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Commitments Contingencies and Proposed Environmental Matters
 6 Months Ended
Jun. 30, 2011
Commitments Contingencies and Proposed Environmental Matters [Abstract]  
COMMITMENTS, CONTINGENCIES AND PROPOSED ENVIRONMENTAL MATTERS
NOTE 6. COMMITMENTS, CONTINGENCIES AND PROPOSED ENVIRONMENTAL MATTERS
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  
Purchased Power(2)
    1       5       1       1       1       10       19  
Solar Equipment(3)
    11       11       11       —       —       —       33  
 
                                         
Total
  $ 46     $ 56     $ 26     $ 15     $ 1     $ 10     $ 154  
 
                                         
     
(1)   TEP executed a new coal supply agreement and amended an existing coal supply agreement in March 2011, incurring minimum purchase obligations.
 
(2)   Purchased Power includes contracts that will settle in June through September 2012 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 June 30, 2011. Additionally, Purchased Power includes one long-term Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation on March 31, 2011. TEP is obligated to purchase 100% of the output of this facility. The table above includes estimated future payments based on expected power deliveries under this contract 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.
 
(3)   TEP has a commitment to purchase 9 MW of photovoltaic equipment, subject to ACC approval, between July 1, 2011 and December 31, 2013.
UNS ELECTRIC COMMITMENTS
In 2011, UNS Electric entered into new long-term, forward power purchase commitments in addition to those reported in our 2010 Annual Report on Form 10-K. These contracts will settle in January through December of 2012. Certain of these contracts are at a fixed price per MWh and others are indexed to natural gas prices. UNS Electric’s estimated 2012 minimum payment obligation for these purchases is $6 million based on projected market prices as of June 30, 2011.
UNISOURCE ENERGY COMMITMENTS
UniSource Energy is constructing a new headquarters building in downtown Tucson with expected completion in November 2011. UniSource Energy has spent $53 million for construction of the building and has a remaining commitment of $12 million at June 30, 2011. Additionally, UniSource Energy has a commitment of $5 million for required tenant improvements, furniture, fixtures and equipment.
TEP CONTINGENCIES
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 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. TEP has not recognized income related to the $11 million refund pending resolution of the dispute.
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 if TEP had paid for 30 MW of transmission from February 1, 2006, through the settlement date, including interest. Under the PPFAC mechanism, TEP would be allowed to recover $2 million of this additional transmission expense from its customers. Additionally, TEP will enter into two new firm transmission capacity agreements under El Paso’s Open Access Transmission Tariff (OATT) for 40 MW. Finally, El Paso will withdraw its appeal before the United States Court of Appeals District of Columbia Circuit, and TEP will withdraw its complaint before the Arizona District of the United States District Court.
The settlement agreement was filed with the FERC in June 2011, and will become 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 will purchase the output of the Macho Springs facility under a 20-year PPA which is expected to begin when Macho Springs becomes operational later this year and which is not contingent upon either aforementioned settlement.
If the settlement agreements are both accepted by the FERC without modification or condition and not subsequently appealed, TEP would recognize a pre-tax gain of approximately $8 million. We anticipate that the FERC will make a decision on the settlements prior to year-end 2011.
If the FERC does not approve the settlement agreements and El Paso were to prevail in its appeal before the United States Court of Appeals for the District of Columbia Circuit, TEP would be required to refund the $11 million received from El Paso plus interest, and to pay for transmission service under El Paso’s OATT from October 2008 through the date of the decision. For the period October 2008 to June 30, 2011, this additional transmission expense would be approximately $12 million. However, under the PPFAC mechanism, TEP would be allowed to recover $10 million of this additional transmission expense from its retail customers.
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; 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 alleges, 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 September 2010, the case was referred to the District Court’s mediation program to assist with settlement negotiations, which are currently ongoing.
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 cannot predict whether the lawsuit will be refiled 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 at this time.
SJCC, the coal supplier to San Juan, through leases with the federal government and the State of New Mexico, owns coal interests with respect to an underground mine that supplies coal to San Juan. Certain gas producers have oil and gas leases with the federal government, the State of New Mexico and private parties in the area of the underground mine. These gas producers allege that SJCC’s underground coal mining operations have or will interfere with their gas production and will reduce the amount of natural gas that they would otherwise be entitled to recover. SJCC has compensated certain gas producers for any remaining gas production from a well when it was determined that mining activity was close enough to warrant plugging and abandoning the well. These settlements, however, do not resolve all potential claims by gas producers in the underground mine 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 Generation Station, and is liable for its share of any resulting liabilities.
Mine Closure Reclamation at Generating Stations Not Operated by TEP
TEP currently pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. It is probable that TEP will have to pay a portion of final reclamation costs upon closure of these mines. TEP’s share of the reclamation costs at the expiration dates of the coal supply agreements in 2016 through 2019 is approximately $26 million. TEP recognizes this cost over the remaining terms of the coal supply agreements and had recorded liabilities of $12 million at June 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 recovers 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 approved the location and 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 June 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 existing 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. Whether emission controls are required at a particular unit, the level of control required, and the cost to achieve that level of control will not be known until the rule has been promulgated.
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
The co-owners of San Juan installed new pollution control equipment at San Juan Units 1 and 2 in 2008 and 2009. These controls are expected to be adequate to achieve compliance with the EPA’s proposed federal standards.
Other Coal-Fired Units
TEP is analyzing the potential impacts of the proposed EPA rule on the Four Corners and Sundt generating facilities.
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.
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.
Navajo and Four Corners are located on the Navajo Indian Reservation and therefore are not subject to state regulatory jurisdictions.
San Juan
In December 2010, the EPA proposed a federal implementation plan under the Clean Air Act addressing, among other things, regional haze requirements for San Juan. The EPA plan proposes that the BART for nitrogen oxides at San Juan is a technology known as selective catalytic reduction (SCR). The EPA’s proposal gives the San Juan participants three years from the date of the final rule to achieve compliance. PNM, the operator of San Juan, has challenged the EPA’s proposal based on its own analysis which concludes that SCR is not the BART for that plant. A final federal implementation plan is expected in August 2011.
TEP’s share of capital expenditures related to the installation of SCR technology over a five-year period, at San Juan, is estimated to be $155 million to $202 million. This estimated range is based on two cost analyses commissioned by PNM. The three-year installation proposed by the EPA could increase the cost of compliance. Adding this technology to San Juan would increase operating costs at the generating station.
In February 2011, the New Mexico Environment Department (NMED) filed its proposed regional haze implementation plan with the New Mexico Environmental Improvement Board (EIB). The plan proposes that the BART for nitrogen oxides at San Juan is the installation of selective non-catalytic reduction (SNCR). TEP’s share of the capital costs related to the installation of SNCR is estimated to be $17 million. The NMED’s plan gives the San Juan participants five years to achieve compliance.
In June 2011, the EIB adopted the NMED state implementation plan and submitted it to the EPA for approval. TEP cannot predict whether or how the EPA will act on the state or final federal implementation plan.
Four Corners
In February 2011, the EPA supplemented the proposed federal implementation plan 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 by the end of the year, with a final rule in 2012. SRP, on behalf of the Navajo owners, is participating in an EPA-sanctioned stakeholder process designed to determine the BART for Navajo. 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 the installation of baghouses is necessary at Navajo, TEP’s estimated share of the capital costs is approximately $43 million. The exact level and 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 .