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 16, 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):

				2011
			NVE Total		NPC Electric			SPPC Electric		SPPC Gas
Deferred Energy
	Cumulative Balance authorized in 2011 DEAA		$	(334,102)	$	(189,032)	⁽¹⁾	$	(115,955)	$	(29,115)
	2011 Amortization			247,489		120,340			104,909		22,240
	2011 Deferred Energy Over Collections⁽²⁾			(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 Deferred Energy	$	(142,639)	$	(57,274)		$	(56,337)	$	(29,028)

(1) Refer to NPC 2011 DEAA “Settled Regulatory Actions” below for separate discussion regarding rate offset of this balance.

(2) These deferred energy over collections will be filed in the March 2012 DEAA filings.

				2010
			NVE Total		NPC Electric			SPPC Electric		SPPC Gas
Nevada Deferred Energy
	Cumulative Balance authorized in 2010 DEAA⁽¹⁾		$	(220,064)	$	(102,398)	⁽²⁾	$	(100,625)	$	(17,041)
	2010 Amortization			74,215		22,441			40,682		11,092
	2010 Deferred Energy Over Collections⁽³⁾			(184,776)		(106,178)			(55,615)		(22,983)
Nevada Deferred Energy Balance at December 31, 2010 - Subtotal			$	(330,625)	$	(186,135)		$	(115,558)	$	(28,932)
Cumulative CPUC balance⁽⁴⁾				(3,210)		-			(3,210)		-
Reinstatement of deferred energy (effective 6/07, 10 years)				132,409		132,409			-		-

		Total Deferred Energy	$	(201,426)	$	(53,726)		$	(118,768)	$	(28,932)

Deferred Assets
	Deferred energy		$	117,623	$	117,623		$	0	$	0
Current Liabilities
	Deferred energy			(315,839)		(171,349)			(115,558)		(28,932)
	Liabilities held for sale			(3,210)		-			(3,210)		-
		Total Deferred Energy	$	(201,426)	$	(53,726)		$	(118,768)	$	(28,932)

(2) Refer to NPC DEAA under “Settled Regulatory Actions” below for separate discussion regarding the NPC rate offset of their 2010 cumulative balance against their deferred rate increase included in other regulatory assets.

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, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return⁽¹⁾		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	72,408	$	-	$	-		$	72,408	$	84,692
	Income taxes	Various		-		251,314		-			251,314		257,078
	Merger costs	Various thru 2046		-		268,668		-			268,668		282,535
	Lenzie Generating Station	2042		-		67,351		-			67,351		77,524
	Mohave Generating Station and deferred costs	2017		9,861		12,654		1,645	⁽²⁾		24,160		25,849
	Piñon Pine	Various thru 2029		27,377		7,016		-			34,393		38,960
	Asset retirement obligations	-		-		-		67,891	⁽²⁾		67,891		55,182
	Conservation programs	Various thru 2017		151,035		-		7,412	⁽³⁾		158,447		177,515
	EEPR	Various thru 2013		30,379		-		-			30,379		30,409
	Ely Energy Center	2017		-		23,403		34,563	⁽²⁾		57,966		-
	Legacy Meters	-		-		-		21,777	⁽²⁾		21,777		-
	Renewable energy programs	2013		29,592		-		-			29,592		2,627
	Peabody coal costs	-		-		17,899		-			17,899		17,738
	Deferred Rate Increase	2011		12,177		-		-			12,177		91,678
	Risk management	-		-		2,426		-			2,426		30,726
	Other costs	Various thru 2031		24,229		33,852		11,198	^{(2, 3)}		69,279		64,646
	Subtotal	-	$	357,058	$	684,583	$	144,486		$	1,186,127	$	1,237,159
	Pensions	-		-		215,656		-			215,656		269,472
Total regulatory assets			$	357,058	$	900,239	$	144,486		$	1,401,783	$	1,506,631

Regulatory liabilities
	Cost of removal	Various	$	422,033	$	-	$	-		$	422,033	$	382,634
	Income taxes	Various		-		17,433		-			17,433		19,506
	Gain on property sales	2013		4,444		-		32,844	⁽³⁾		37,288		7,151
	Renewable energy programs	2012		1,046		-		-			1,046		10,234
	Other	Various thru 2017		6,183		-		2,276			8,459		8,589
Total regulatory liabilities			$	433,706	$	17,433	$	35,120		$	486,259	$	428,114

		NPC
		OTHER REGULATORY ASSETS AND LIABILITIES

		As of December 31, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return⁽¹⁾		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	39,958	$	-	$	-		$	39,958	$	43,765
	Income taxes	Various		-		178,060		-			178,060		174,022
	Merger costs	Various thru 2044		-		168,212		-			168,212		176,974
	Lenzie Generating Station	2042		-		67,351		-			67,351		77,524
	Mohave Generating Station and deferred costs	Various thru 2017		9,861		12,654		1,645	⁽²⁾		24,160		25,849
	Asset retirement obligations	-		-		-		60,797	⁽²⁾		60,797		48,970
	Conservation programs	Various thru 2017		129,885		-		4,004	⁽³⁾		133,889		144,107
	EEPR	Various thru 2013		25,250		-		-			25,250		24,905
	Ely Energy Center	2017		-		23,403		22,970	⁽²⁾		46,373		-
	Legacy Meters	-		-		-		21,777	⁽²⁾		21,777		-
	Renewable energy programs	2013		10,694		-		-			10,694		-
	Peabody coal costs	-		-		17,899		-			17,899		17,738
	Risk management	-		-		2,426		-			2,426		20,261
	Deferred Rate Increase	2011		12,177		-		-			12,177		91,678
	Other costs	2017		13,324		21,772		8,870	^{(2, 3)}		43,966		26,189
	Subtotal	-	$	241,149	$	491,777	$	120,063		$	852,989	$	871,982
	Pensions	-		-		108,528		-			108,528		133,410
Total regulatory assets			$	241,149	$	600,305	$	120,063		$	961,517	$	1,005,392


Regulatory liabilities
	Cost of removal	Various	$	232,093	$	-	$	-		$	232,093	$	208,795
	Income taxes	Various		-		5,798		-			5,798		6,557
	Gain on property sales	-		-		-		32,844	⁽³⁾		32,844		0
	Renewable energy programs	2013		1,046		-		-			1,046		7,797
	Other	2017		925		-		2,245			3,170		2,834
Total regulatory liabilities			$	234,064	$	5,798	$	35,089		$	274,951	$	225,983

		SPPC
		OTHER REGULATORY ASSETS AND LIABILITIES

		As of December 31, 2011
		Remaining	Receiving Regulatory Treatment				Pending					As of
DESCRIPTION		Amortization	Earning a		Not Earning		Regulatory			2011		December 31, 2010
		Period	Return⁽¹⁾		a Return		Treatment			Total		Total
Regulatory assets
	Loss on reacquired debt	Term of Related Debt	$	32,450	$	-	$	-		$	32,450	$	40,927
	Income taxes	Various		-		73,254		-			73,254		83,056
	Merger costs	Various thru 2046		-		100,456		-			100,456		105,561
	Risk management	-		-		-		-			-		10,465
	Piñon Pine	Various thru 2029		27,377		7,016		-			34,393		38,960
	Asset retirement obligations	-		-		-		7,094	⁽²⁾		7,094		6,212
	Conservation programs	Various thru 2013		21,150		-		3,408	⁽³⁾		24,558		33,408
	EEPR	Various thru 2013		5,129		-		-			5,129		5,504
	Renewable energy programs	2013		18,898		-		-			18,898		2,627
	Ely Energy Center	-		-		-		11,593	⁽²⁾		11,593		-
	Other costs	Various thru 2031		10,905		12,080		2,328	^{(2, 3)}		25,313		38,457
	Subtotal	-	$	115,909	$	192,806	$	24,423		$	333,138	$	365,177
	Pensions	-		-		104,159		-			104,159		131,734
Total regulatory assets			$	115,909	$	296,965	$	24,423		$	437,297	$	496,911


Regulatory liabilities
	Cost of removal	Various	$	189,940	$	-	$	-		$	189,940	$	173,839
	Income taxes	Various		-		11,635		-			11,635		12,949
	Gain on property sales	2013		4,444		-		-			4,444		7,151
	Renewable energy programs	-		-		-		-			-		2,437
	Other costs	Various thru 2043		5,258		-		31	⁽³⁾		5,289		5,755
Total regulatory liabilities			$	199,642	$	11,635	$	31		$	211,308	$	202,131

(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 2011, the Legislature passed Assembly Bill 215 which allows an electric or gas utility that adjusts its BTER on a quarterly basis to request PUCN approval to make quarterly changes to its DEAA rate if the request is in the public interest. The Utilities will still be required to file an annual DEAA case to review costs for prudency and reasonableness, and if any costs are disallowed on such grounds, the disallowance will be incorporated into the next subsequent quarterly rate change. SPPC filed an application to change its quarterly DEAA rates for both electric and gas in July 2011, and in October 2011, the PUCN accepted a stipulation authorizing the first quarterly adjustments to the electric and gas DEAAs to become effective on January 1, 2012. NPC filed an application to change its quarterly DEAA in October 2011, and in December 2011, the PUCN accepted a stipulation authorizing the first quarterly adjustment to the DEAA to become effective on April 1, 2012.

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

In 2009, the Nevada Legislature passed Senate Bill 358, which required the PUCN to adopt regulations authorizing an electric utility to recover lost revenue that is attributable to the measurable and verifiable effects associated with the implementation of efficiency and conservation programs approved by the PUCN. As a result, the PUCN opened Docket No. 09-07016 to amend and adopt the regulation. The regulation was adopted by the Legislature on July 22, 2010. 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 will make a filing 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 have recognized 2011 revenues of approximately $15.5 million and $2.5 million, respectively, of the authorized EEIR base amounts.

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

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 have recorded $37.3 million and $6.2 million respectively, of EEPR revenues. Costs accumulated between August 1, 2010 and December 31, 2010 were requested for recovery in the March 2011 filing with rates effective October 2011. Reference further discussion below at NPC and SPPC DEAA, TRED, REPR, EEIR, EEPR Rate Filing.

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 have 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.

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):


			Effective Date	Authorized Revenue Requirement			Present Revenue Requirement		$ Change in Revenue 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		-
	EEPR Amortization		Oct. 2011		21.3			-		21.3
	EEIR Base		Oct. 2011		17.1			14.5		2.6
	EEIR Amortization		Oct. 2011		4.8	⁽¹⁾		-		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.

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.

In February 2009, NPC filed an application to create a new DEAA rate. In this application, NPC requested to increase rates by $72.1 million, an increase of 3.18%, while recovering $77.5 million of deferred fuel and purchased power costs. In September 2009, the PUCN ordered that the DEAA rate remain set at $0.00 per kWh, in addition, the PUCN also ordered a slight increase to the TRED charge and a slight decrease to the REPR which resulted in a net decrease to revenues of $4.6 million, or a 0.20% decrease. The PUCN found that NPC's purchases of fuel and power were prudent and approved those costs for the test period which were included as an offset to 2009 deferred energy over-collections within the 2010 DEAA filing.

In December 2008, NPC filed its statutorily required GRC with the PUCN and further updated the filing in February and March 2009. The filing, as updated, requested an ROE of 11.0% and ROR of 8.88% and an increase to general revenues of $305.7 million.

The PUCN issued its order in June 2009, which resulted in the following significant items:

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 $12.2 million, which has been approved by the PUCN and included in rates. All other costs for Mohave Generating Station, including approximately $12.7 million of decommissioning costs were accumulated in other regulatory assets as incurred and were requested for recovery in NPC's 2011 GRC and 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 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		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		-
	EEPR Amortization		Oct. 2011		4.6			-		4.6
	EEIR Base		Oct. 2011		3.1			2.6		0.5
	EEIR Amortization		Oct. 2011		0.5	⁽¹⁾		-		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 their customers.

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. The PUCN authorized the refund and recovery of the following amounts (dollars in millions):

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:

In July 2008, SPPC filed a GRC with the CPUC and subsequently filed an amendment to the original filing in December 2008. SPPC requested an ROE of 11.4% and ROR of 8.81% and an increase in general revenues of $8.9 million. In July 2009, a settlement was filed with the CPUC, which includes the following:

The CPUC approved the settlement and rates were effective December 1, 2009. However, on January 1, 2011, SPPC sold its California Assets, as discussed further in Note 16, Assets Held for Sale.

In February 2009, SPPC filed an application to create a new electric DEAA rate for Nevada customers. In this application, SPPC requested to decrease rates by $25.9 million, a decrease of 2.69%, while refunding $19.8 million of deferred fuel and purchased power costs. The PUCN issued its order in September 2009 decreasing rates by $30.8 million, a decrease of 3.19% and approving SPPC's purchases of fuel and power as prudent for the test period. The new credit DEAA rate became effective October 1, 2009.

In February 2009, SPPC filed an application to create a new gas DEAA rate for Nevada customers. In this application, SPPC requested to decrease rates by $8.7 million, a decrease of 4.71%, while refunding $8.7 million of deferred gas costs. The PUCN issued its order in September 2009 approving SPPC's requested rate decrease and approving SPPC's purchases of natural gas and propane as prudent for the test period. The new DEAA rate became effective October 1, 2009.

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 have collectively agreed to release to the California parties, NPC and SPPC's claims to the receivables held by the CALPX and CAISO, plus interest therein, and to pay an immaterial amount in cash.