Commitments Contingencies and Proposed Environmental Matters

9 Months Ended

Sep. 30, 2011

Commitments Contingencies and Proposed Environmental Matters [Abstract]

COMMITMENTS, CONTINGENCIES AND PROPOSED ENVIRONMENTAL MATTERS

NOTE 6. COMMITMENTS, CONTINGENCIES AND PROPOSED ENVIRONMENTAL MATTERS

UNISOURCE ENERGY AND TEP COMMITMENTS

Through September 2011, UniSource Energy has spent $59 million to acquire land and develop a new headquarters building in downtown Tucson. UniSource Energy has a remaining commitment of $10 million at September 30, 2011. UniSource Energy expects to sell the land and building to TEP at cost in November 2011. TEP expects to complete the building in the fourth quarter of 2011.

TEP COMMITMENTS

In 2011, TEP entered into the following new long-term purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K:

	Purchase Commitments
	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Coal(1)	$	34	$	40	$	14	$	14	$	—	$	—	$	102
Transportation(2)		3		4		4		4		4		8		27
Purchased Power(3)		3		23		20		21		12		196		275
Solar Equipment(4)		12		12		12		—		—		—		36
Total	$	52	$	79	$	50	$	39	$	16	$	204	$	440

(1)	TEP executed a new coal supply agreement and amended an existing coal supply agreement in March 2011, incurring minimum purchase obligations.
(2)	TEP executed a new transportation agreement requiring minimum annual transport quantities of 2.4 million tons of coal to its Springerville Generating Station from July 1, 2011 through December 2017.
(3)	Purchased Power includes contracts that will settle in June 2012 through September 2014 with prices per MWh that are indexed to natural gas prices. TEP’s estimated minimum payment obligation for these purchases is based on projected market prices as of September 30, 2011. Additionally, Purchased Power includes two long-term Power Purchase Agreements (PPAs) with renewable energy generation facilities that achieved commercial operation in 2011. TEP is obligated to purchase 100% of the output from these facilities. The table above includes estimated future payments based on expected power deliveries through 2031. TEP has entered into additional long-term renewable PPAs to comply with the RES requirements; however, TEP’s obligation to accept and pay for electric power under these agreements does not begin until the facilities are constructed and operational.
(4)	TEP has a commitment to purchase 9 MW of photovoltaic equipment through December 2013. 3 MW were approved by the ACC, and 6 MW remain subject to ACC approval, which is expected in the fourth quarter of 2011.

UNS ELECTRIC COMMITMENTS

In 2011, UNS Electric entered into the following new long-term, forward power purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K.

	2011		2012		2013		2014		2015		Thereafter		Total
	-Millions of Dollars-
Purchased Power(1)	$	1	$	20	$	24	$	35	$	3	$	46	$	129

⁽¹⁾ Purchased power includes contracts that will settle in October 2011 through December 2014 at fixed prices per MWh or at prices indexed to natural gas prices. UNS Electric’s estimated minimum payment obligation for these purchases is based on projected market prices as of September 30, 2011. Purchased power commitments also include one long-term PPA with a renewable energy generation facility that achieved commercial operation in September 2011. UNS Electric is obligated to purchase 100% of the output from this facility. The table above includes estimated future payments based on expected power deliveries through 2031.

UNS GAS COMMITMENTS

In 2011, UNS Gas entered into new long-term purchase commitments for fuel in addition to those reported in our 2010 Annual Report on Form 10-K. These contracts will settle in January 2012 through July 2014 at fixed prices per MMBtu. UNS Gas’ minimum payment obligation for these purchases is $3 million in both 2012 and 2013 and $2 million in 2014.

TEP CONTINGENCIES

Settlement of El Paso Electric Dispute

In April 2011, TEP and El Paso entered into a settlement agreement, subject to approval by the FERC, to resolve a dispute over transmission service from Luna to TEP’s system. The dispute that originated in 2006 under the 1982 Power Exchange and Transmission Agreement between the parties (Exchange Agreement). In 2008, the FERC issued an order supporting TEP’s position in the dispute. El Paso subsequently appealed that order. In December 2008, El Paso refunded $11 million, including interest, to TEP for transmission service from Luna to TEP’s system from 2006 to 2008.

The settlement reduces TEP’s rights for transmission under the Exchange Agreement from 200 MW to 170 MW and requires TEP to pay El Paso a lump-sum of $5 million, equivalent to the total amount that TEP would have paid El Paso for 30 MW of transmission from February 1, 2006, through the settlement date, including interest. Under the PPFAC mechanism, TEP is allowed to recover $2 million of this additional transmission expense from its customers. In accordance with the settlement agreement, TEP has entered into two new firm transmission service agreements under El Paso’s Open Access Transmission Tariff for a total of 40 MW. The settlement agreement also requires El Paso to withdraw its appeal before the United States Court of Appeals District of Columbia Circuit and requires TEP to withdraw its related complaint before the Arizona District of the United States District Court.

The settlement agreement was filed with the FERC in June 2011, and becomes effective after: 1) issuance by the FERC of a final non-appealable order approving the settlement, and 2) issuance by the FERC of a final non-appealable order approving a settlement between El Paso and Macho Springs Power I, LLC regarding the reimbursement of network upgrade costs associated with the interconnection of the Macho Springs wind facility to the El Paso system. TEP has agreed to purchase Macho Springs’ output through a 20-year PPA and expects to begin receiving power from the facility in the fourth quarter of 2011. The settlement agreements were both approved by the FERC in August 2011 which approvals became final and non-appealable on September 30, 2011. By its terms, the TEP settlement agreement is effective November 1, 2011.

As a result, TEP recognized a pre-tax gain of approximately $7 million, including interest, in the third quarter of 2011. To reflect the gain, TEP recorded a $7.1 million net reduction to Transmission Expense, $0.9 million of Interest Income, and $0.6 million of Interest Expense on the Income Statement.

Claims Related to Navajo Generating Station

In June 1999, the Navajo Nation filed suit in the U.S. District Court for the District of Columbia (D.C. Lawsuit) against parties including SRP; several Peabody Coal Company entities including Peabody Western Coal Company (Peabody), the coal supplier to Navajo Generating Station (Navajo); Southern California Edison Company (SCE); and other defendants. Although TEP is not a named defendant in the D.C. Lawsuit, TEP owns 7.5% of Navajo Units 1, 2 and 3. The D.C. Lawsuit alleged, among other things, that the defendants obtained a favorable coal royalty rate on the lease agreements under which Peabody mines coal by improperly influencing the outcome of a federal administrative process pursuant to which the royalty rate was to be adjusted. The suit initially sought $600 million in damages, treble damages, 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 District Court dismissed all claims against SRP. In April 2010, the Navajo Nation filed a Second Amended Complaint which dropped the treble damages claim. In August 2011, the Navajo Nation, Peabody, SCE and SRP executed a written settlement agreement in return for the Navajo Nation’s dismissal of all claims in the D.C. Lawsuit. SRP has asked that the Navajo participants, including TEP, contribute toward the settlement based on its 7.5% ownership interest in the Navajo plant. TEP will pay SRP the requested contribution which will not have a material impact on TEP’s financial statements.

In 2004, Peabody filed a complaint in the Circuit Court for the City of St. Louis, Missouri against the participants at Navajo, including TEP, for reimbursement of royalties and other costs arising out of the D.C. Lawsuit. In July 2008, the parties entered into a joint stipulation of dismissal of these claims which was approved by the Circuit Court. TEP does not believe the lawsuit will be re-filed based upon the final outcome of the D.C. Lawsuit.

Claims Related to San Juan Generating Station

In April 2010, the Sierra Club filed a citizens’ suit under the Resource Conservation and Recovery Act (RCRA) and the Surface Mine Control and Reclamation Act (SMCRA) in the U.S. District Court for the District of New Mexico against PNM, as operator of San Juan; PNM’s parent PNM Resources, Inc. (PNMR); San Juan Coal Company (SJCC), which operates the San Juan mine that supplies coal to San Juan; and SJCC’s parent BHP Minerals International Inc. (BHP). The Sierra Club alleges in the suit that certain activities at San Juan and the San Juan mine associated with the treatment, storage and disposal of coal and coal combustion residuals (CCRs), primarily coal ash, are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCRs at the mine constitute “open dumping” in violation of RCRA. The RCRA claims are asserted against PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA which are directed only against SJCC and BHP. The suit seeks the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCRs at the mine or to cease placement of CCRs at the mine; the imposition of civil penalties; and attorney’s fees and costs. With the agreement of the parties, the court entered a stay of the action in August 2010, to allow the parties to try to address the Sierra Club’s concerns. If the parties are unable to settle the matter, PNM has indicated that it plans an aggressive defense of the RCRA claims in the suit. TEP cannot predict the outcome of this matter and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought, an estimate of the range of loss cannot be determined at this time.

SJCC operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC has compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.

TEP owns 50% of San Juan Units 1 and 2, which represents approximately 20% of the total generation capacity of the entire San Juan Generating Station, and is responsible for its share of any resulting liabilities.

San Juan Mine Fire

In September 2011, there was a fire at the underground mine that provides coal for San Juan. In October 2011, SJCC indicated that mining operations could restart in April 2012.

PNM estimates that the current inventory of mined coal could supply the fuel requirements of San Juan for approximately eight and one-half months at forecasted consumption levels. Based on information we have received to date, TEP does not expect the mine fire to have a material effect on its financial condition, results of operations, or cash flows due to the inventories of previously mined coal available to supply San Juan. However, if the mine is shut down longer than currently anticipated, the owners of San Juan would need to consider alternatives for operating the unit, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time. TEP expects that any incremental fuel and purchased power costs would be recoverable from customers through the PPFAC, subject to ACC approval.

Claims Related to Four Corners Generating Station

On May 7, 2010, APS received a Notice of Intent to Sue from EarthJustice (the Notice), on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at the Four Corners Generating Station (Four Corners). The Notice alleges New Source Review-related violations and New Source Performance Standards (NSPS) violations. Under the Clean Air Act, a citizens group is required to provide 60 days advance notice of its intent to file a lawsuit. Within that 60-day time period, the EPA may step in and file a lawsuit regarding the allegations. If the EPA does so, the citizens group is precluded from filing its own lawsuit, but it may still intervene in the EPA’s lawsuit, if it so desires. The 60-day period lapsed in early July 2010, and the EPA did not take any action. In September 2011, APS received a second Notice of Intent to Sue from EarthJustice, on behalf of the same environmental organizations (the Second Notice). The Second Notice is virtually identical to the May 2010 Notice and alleges violations of the New Source Review and NSPS programs.

In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. TEP is evaluating the lawsuit and cannot currently predict the outcome of the proceeding and, due to the general and non-specific nature of the claim and the indeterminate scope and nature of the injunctive relief sought, an estimate of the range of loss cannot be determined at this time.

TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities.

Mine Closure Reclamation at Generating Stations Not Operated by TEP

TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of these mines. TEP’s share of the reclamation costs for coal supply agreements expiring in 2016 through 2019 is approximately $26 million. TEP recognizes this cost over the remaining terms of these coal supply agreements and had recorded liabilities of $13 million at September 30, 2011, and $11 million at December 31, 2010.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreement terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.

TEP’s PPFAC allows TEP to pass through most fuel costs (including final reclamation costs) to customers. Therefore, TEP classifies these costs as a regulatory asset. TEP will increase the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and recover the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.

Tucson to Nogales Transmission Line

TEP and UNS Electric are parties to a project development agreement for the joint construction of an approximately 60-mile transmission line from Tucson to Nogales, Arizona. UNS Electric’s participation in this project was initiated in response to an order by the ACC to improve the reliability of electric service in Nogales. That order was issued before UniSource Energy purchased the electric system in Nogales and surrounding Santa Cruz County from Citizens Utilities in August 2003.

In 2002, the ACC authorized construction of the proposed 345-kV line along a route identified as the Western Corridor subject to a number of conditions, including the issuance of all required permits from state and federal agencies. The U.S. Forest Service subsequently expressed its preference for a different route in its final Environmental Impact Statement for the project. TEP and UNS Electric are considering options for the project, including potential new routes. If a decision is made to pursue an alternative route, approvals will be needed from the ACC, the Department of Energy, U.S. Forest Service, Bureau of Land Management, and the International Boundary and Water Commission. As of September 30, 2011 and December 31, 2010, TEP had capitalized $11 million related to the project, including $2 million to secure land and land rights. If TEP does not receive the required approvals or abandons the project, TEP believes cost recovery is probable for prudent and reasonably incurred costs related to the project as a consequence of the ACC’s requirement for a second transmission line serving the Nogales, Arizona area.

PROPOSED ENVIRONMENTAL MATTERS

TEP’s generating facilities are subject to Environmental Protection Agency (EPA) limits on the amount of sulfur dioxide (SO₂), nitrogen oxide (NOx) and other emissions released into the atmosphere. TEP may incur additional costs to comply with future changes in federal and state environmental laws, regulations and permit requirements at its electric generating facilities. Compliance with these changes may reduce operating efficiency.

Hazardous Air Pollutant Requirements

The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. The EPA is required to develop rules establishing standards for the control of emissions of mercury and other hazardous air pollutants from electric generating units and to issue final rules by November 2011.

The EPA issued its proposed rule in March 2011. Depending on the terms of the EPA’s final rule, emission controls may be required at some or all of TEP’s coal-fired units by 2014 or later. Costs and other details regarding TEP’s compliance cannot be determined until the rule is finalized.

Navajo

Based on the EPA’s proposed standards, mercury and particulate emission control equipment may be required at Navajo by 2015. TEP’s share of the estimated capital cost of this equipment is less than $1 million for mercury control and approximately $43 million if the installation of baghouses to control particulates is necessary.

Springerville

Based on the EPA’s proposed standards, mercury emission control equipment may be required at Springerville by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is approximately $5 million. The annual operating cost associated with the mercury emission control equipment is expected to be approximately $3 million.

San Juan

Current emission controls at San Juan are expected to be adequate to achieve compliance with the EPA’s proposed federal standards.

Sundt

TEP does not anticipate the proposed EPA rule will have a material capital impact on Sundt Unit 4.

Four Corners

TEP is analyzing the potential effect of the proposed EPA rule on Four Corners.

Regional Haze Rules

The EPA’s regional haze rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas and to submit a state implementation plan to the EPA for approval. Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions. The EPA therefore oversees regional haze planning for these plants.

Compliance with the EPA’s BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations and other business considerations could jeopardize the economic viability of the San Juan, Four Corners and Navajo plants or the ability of individual participants to meet their obligations and maintain participation in these plants. TEP cannot predict the ultimate outcome of these matters.

San Juan

In August 2011, EPA Region VI issued a Federal Implementation Plan (FIP) establishing new emission limits for NOx, SO₂ and sulfuric acid emissions at the San Juan Generating Station. The FIP requires the installation of Selective Catalytic Reduction (SCR) technology with sorbent injection on all four units within five years to reduce NOx and control sulfuric acid emissions. Based on two recent cost analyses commissioned by PNM, TEP’s share of the cost to install SCR with sorbent injection is estimated to be between $155 million and $202 million.

In September 2011, PNM filed a petition to review the EPA FIP with the 10th Circuit Court of Appeals challenging the EPA’s cost analysis used to determine the BART, the visibility analysis used to justify SCRs, and various other legal aspects of the order. Also in September 2011, PNM filed with the EPA a request to stay the five-year installation timeframe ordered by the FIP until the 10th Circuit has had time to consider and rule on the petition to review. PNM filed a Petition for Reconsideration of the rule and a Request to Stay the effective date of the final BART FIP under the CAA with the EPA in October 2011. Neither the Petition in the 10^th Circuit, nor the Petition for Reconsideration by the EPA delays the implementation timeframe unless a stay is granted.  WildEarth Guardians filed a separate appeal against the EPA challenging the five-year, rather than three-year, implementation schedule.  PNM was granted leave to intervene in that appeal. WildEarth Guardians, Dine Citizens against Ruining our Environment, National Parks Conservation Association, New Energy Economy, San Juan Citizens Alliance and Sierra Club sought, and were granted leave to intervene in PNM’s petition to review in the 10^th Circuit. Additionally, in October 2011, Governor Susana Martinez of New Mexico and the New Mexico Environment Department filed a Petition for Review of the EPA’s final FIP determination in the 10^th Circuit and a Petition for Reconsideration of the rule with the EPA.

Four Corners

In February 2011, the EPA supplemented the proposed FIP for the BART at Four Corners that would require the installation of SCR on Units 4 and 5. TEP’s estimated share of the capital costs to install SCR is approximately $35 million. Once the EPA finalizes the BART rule for Four Corners, the plant’s participants would have until 2018 to achieve compliance.

Navajo

The EPA is expected to issue a proposed rule establishing the BART for Navajo following the consideration of a report being commissioned by the Department of Interior. The report will address potential energy, environmental and economic issues associated with regional haze rule compliance at Navajo. That report is due in December 2011. A final BART rule is expected in 2012. If the EPA determines that SCR is required at Navajo, the capital cost impact to TEP is estimated to be $42 million. In addition, the installation of SCR at Navajo could increase the plant’s particulate emissions, necessitating the installation of baghouses. If baghouses are required, TEP’s estimated share of the capital costs is approximately $43 million. The cost of required pollution controls will not be known until final determinations are made by the regulatory agencies. TEP anticipates that if the EPA finalizes a BART rule for Navajo that requires SCR, the owners would have five years to achieve compliance.