The Utilities enter into several purchase commitments for electric power, coal, natural gas and transportation, as well as, long-term service agreements, capital project commitments and operating leases. Detailed below are estimates of future commitments under these arrangements (dollars in millions):

		NVE
	2013		2014		2015		2016		2017		Thereafter		Total
Purchased Power	$	521.9	$	508.6	$	515.7	$	518.9	$	522.4	$	4,555.8	$	7,143.3
Purchased Power - Not Commercially Operable		3.9		90.1		109.4		117.7		118.5		2,836.3		3,275.9
Coal & Natural Gas		472.3		221.8		59.3		43.5		44.4		93.1		934.4
Transportation		139.3		173.7		160.9		142.7		135.1		1,719.3		2,471.0
Long-Term Service Agreements		20.7		20.0		21.4		19.5		18.1		51.1		150.8
Capital Projects		99.7		1.8		0.4		0.0		0.0		0.0		101.9
Operating Leases		17.4		15.8		11.5		6.6		5.3		128.3		184.9
Total Commitments	$	1,275.2	$	1,031.8	$	878.6	$	848.9	$	843.8	$	9,383.9	$	14,262.2

		NPC
	2013		2014		2015		2016		2017		Thereafter		Total
Purchased Power	$	430.3	$	411.4	$	416.7	$	417.9	$	419.7	$	3,779.2	$	5,875.2
Purchased Power - Not Commercially Operable		3.9		85.7		103.9		112.1		112.9		2,718.0		3,136.5
Coal & Natural Gas		350.9		160.6		45.8		43.5		44.4		93.1		738.3
Transportation		75.8		115.4		127.8		114.1		110.7		1,601.3		2,145.1
Long-Term Service Agreements		15.6		15.2		15.9		15.0		14.0		32.3		108.0
Capital Projects		94.5		1.2		0.3		0.0		0.0		0.0		96.0
Operating Leases		9.4		8.7		6.1		4.7		4.1		95.0		128.0
Total Commitments	$	980.4	$	798.2	$	716.5	$	707.3	$	705.8	$	8,318.9	$	12,227.1

		SPPC
	2013		2014		2015		2016		2017		Thereafter		Total
Purchased Power	$	124.4	$	97.2	$	99.0	$	101.0	$	102.7	$	776.6	$	1,300.9
Purchased Power - Not Commercially Operable		-		4.4		5.5		5.6		5.6		118.3		139.4
Coal & Natural Gas		121.4		61.2		13.5		-		-		-		196.1
Transportation		63.5		58.3		33.1		28.6		24.4		118.0		325.9
Long-Term Service Agreements		5.1		4.8		5.5		4.5		4.1		18.8		42.8
Capital Projects		5.2		0.6		0.1		-		-		-		5.9
Operating Leases		5.5		4.6		3.0		1.9		1.2		33.3		49.5
Total Commitments	$	325.1	$	231.1	$	159.7	$	141.6	$	138.0	$	1,065.0	$	2,060.5

The Utilities have several contracts for long-term purchase of electric energy; the expiration of these contracts range from 2013 to 2039. While the Utilities are not required to make payment if power is not delivered under these contracts, estimated future payments are included in the tables above. Related party purchase power agreements have been eliminated from the NVE totals for the year 2013.

The Utilities entered into several contracts for long-term purchase of electric energy in which the facility remains under development. This represents the estimated payments under renewable energy power purchase contracts, which have been approved by the PUCN and are contingent upon the developers obtaining commercial operation and their ability to deliver power.

The Utilities have several long-term contracts for the purchase of coal and natural gas; the expiration of these contracts range from 2013 to 2019.

The Utilities have several long-term contracts for the transport of coal and natural gas. Also included in the transportation obligations is the TUA with GBT, of which NPC will be responsible for 95% and SPPC 5%. The TUA remains contingent upon final construction costs, and reaching commercial operation. The expiration of these transportation contracts range from 2013 to 2054.

The Utilities have long term service agreements for the performance of maintenance on generation units. Obligation amounts are based on estimated usage.

Capital projects at NPC includes NPC's requirement to purchase the CDWR's share of the undepreciated cost of capital of Reid Gardner Generating Station Unit No. 4 in 2013 (see Note 5, Jointly Owned Properties), at which time NPC will be required to assume all associated operating and maintenance costs for the Unit. Additionally, the Utilities have obligations regarding the construction of ON Line, of which NPC will be responsible for 95% and SPPC 5%.

The Utilities have entered into various non-cancelable operating leases primarily for building, land and equipment. Contract expiration dates range from 2013 to 2103. NVE's rent payments meeting the above described criteria for 2012 and 2011 were $2.4 million and $2.4 million respectively. Prior to 2011, NVE did not have non-cancelable operating leases that were material. NPC's rent payments meeting the above described criteria for 2012, 2011 and 2010 were $9.6 million, $11.5 million and $13.6 million respectively. SPPC's rent payments meeting the above described criteria for 2012, 2011 and 2010 were $5.8 million, $7.4 million and $14.0 million respectively.

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 for this property going forward, including reclamation or sale to a third party.

On October 4, 2011, NPC 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 NPC's Reid Gardner Generating Station located near Moapa, Nevada. NPC operates the facility and owns Units 1-3. Unit 4 of the facility is co-owned with the California Department of Water Resources. The EPA's Section 114 information request does not allege any incidents of non-compliance at the plant. NPC completed its responses to EPA during the first quarter of 2012 and will continue to monitor developments relating to this Section 114 request. At this time, NPC cannot predict the impact, if any, associated with this information request.

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. At this time, SPPC cannot predict the impact, if any, associated with this information request.

In 2005, the EPA finalized amendments to its Regional Haze Rules that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Certain NVE generating facilities are subject to BART requirements. Pursuant to the EPA's Regional Haze Rules, individual states were required to identify the facilities located in their states that will have to reduce sulfur dioxide (SO2), nitrogen oxide (NOx) and particulate matter emissions under BART and then set emissions limits for those facilities.

In June 2011, the EPA published in the Federal Register its proposal to approve Nevada's State Implementation Plan (SIP) implementing the Regional Haze Rules for affected units in the State of Nevada, which includes units at our Reid Gardner, Tracy and Ft. Churchill Generating Stations. However, in March 2012, the EPA approved Nevada's SIP as it pertains to all affected units and emissions, except for NOx controls at Units 1-3 at the Reid Gardner Generating Station. The specified compliance date for this action, which includes the affected Tracy and Ft. Churchill Generating Station units, is January 1, 2015. In that same March 2012 Federal Register notice, the EPA stated that it intended to make a BART determination on those Reid Gardner Generating Station Units at a later date. In August 2012, the EPA published its final determination for NOx BART controls for the Reid Gardner Generating Station Units 1-3, approving and rejecting certain components of Nevada's SIP. For the limited portions of Nevada's SIP that EPA rejected, it put in place a Federal Implementation Plan (FIP) that will remain enforceable until such time as Nevada submits a revised SIP to address the concerns the EPA noted in its August 2012 Federal Register notice. Within the August 2012 notice, the EPA approved Nevada's determination in its SIP that the installation of selective non-catalytic reduction technology (SNCR) represented BART for purposes of compliance with the Regional Haze Rule, with a specified compliance date of January 1, 2015. On October 19, 2012, NPC submitted to EPA a Petition for Reconsideration of the August 2012 final rule requesting EPA to reconsider the compliance deadline so that it be set no earlier than June 30, 2016, which would match the modified compliance data put forward by the State of Nevada. The modified State's compliance date of 2016 also applies to SPPC. Since filing of the Petition for Reconsideration, NPC has participated in various discussions with EPA regarding the compliance date. A final decision from EPA on the Petition for Reconsideration remains pending.

NVE continues to work toward finalizing the retrofit designs for the affected BART units. NVE filed and has already received approval from the PUCN to retire Tracy Generating Station Units 1 and 2, and install retrofit controls on Tracy Generating Station Unit 3 and Ft. Churchill Generating Station Units 1 and 2. NVE intends to also file with the PUCN the request to install SNCRs on Reid Gardner Generating Station Units 1, 2 & 3. Compliance with the Regional Haze Rules are estimated to cost approximately $77.1 million, excluding AFUDC, over the next several years; however, these costs are preliminary and subject to change based on final engineering analysis and retirement of generating station units. NVE expects that costs incurred to comply with the Regional Haze Rules would be capitalized and recovered through the Utilities' regulatory proceedings similar to other environmental compliance requirements.

Environmental groups have challenged both of the EPA's final determinations with respect to Nevada's regional haze SIP submittal. In May 2012, WildEarth Guardians petitioned the Ninth Circuit to review the EPA's March 2012 approval of Nevada's SIP for all affected units and emissions except NOx controls at the Reid Gardner Generating Station, alleging that the EPA's approval did not conform to the requirements set forth in the Regional Haze Rule. NVE has intervened in that lawsuit. In October 2012, Earthjustice, on behalf of the Moapa Band of Paiute Indians, Sierra Club, and the National Parks Conservation Association, petitioned the Ninth Circuit to review the EPA's August 2012 final determinations pertaining to NOx controls at the Reid Gardner Generating Station. NVE has intervened in this lawsuit. At this time management is unable to determine the likelihood of success by petitioners in these litigation matters. An adverse decision in either lawsuit could impact our compliance strategy for the Tracy, Ft. Churchill and Reid Gardner Generating Stations, and could result in the requirement to install more stringent emissions controls, or the retirement of certain units earlier than currently planned.

The Navajo Generating Station is also an affected unit under EPA's Regional Haze Rules. On January 17, 2013, the EPA announced a proposed FIP addressing BART and an “Alternative to BART” for the Navajo Generating Station that includes a flexible timeline for reducing NOx emissions. NVE, along with the other owners of the facility, are reviewing the EPA proposal to determine its impact on the viability of the plant's future operations. The land lease for the Navajo Generating Station is up for renewal in 2019. Renewal of this lease will require completion of an Environmental Impact Statement as well as a renewal of the fuels supply agreement, among other considerations. It is believed that the EPA BART proposal will require an investment of up to $1.1 billion in additional emission controls at the plant of which NPC's ownership share is 11.3%. Given that the lease must be renegotiated by 2019, the timeline for BART installation is unclear, and EPA's overall proposal will be subject to significant input from a variety of affected parties before it is finalized, NVE cannot predict at this time the ultimate financial impact to the Navajo Generating Station operations or what other alternative actions the ownership may decide to take at this time.

In December 2011, the EPA signed for publication in the Federal Register a final rule regulating hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units. The rule, referred to as the MATS rule requires coal- and oil-fired electric utility steam generating units to meet HAP emission standards reflecting the application of the maximum achievable control technology (MACT). The final MATS rule (previously referred to as the Utility MACT Rule) was published in the Federal Register on February 16, 2012. The final rule establishes emission limits for hazardous air pollutants from new and existing coal-fired and oil-fired steam electric generating units. The rule requires sources to comply with the emission limits by April 16, 2015, with a potential one year compliance extension available for sources that are unable to complete the installation of emission controls before the compliance deadline. Numerous petitions for review of the final MATS rule have been filed with the United States Court of Appeals for the District of Columbia. The court has established a schedule for the litigation that has final briefs being filed as soon as in April, 2013.

The final rule does not specifically list control technologies that are required to achieve the MATS emission standards. Coal- and oil-fired electric generating units are required to meet the applicable HAP emission limits using whatever control technology, or combination of technologies, they deem appropriate for their specific situation. In general, control technology requirements will be a function of the fuel being fired and the performance of existing air pollution control systems. Based on a review of emissions data available from NVE's generating units, as well as emissions data available from EPA for similar sources, the Utilities anticipate that SO2 and/or acid gas reduction will be required at SPPC's Valmy Generating Station, Unit 1 to achieve compliance with the MATS standards. At the present time, SPPC believes a dry sorbent injection system will be selected as the final control option for Unit 1, at an estimated capital cost for SPPC's 50% ownership interest of approximately $6.4 million, excluding AFUDC. Note that the actual cost will be dependent upon final engineering design.

Currently, all four of the units at the Reid Gardner Generating Station, as well as Unit 2 at the Valmy Generating Station are compliant with the MATS emission standards, based on the current fuel blend. However, NVE and the Utilities will continue to monitor the chemical coal composition utilized in these units to ensure continued compliance.

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. Due to the age and/or historical usage of past and present operating properties, the Utilities may be responsible for various levels of environmental remediation at contaminated sites. This can include properties that are part of ongoing Utility operations, sites formerly owned or used by NVE or the Utilities, and/or sites owned by third parties. The responsibility to remediate typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, NVE, the Utilities or their respective affiliates could potentially be held responsible for contamination caused by other parties. In some instances, NVE or the Utilities may share liability associated with contamination with other parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. These types of sites/situations are generally managed in the normal course of business operations.

In 2008, NPC signed an Administrative Order of Consent (AOC) as owner and operator of Reid Gardner Generating Station Unit Nos. 1, 2 and 3 and as co-owner and operating agent of Unit No. 4. Based on the AOC, in 2008, NPC recorded estimated ARO and capital remediation costs. However, actual costs of work under the AOC may vary significantly once the scope of work is defined and additional site characterization has been completed.

NVE and the Utilities seek to continually comply with environmental regulations; however, given the uncertainties involved in the federal, state and local regulatory environment, future costs to comply may be material.

NPC owns an 11% interest in the Navajo Generating Station, which is located in northern Arizona and operated by Salt River Project (SRP). 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 SRP 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.

In June 1999, the Navajo Nation filed suit against SRP, several Peabody Coal Company entities (collectively referred to as “Peabody”) and SCE in the U.S. District Court for the District of Columbia (the “DC Lawsuit”). NPC was 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 asserted claims relating to the renegotiation of coal royalty and lease agreements and alleged, among other things, that the defendants obtained a favorable coal royalty rate for leases under which Peabody mined coal for both the Navajo Generating Station and Mohave Generating Station by improperly influencing the outcome of a federal administrative process. The DC Lawsuit sought $600 million in damages and punitive damages of not less than $1.0 billion.

In 2004, Peabody brought suit against the Navajo Joint Owners in state court in St. Louis, Missouri, seeking a declaration that the Navajo Joint Owners are obligated to reimburse Peabody for any royalty, tax or other obligations arising out of the DC Lawsuit. In July 2008, the court dismissed all counts against NPC, two without prejudice to their possible re-filing.

In August 2011, all claims in the DC Lawsuit were dismissed pursuant to a settlement agreement among the Navajo Nation, Peabody, SRP and SCE. At the request of SRP, NPC contributed an immaterial amount toward the settlement of the DC Lawsuit based on its 11% ownership stake in the Navajo Generating Station.

SCE also has asked that the Mohave Joint Owners, including NPC, contribute toward the settlement based upon their ownership stakes in the Mohave Generating Station. NPC has not agreed to contribute to SCE's portion of the DC Lawsuit settlement. Management has discussed the matters with SCE, but does not believe the impact of any claim by, or settlement with, SCE will be material to NPC.

In June 2001, SPPC sold four hydro generating units (10.3 MW total capacity) located in Nevada and California to TMWA for $8.0 million. One of the units, the Farad Hydro (2.8 MW), has been out of service since the summer of 1996 due to a collapsed flume. 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. The current estimate to rebuild the diversion dam, if management decides to rebuild, is approximately $20 million.

SPPC filed a claim with the Farad Dam's insurers, Hartford Steam Boiler Inspection and Insurance Company and Zurich-American Insurance Company, and in 2003 initiated federal court litigation against the insurers. The insurers contested the extent and amount of insurance coverage. Coverage was established through this litigation, but until July 2012 the matter remained in litigation to determine the amount of coverage.

In July 2012, the U.S. Court of Appeals for the Ninth Circuit entered its order reversing the valuation holding of the U.S. District Court and setting the value of Farad Dam at $19.8 million dollars (as was argued by SPPC), with some deduction for depreciation to be determined on remand. The court also affirmed SPPC's right to recover $4.0 million dollars in permitting and design costs, but held that if SPPC accepts the money, rather than rebuild, the $4.0 million is part of the $19.8 million replacement cost. In addition, the court held that SPPC is entitled to recover full replacement cost in the event of a rebuild, and that the District Court is free, on remand, to extend the three year time to rebuild to start at the conclusion of all litigation.

It is not known at this time when the District Court will set hearings for the issues remanded by the Ninth Circuit. Management cannot assess or predict the outcome or the impact of the District Court decisions at this time, but they are not expected to be material to SPPC.

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.

During the second quarter of 2011, NVE began to construct Phase 1 of ON Line, which is a joint project between the Utilities and GBT-South. Construction of Phase 1 consists of the initial 500 kV interconnection between the Robinson Summit substation on the SPPC system and the Harry Allen substation on the NPC system. ON Line has an expected in-service date of no later than December 31, 2013. The Utilities will own a 25% interest in Phase 1 and have entered into a TUA with GBT-South for its 75% interest in Phase 1. Under the terms of the TUA, NVE's future lease payments are adjusted for construction costs, including cost overruns; for which the Utilities expect to get regulatory recovery of. For accounting purposes NVE is treated as the owner of the construction project in accordance with Lease Accounting, The Effect of Lessee Involvement in Asset Construction of the FASC. As a result, as of December 31, 2012, capitalized construction costs associated with GBT's 75% interest were $264.9 and $14.2 million at NPC and SPPC, respectively, in CWIP with a corresponding credit to other deferred liabilities. NVE expects to recover future lease payments including cost overruns through the Utilities' regulatory proceedings.