.5
		Total Revenue Requirement		$	(50.9)		$	(42.7)		$	(8.2)

⁽¹⁾	In accordance with Alternative Revenue Accounting, SPPC recognized approximately $0.5 million in revenues pertaining to 2010.
	Based on the order from the PUCN in May 2011, which clarified the calculation of EEIR revenues, SPPC does not expect to record
	further revenue from this rate request; however, SPPC does expect to collect approximately $0.5 million from its customers.
⁽²⁾	Represents present revenue requirement at the time of filing.

In March 2011, SPPC filed an application to create a new DEAA rate to refund over-collected gas costs and to establish a new STPR (Solar Thermal Prospective Rate) to recover a legislatively mandated solar thermal program. In September 2011, the PUCN accepted stipulations which resulted in an overall decrease in revenue requirement of $12.1 million that was effective October 1, 2011.

In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $8.3 million, a decrease of 4.69%, while refunding approximately $17 million of deferred gas costs. The new DEAA rate became effective October 1, 2010.

In March 2010, SPPC filed an application to create a new DEAA rate. In September, the PUCN accepted a stipulation to decrease rates by $47.0 million, a decrease of 6.31%, while refunding $101 million of deferred fuel and purchased power costs. The new DEAA rate became effective October 1, 2010.

In June 2010, SPPC filed its statutorily required GRC for its Nevada electric operations and further updated the filing in July and August 2010. The filing, as updated, requested an ROE of 10.75% and ROR of 8.14% and an increase to general revenues of $29.3 million.

The PUCN issued its order in December 2010, which resulted in the following significant items:

In June 2010, SPPC filed a GRC for its gas operations and further updated the filing in July and August 2010. The filing, as updated, requested an ROE of 10.75% and ROR of 5.48% and an increase to general revenues of $4.3 million.

The PUCN issued its order in December 2010, which resulted in the following significant items:

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

In 2009, the Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation. The regulation was adopted by the Legislature on July 22, 2010. Accordingly, as of August 1, 2010, the Utilities began recording the amount of additional revenues which are objectively determinable and probable of recovery and are attributable to reduced kWh sales related to energy efficiency programs, prior to their inclusion in rates in accordance with FASC 980-605-25, Alternative Revenue Programs.

In October 2010, the Utilities filed to set 2011 base rates effective mid-2011 to recover approximately $35.1 million and $7.6 million for NPC and SPPC, respectively, for estimated reduced kWh sales related to the Utilities' energy efficiency programs. Annually, thereafter, the Utilities file in March, to adjust rates and set a clearing rate or EEIR for over or under collected balances, effective in October of the same year. In May 2011, the PUCN issued a final order on the October 2010 filing authorizing increases to the base rates of $14.5 million and $2.6 million for NPC and SPPC, respectively, effective July 1, 2011. As a result of the May order, in June 2011, NPC and SPPC recorded a pre-tax adjustment to earnings for revenue previously recorded of approximately $4.5 million and $4.1 million, respectively. As of December 31, 2011, NPC and SPPC recognized 2011 revenues of approximately $15.5 million and $2.5 million, respectively, of the authorized EEIR base amounts.

In March 2011 and 2012, the Utilities filed applications with their annual DEAA filings to reset the base rates and clear the accumulated regulatory asset accounts between January 1 and December 31, 2010 and 2011, respectively, with rates effective October 2011 and January 2013, respectively. Reference further discussion above at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filings.

In addition, the regulation approved the transition of the recovery of energy efficiency program costs from general rates (filed every 3 years) to recovery through independent annual rate filings. Accordingly, in their filing made in October 2010, the Utilities requested to set base rates beginning mid-2011 to recover the 2011 costs of implementing energy efficiency program costs of approximately $71.0 million and $12.1 million for NPC and SPPC, respectively. In May 2011, the PUCN issued a final order authorizing increases to the base rates of $58.4 million and $9.7 million for NPC and SPPC, respectively, effective July 1, 2011. As of December 31, 2011, NPC and SPPC recorded $37.3 million and $6.2 million respectively, of EEPR revenues. Costs accumulated between January 1 and December 31, 2010 and 2011, respectively, were requested for recovery in the March 2011 and 2012 filings with rates effective October 2011 and January 2013, respectively. Reference further discussion above at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filings.

In February 2011, NVE and the Utilities cancelled plans to construct the EEC due to increasing environmental and economic uncertainties. In June 2009, the Utilities filed to withdraw the initial construction application under the Utility Environmental Protection Act (UEPA) filed in 2006 due to postponing the construction of the EEC. The PUCN had previously approved the Utilities spending on development costs and farming assets for the EEC up to $130 million, of which the Utilities had spent and recorded as an other deferred asset approximately $58.0 million as of December 31, 2011. In compliance with the SPPC 2010 Electric GRC, SPPC filed a separate application concurrent with the filing of NPC's GRC filed in June 2011, to determine the reasonableness of the EEC project development costs and farming assets and proposed reclassification of these costs from a deferred debit to a regulatory asset. In December 2011, the PUCN authorized recovery of approximately $23.2 million of the development costs for NPC and reclassification of $23.1 million of farming assets to a regulatory asset for NPC. The PUCN also authorized SPPC to reclassify approximately $11.6 million of development costs and farming assets to regulatory asset accounts. In accordance with NPC's December 2011 GRC order, farming assets on NPC and SPPC are subject to prudence review in a subsequent filing to the PUCN.

NPC and SPPC were participants in a FERC proceeding wherein California parties have been authorized to recalculate, or mitigate, the prices they paid for wholesale spot market power between October 2, 2000 and June 20, 2001. Both of the Utilities made spot market sales that were eligible for mitigation. NPC and SPPC have negotiated a comprehensive settlement with the California parties and a FERC order on the joint offer of settlement was approved in February 2012.

At the time of the settlement the CAISO and CALPX owed NPC approximately $19 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and for which NPC had fully reserved in 2001. As a part of the settlement, NPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.

At the time of the settlement the CAISO and CALPX owed SPPC approximately $1 million (plus interest) for power delivered during the same timeframe, but which was being held pending resolution of the FERC proceedings, and SPPC had recorded a reserve against the receivable in 2001. As a part of the settlement, SPPC released these receivables to the California parties which resulted in reversal of the accounts receivable reserve as of December 31, 2011.

As a result of the February 2012 FERC order, NPC and SPPC released to the California parties, NPC and SPPC's claims to the receivables held by the CALPX and CAISO, plus interest therein, and, paid an immaterial cash amount.

In October 2012, NPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2003. The rate changes requested in this filing would result in an overall annual revenue increase of $11.3 million. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013 and accepted two proposed rate decreases effective January 1, 2013. All rates are subject to final approval by FERC in 2013.

In October 2012, SPPC filed an application with the FERC to reset transmission and ancillary service rates that were last set in 2007 and 2003, respectively. The rate changes requested in this filing would result in an overall annual revenue increase of $3.2 million. In December 2012, FERC issued an order which suspended certain rate increases until June 1, 2013 and accepted two proposed rate decreases effective January 1, 2013. All rates are subject to final approval by FERC in 2013.