ITEM 1. BUSINESS
THE COMPANY
Overview
PNMR is an investor-owned holding company of energy and energy-related businesses. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNM is a public utility with regulated operations primarily engaged in the generation, transmission, and distribution of electricity and, through January 29, 2009, the transmission and distribution and sale of natural gas. TNMP is a regulated utility providing regulated transmission and distribution services in Texas. First Choice is a competitive REP operating in Texas. PNMR owns 50% of Optim Energy, which is focused on unregulated electric operations, principally within the areas of Texas covered by ERCOT, including the development, operation, and ownership of diverse generation assets and wholesale marketing. As described below and in Note 22, PNMR’s investment in Optim Energy was reduced to zero at December 31, 2010 due to the determination that the investment was fully impaired.
On January 12, 2008, PNM entered into an agreement to sell its natural gas operations, which comprised the PNM Gas segment, to NMGC, a subsidiary of Continental, for $620.0 million in cash, subject to adjustment based on the level of working capital at closing. Financial information regarding PNM’s gas operations, which are reflected as discontinued operations herein, is presented in Note 23. In a separate transaction conditioned upon the sale of the natural gas operations, PNMR proposed to acquire CRHC, Continental’s regulated Texas electric transmission and distribution business, for $202.5 million in cash. On July 22, 2008, PNMR and Continental agreed to terminate the agreement for the acquisition of CRHC. The termination agreement provided that Continental pay PNMR $15.0 million upon the closing of the PNM Gas transaction. PNMR completed the sale of its gas operations on January 30, 2009. PNM used proceeds from the sale to retire short-term debt and paid a dividend of $220.0 million to PNMR. The remaining proceeds were used to pay income taxes on the gain from the sale. PNMR used the dividend from PNM and the $15.0 million from Continental to retire debt.
PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM. PNMR was incorporated in the State of New Mexico in 2000.
Other Information
These filings for PNMR, PNM, and TNMP include disclosures for PNMR, PNM, and TNMP. For discussion purposes, this report will use the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such. A reference to “MD&A” in this report refers to Part II, Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report. A reference to a “Note” refers to the accompanying Notes to Consolidated Financial Statements.
Financial information relating to amounts of sales, revenue, net income, and total assets of reportable segments is contained in MD&A and Note 3.
WEBSITES
The PNMR website, www.pnmresources.com, is an important source of Company information and PNMR encourages investors, analysts, and other interested parties to visit the website frequently. PNMR keeps the site updated and routinely posts new or updated information for public access. PNMR encourages analysts, investors, and other interested parties to register on the website to automatically receive Company information by e-mail. Once registered, participants can choose from a menu to automatically receive requested information, including news releases, notices of webcasts, and filings with the SEC. Participants can unsubscribe at any time and will not receive information that was not requested.
PNMR’s Internet address is http://www.pnmresources.com; PNM’s Internet address is http://www.pnm.com; TNMP’s Internet address is http://www.tnpe.com. The contents of these websites are not a part of this Form 10-K. The filings of PNMR, PNM, and TNMP with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports, filed or furnished pursuant to Section
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13(a) or 15(d) of the Securities and Exchange Act of 1934, are accessible free of charge at http://www.pnmresources.com as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports are also available upon request in print from PNMR free of charge. Additionally, PNMR’s Corporate Governance Principles, code of ethics (Do the Right Thing-Principles of Business Conduct), and charters of its Audit and Ethics Committee, Nominating and Governance Committee Compensation and Human Resources Committee, and Finance Committee are available at http://www.pnmresources.com/investors/governance.cfm and such information is available in print, without charge, to any shareholder who requests it. The Company will post amendments to or waivers from its code of ethics (to the extent applicable to the Company’s executive officers and directors) at this location on its website.
OPERATIONS
Regulated Operations
PNM Electric
PNM Electric is an electric utility that is primarily focused on providing service to its rate-regulated customers. PNM Electric’s operations consist of generation, transmission, and distribution of electricity for retail electric customers in New Mexico subject to the jurisdiction of the NMPRC and for wholesale customers in New Mexico and Arizona subject to the jurisdiction of FERC. PNM Electric also provides transmission services to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. PNM Electric provides retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of southern New Mexico. PNM Electric owns or leases transmission lines, interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. The largest retail electric customer served by PNM Electric accounted for 2.9% of PNM Electric’s revenues for the year ended December 31, 2010. PNM was incorporated in the State of New Mexico in 1917.
Customer rates for retail electric service are set by the NMPRC. In February 2007, PNM filed a general rate case with the NMPRC for all of its New Mexico retail customers except those formerly served by TNMP. Following NMPRC approvals, PNM implemented new electric rates reflecting an annual $34.4 million rate increase in May 2008 and, beginning in June 2008, an Emergency FPPAC through which changes in the cost of fuel and purchased power, above or below the costs included in base rates, are passed through to customers on a monthly basis. In September 2008, PNM filed its 2008 Electric Rate Case requesting an increase in electric rates for all of its New Mexico retail customers except those formerly served by TNMP and a more traditional FPPAC. In June 2009, the NMPRC approved a stipulation resolving all issues in the 2008 Electric Rate Case, including that the Luna and Lordsburg generating plants, the Valencia PPA, and the portion of PVNGS Unit 2 previously owned by another subsidiary of PNMR and leased to PNM, be included as additional sources of power in determining rates. The approved stipulation allowed for an increase in annual non-fuel revenues of $77.1 million with, 65% being implemented July 1, 2009 and the remainder being implemented April 1, 2010. As an offset to the non-fuel revenue increase, PNM implemented a credit to customers totaling $26.3 million, representing the amount of revenues from past sales of SO2 allowances. This amount is being credited to customers over 21 months beginning July 1, 2009.
PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represents a 22% increase for PNM North and a 20% increase for PNM South. On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would resolve all issues in the 2010 Electric Rate Case and provide a rate path for PNM through 2013. Other parties have filed statements opposing the stipulation. This stipulation, which reflects some aspects of a future test year, is subject to approval of the NMPRC. The stipulation would allow PNM to increase rates by $45.0 million beginning May 15, 2011 and by an additional $40.0 million beginning January 1, 2012. The proposed rates are designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers, who are not currently covered by a FPPAC, would be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1 2012. PNM would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and
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December 31, 2012. PNM’s next general rate adjustment could not go into effect before January 1, 2014, except that PNM can file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. If the stipulation is approved by the NMPRC, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account, which would be recorded as a regulatory disallowance. On February 22, 2011, the NMPRC issued an order denying a motion that requested the NMPRC, instead of the Hearing Examiner, conduct the hearing on the stipulation. PNM agreed to extend the suspension period for an additional three months to November 10, 2011. The Hearing Examiner has established a procedural schedule that includes a hearing on the stipulation beginning on May 9, 2011. See Note 17. PNM is unable to predict the outcome of this proceeding.
Weather-normalized retail electric loads increased by 1.4% in 2010. PNM Electric’s system peak demands for its retail and firm requirements customers in the summer and the winter for the last three years are shown in the following table:
System Peak Demands
PNM holds long-term, non-exclusive franchise agreements for its electric retail operations, with varying expiration dates. These franchise agreements allow PNM to access public rights-of-way for placement of PNM’s electric facilities. Franchise agreements have expired in some areas PNM serves, including Albuquerque, Santa Fe, and Rio Rancho. PNM remains obligated under New Mexico state law to provide service to customers in these franchise areas despite the absence of an effective franchise agreement, so the expirations should not have a material adverse impact on PNM’s business. The Albuquerque, Rio Rancho, and Santa Fe metropolitan areas accounted for 45.3%, 9.8%, and 8.9% of PNM Electric’s 2010 revenues and no other franchise area represents more than 5%. Although PNM does not collect or pay franchise fees in some areas it serves, PNM continues to collect and pay franchise fees in certain parts of its service territory, including Albuquerque, Santa Fe, and Rio Rancho.
PNM Electric owns or leases 3,188 circuit miles of electric transmission lines, interconnected with other utilities in New Mexico, Arizona, Colorado, Texas, and Utah. Due to rapid load growth in PNM Electric’s service territory in recent years and the lack of transmission development, most of the capacity on this transmission system is fully committed during peak hours and there is very little or no additional access available on a firm commitment basis. These factors result in physical constraints on the system and limit the ability to wheel power into PNM Electric’s service area from outside of New Mexico.
PNM Electric includes wholesale activities that consist of the generation and sale of electricity into the wholesale market. PNMR completed its undertaking to move away from certain wholesale merchant activities within PNM Electric by the sale of certain wholesale power, natural gas and transmission contracts (see Note 8) and NMPRC approval to include the Luna and Lordsburg assets in retail rates (see Note 17). Because PNM’s share of Unit 3 at the PVNGS is permanently excluded from retail rates, it can remain within PNM and its power can continue to be sold on the wholesale market. In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW, through December 31, 2010. In late 2010 and early 2011, PNM entered into contracts for the sale of power from PVNGS Unit 3 through December 31, 2011; however, PNM expects the margins to be significantly lower, due to lower existing market prices than those achieved in the tolling agreement in 2008. PNM Electric also engages in activities to optimize its existing jurisdictional assets and long-term purchase power agreements through spot market, hour ahead, day ahead, week ahead, and other sales of any excess generation not required to fulfill PNM Electric’s retail load and contractual commitments. Revenues from these sales are credited to retail customers through the FPPAC.
PNM Electric has entered into various firm-requirements wholesale electric sales contracts. These contracts contain fixed capacity charges in addition to energy charges. Capacity charges are fixed monthly payments for a commitment of resources to service the contract requirements. Energy charges are payments based on the amount of electricity delivered to the customer intended to compensate PNM Electric for its variable costs incurred to provide the energy. PNM Electric’s firm-requirements demand was 107 MW in 2010, and is expected, based solely
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on existing contracts, to be 106 MW in 2011, 109 MW in 2012, and 111 MW in 2013. No firm-requirements customer of PNM Electric accounted for more than 1.9% of the PNM Electric’s revenues for the year ended December 31, 2010.
TNMP Electric
TNMP Electric consists of all the operations of TNMP. TNMP is a regulated utility operating in Texas. TNMP’s predecessor was organized in 1925 and TNMP is incorporated in the State of Texas.
In Texas, TNMP Electric provides regulated transmission and distribution services under the provisions of TECA and the Texas Public Utility Regulatory Act. TNMP Electric serves a market of small-to-medium-sized communities most of which have populations of less than 50,000. In most areas that TNMP Electric serves, it is the exclusive provider of transmission and distribution services.
TNMP Electric’s Texas territory consists of three non-contiguous areas. One portion of this territory extends from Lewisville, which is approximately 10 miles north of the Dallas-Fort Worth International Airport, eastward to municipalities near the Red River, and to communities north, west and south of Fort Worth. The second portion of its territory includes the area along the Texas Gulf Coast between Houston and Galveston, and the third portion includes areas of far west Texas between Midland and El Paso. TNMP Electric’s Texas operations lie entirely within the ERCOT region. ERCOT is the independent system operator that is responsible for maintaining reliable operations for the bulk electric power supply system in the ERCOT region, which is located entirely within Texas. See Rates and Regulation below for more information about ERCOT.
TNMP Electric provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service within TNMP Electric’s Texas service area. As of December 31, 2010, 81 active REPs served customers that receive transmission and distribution services from TNMP Electric. First Choice, TNMP Electric’s affiliated REP, was TNMP Electric’s second largest customer and accounted for 18.4% of TNMP’s revenues for the year ended December 31, 2010. Revenues of TNMP’s other large customers accounted for 19.1% and 13.1% of revenues. No other customers accounted for more than 10% of revenues.
In August 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues, which would be TNMP’s first increase in rates since 2002. Hurricane Ike, which struck the Texas Gulf Coast on September 13, 2008, caused extensive damage to the city of Galveston and the surrounding communities. In March 2009, TNMP filed supplemental testimony, requesting an additional revenue increase of $15.7 million annually relating to costs incurred during Hurricane Ike and anticipated increased financing costs. In June 2009, TNMP and the other parties in the rate case reached a unanimous settlement that was approved by the PUCT in August 2009. The settlement permitted TNMP to increase revenues by $12.7 million annually beginning September 1, 2009. This increase reflects interest and other costs associated with its March 2009 debt refinancing and the settlement adjusts the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The rate increase includes recovery of $17.6 million of Hurricane Ike restoration costs plus carrying costs over five years. The PUCT approved an interim adjustment to TNMP’s transmission rates of $5.5 million on May 14, 2010. On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues. On January 27, 2011, the PUCT approved a stipulation among the parties to the case that settles the case and provides for a revenue increase of $10.25 million beginning February 1, 2011.
TNMP holds long-term, non-exclusive franchise agreements for its electric transmission and distribution services with varying expiration dates, including some that have expired. TNMP intends to negotiate and execute new or amended franchise agreements with municipalities where the agreements have expired or will be expiring. Since TNMP Electric is the exclusive provider of transmission and distribution services in most areas that it serves, the need to renew or renegotiate franchise agreements should not have a material adverse impact on TNMP’s business. TNMP also earns revenues from service provided to facilities in its service area that lie outside the territorial jurisdiction of the municipalities with which TNMP has franchise agreements.
PNM Gas
PNM Gas distributed natural gas to most of the large communities in New Mexico, including Albuquerque and Santa Fe, through January 29, 2009 under rates that were subject to traditional rate regulation by the NMPRC.
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On January 12, 2008, PNM entered into an agreement to sell PNM Gas. On January 30, 2009, PNM completed the sale. See Note 2 and Note 23.
PNM Gas had a customer base that included both sales-service customers and transportation-service customers. Sales-service customers purchased natural gas and received transportation and delivery services from PNM Gas for which PNM Gas received both cost-of-gas and cost-of-service revenues. Cost-of-gas revenues collected from its sales-service customers were recovered in accordance with NMPRC regulations through the PNM Gas PGAC and represented a pass-through of the cost of natural gas to the customer. As a result, increases or decreases in gas revenues resulting from wholesale gas price fluctuations did not impact gross margin. Additionally, PNM Gas made occasional gas sales to off-system sales customers. Off-system sales deliveries generally occurred at pipeline interconnections with the PNM Gas system and profits were shared between PNM Gas and its regulated customers on a 30%/70% basis.
Competitive Businesses
First Choice
First Choice is a certified REP operating in ERCOT, which provides electricity to residential, small commercial and governmental customers. First Choice’s services include acquiring retail customers, setting up retail accounts, handling customer inquiries and complaints, and acting as a liaison between the transmission and distribution companies and retail customers. First Choice focuses its competitive customer acquisition efforts in the major Texas metropolitan areas that are open to electric choice within ERCOT, including Dallas-Fort Worth, Houston, Corpus Christi, and McAllen-Harlingen. Due to the competitive nature of the Texas market, First Choice, similar to other REPs, experiences significant turnover in its customer base. There is no provision under Texas regulation that requires customers to pay their previous REP before obtaining service from another REP. In 2008 and early 2009, this was exacerbated by the impacts of Hurricane Ike and depressed economic conditions, which resulted in significant increases in the levels of uncollectible accounts and bad debt expense. During late 2009 and continuing through 2010, the levels of uncollectible accounts and bad debt expense at First Choice have been significantly reduced. Although First Choice is regulated in certain respects by the PUCT under ERCOT, its business is not subject to traditional rate of return regulation.
First Choice’s load fluctuates continuously due to, among other things, customer additions and losses, changes in customer usage, and seasonality of weather. First Choice continually monitors and revises its load forecast to account for changing competitive customer loads. First Choice develops short-term load forecasts to identify short-term load surpluses and shortages, and to ensure that hedges are in place to cover forecasted sales. To the extent these short-term load forecasts identify shortages, First Choice covers shortages through short-term power purchases or through purchases on the ERCOT balancing market.
First Choice experiences increased sales and operating revenues during the summer months as a result of increased air conditioner usage in hot weather. In 2010, approximately 32% of First Choice’s consolidated annual revenues were recorded in June, July, and August.
First Choice is exposed to market risk to the extent that its retail rates or cost of supply fluctuates with market prices. Additionally, fluctuations in First Choice retail load requirements that are greater than anticipated may subject First Choice to market risk. First Choice’s basic strategy is to minimize its exposure to fluctuations in market energy prices by matching fixed price sales contracts with fixed price supply.
Optim Energy
In January 2007, PNMR and ECJV created EnergyCo to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. In February 2009, the name of EnergyCo was changed to Optim Energy and references to Optim Energy herein encompass periods prior to the name change. ECJV is a wholly owned subsidiary of Cascade, which is a large PNMR shareholder. PNMR and ECJV each have a 50 percent ownership interest in Optim Energy, a limited liability company. Optim Energy’s electric generating resources consist of the Twin Oaks plant, which was acquired from PNMR in 2007, the Altura Cogen plant, a cogeneration electric and steam generating plant that was purchased in 2007, and 50 percent of the Cedar Bayou 4 generating unit, construction of which was completed in June 2009. Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit.
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PNMR accounts for its 50 percent ownership interest in Optim Energy using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over Optim Energy and its operations. Through December 31, 2010, PNMR recorded its percentage share of earnings or losses of Optim Energy and carried its investment at cost, adjusted for its share of undistributed earnings or losses. Accordingly, Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses. See below and Note 22.
Optim Energy’s strategy had been focused on expanding unregulated operations in one of the nation’s growing power markets. Optim Energy’s business consisted of development, operation, and ownership of diverse generation assets and wholesale marketing to optimize its assets. In 2009, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. The adverse market conditions continued throughout 2010.
In response to those adverse conditions, Optim Energy changed its strategy and near-term focus in October 2009. Optim Energy is currently focused on utilizing cash flow from operations to reduce debt and optimizing its current generation assets as a stand-alone independent power producer. Optim Energy’s goal is to optimize its performance under current market conditions with the expectation of being able to take advantage of any economic recovery in the power and gas markets over the next several years.
In addition to the continuing adverse market conditions evidenced by low power and natural gas prices, recently reported sales of electric generating resources within the ERCOT market have been transacted at prices (per KW of generating capacity) that are substantially below the amounts recorded for electric generating plants underlying PNMR’s investment in Optim Energy. Under GAAP, these factors are indicators of impairment that required impairment analyses to be performed as of December 31, 2010, both by Optim Energy of its electric generating plants and by PNMR of its investment in Optim Energy. GAAP requires that Optim Energy perform the impairment analysis of its electric generating plants using forecasts of future cash flows on an undiscounted basis in order to determine its investments are recoverable. That analysis indicates Optim Energy will be able to recover its investments in electric generating assets based on its estimates of undiscounted future cash flows from operating those plants over their expected useful lives. Therefore, Optim Energy did not record any impairment loss related to its electric generating plants at December 31, 2010. However, GAAP requires that PNMR base the impairment analysis of its investment in Optim Energy on fair value. To the extent forecasts of future cash flows are used in the determination of fair value, the cash flows must be on a discounted basis that reflects the time value of money relative to those cash flows. PNMR’s analysis of the discounted cash flows of Optim Energy, recent sales of comparable generating assets, and the preliminary discussions regarding strategic alternatives for Optim Energy discussed in Strategy below indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax loss of $188.2 million ($113.7 million after-tax), which is reflected within Other Income and Deductions on the Consolidated Statements of Earnings (Loss) of PNMR.
Strategy
As a result of the adverse market conditions experienced by Optim Energy described above, PNMR (in collaboration with Optim Energy and ECJV) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. Discussions regarding various alternatives have been held with several potential parties. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize gains or additional impairments based on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.
Corporate and Other
PNMR Services Company provides corporate services through shared services agreements to PNMR, to all of PNMR’s business units, including First Choice, PNM, and TNMP, and to Optim Energy. These services are charged and billed on a monthly basis to the business units. Billings are at cost, except for Optim Energy, which includes a profit element. PNMR Services Company is included in the Corporate and Other segment.
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SOURCES OF POWER
PNMR
First Choice buys electricity and enters into hedging arrangements to purchase quantities of power to match the supply obligations to customers that are under fixed price contracts. In the long term, power is purchased in the over-the-counter market or using futures. In the short term, the hedges are adjusted to load forecast changes by buying and selling power in the over-the-counter market or ERCOT day-ahead market.
PNM
As of December 31, 2010, the total net generation capacity of facilities owned or leased by PNM was 2,331 MW. See Item 2. Properties. PNM also obtains power under long-term PPAs as described below. PNM Electric’s total generation capacity from these sources is:
Owned and Leased
SJGS’ equivalent availability was 73.5% and 84.9% for the years ended December 31, 2010 and 2009. Four Corners’ equivalent availability was 75.3% and 87.5% for the years ended December 31, 2010 and 2009. In 2010, PVNGS achieved its best generation year ever, producing over 31 million megawatt-hours, with an overall station capacity factor of 90.5%. The generation from each PVNGS operating unit directly reflects the station’s currently effective 18-month refueling cycle. In 2010, PVNGS refueled both Unit 1 and Unit 3. As part of the 2010 refueling outages, PVNGS installed new reactor vessel closure heads and simplified head assembly modifications. These projects are designed to provide safety benefits, eliminate costly inspections and reduce the duration of future outages. SJGS is operated by PNM. Four Corners and PVNGS are operated by APS.
PNM’s Lordsburg plant was built to serve wholesale customers and other sales rather than New Mexico retail customers. In 2004, a subsidiary of PNMR purchased a one-third interest in Luna, a 570 MW, partially constructed, natural gas-fired power plant near Deming in southern New Mexico. In 2005, the one-third interest in Luna was transferred to PNM. These plants became included in retail rates beginning in July 2009 pursuant to the 2008 Electric Rate Case. See Note 17.
In 2007, PNM Electric completed the conversion of Afton to a combined cycle plant. The NMPRC approved bringing Afton into retail rates and currently 50% of Afton’s capacity is designated to serve customers formerly served by TNMP and the other 50% is designated to serve PNM Electric’s other retail customers.
PNM leases portions of PVNGS and the lease payments are recovered through retail rates approved by the NMPRC. In July 2009, PNM acquired the ownership of a portion of PVNGS Unit 2 previously owned by another PNMR subsidiary and leased to PNM, including it in rates charged to retail customers on an ownership basis. See Item 2. Properties, Note 7, and Note 17 for additional information.
In 1996, PNM entered into an operating lease agreement for the rights to all the output of the Delta gas-fired generating plant for 20 years. The plant received FERC approval for “exempt wholesale generator” status. The maximum dependable capacity under the lease is 132 MW. The gas turbine generating unit is operated by Delta and is located on PNM’s retired Person Generating Station site in Albuquerque. Primary fuel for the gas turbine generating unit is natural gas provided by wholesale gas purchases. In addition, the unit has the capability to utilize low sulfur fuel oil if natural gas is neither available nor cost effective.
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In April 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. A third-party built, owns, and operates the facility. PNM is the sole purchaser of the electricity generated. The term of the PPA is for 20 years beginning June 1, 2008. Valencia became included in retail rates charged to customers beginning with the 2008 Electric Rate Case. PNM has evaluated the accounting treatment of this arrangement and concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia. As the primary beneficiary, PNM consolidates the entity in its financial statements. Accordingly, the assets of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The 145 MW capacity of Valencia is reflected as owned in the above table. See Note 9 and Note 17.
Joint Projects
SJGS, PVNGS, and Four Corners are joint projects each owned or leased by several different utilities. Some participants in the joint projects are investor-owned utilities, while others are municipally or co-operatively owned. Furthermore, participants in SJGS and Four Corners may have varying percentage interests in different generating units within the project. The primary operating or participation agreements for the joint projects expire in 2017 for Four Corners, 2022 for SJGS, and 2027 for PVNGS. In addition, SJGS and Four Corners are coal-fired generating plants that obtain their coal requirements from mines near the plants. The agreements for coal supply expire in 2016 for Four Corners and 2017 for SJGS. Four Corners is situated on land under a lease from the Navajo Nation. APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest to 2041. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which occurred on February 15, 2011 and is awaiting final signature by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant which the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process. Portions of PNM’s interests in PVNGS Units 1 and 2 are through leases that expire in 2015 and 2016, but contain certain fixed-rate renewal and fair market value purchase options. Several of the participants in the joint projects are located in California. There are legislative and regulatory mandates in California that prohibit utilities from entering into new, or extending existing, arrangements for coal-fired generation. It is also possible that the participants in the joint projects have changed circumstances and objectives from those existing at the time of becoming participants. The status of the joint projects is further complicated by the uncertainty surrounding the form of potential legislation and/or regulation of GHG, CCBs and other air emissions, as well as the impacts of the costs of compliance and operational viability of all or certain units within the joint projects. It is unclear how these factors will enter into discussion and negotiations concerning the status of the joint projects as the expiration of basic operational agreements approaches and PNM can provide no assurance that its participation in the joint projects will continue in the manner that currently exists.
PPAs
In addition to generating its own power, PNM Electric purchases power in the open market under long-term PPAs. PNM also purchases power in the forward, day-ahead and real-time markets.
In 2002, PNM entered into an agreement with FPL to develop a 200 MW wind generation facility in New Mexico. PNM began receiving commercial power from the project in June 2003. FPL owns and operates the New Mexico Wind Energy Center, which consists of 136 wind-powered turbines on a site in eastern New Mexico. PNM has a contract to purchase all the power and RECs generated by the New Mexico Wind Energy Center for 25 years. In 2003, PNM received approval from the NMPRC for a voluntary tariff that allows PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from the New Mexico Wind Energy Center is used to service load under the voluntary tariff and as part of PNM’s electric supply mix for meeting retail load, as well as for meeting wholesale load.
In addition, PNM has a long-term PPA with SPS to purchase 100 MW of interruptible power through May 2011. See Owned and Leased above regarding the Valencia PPA.
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A summary of purchased power is as follows:
TNMP
TNMP provides only transmission and distribution services and does not sell power.
FUEL AND WATER SUPPLY
PNM
The percentages of PNM’s generation of electricity (on the basis of KWh) fueled by coal, nuclear fuel, and gas and oil, and the average costs to PNM of those fuels per MMBTU, during the past three years were as follows:
The generation mix for 2011 is expected to be 64.6% coal, 27.3% nuclear, 8.0% gas and oil, and 0.1% utility owned solar. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits, and the generally adequate supply of nuclear fuel, PNM believes that adequate sources of fuel are available for its generating stations into the foreseeable future. See Sources of Power - PNM - PPAs for information concerning the cost of purchased power.
Coal
See Note 16 for information about PNM’s coal supply.
Natural Gas
The natural gas used as fuel for the electric generating plants is procured on the open market and delivered by third party transportation providers and NMGC (PNM Gas prior to January 29, 2009) through its transportation facilities.
Nuclear Fuel
PNM is one of several participants in PVNGS. See Note 14. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have contracted for all of PVNGS’s requirements for uranium concentrates through 2011 and 95% of its requirements through 2017. A new contract is currently being negotiated that will cover PVNGS’s remaining requirements for uranium concentrates through 2017. The participants have also contracted for all of PVNGS’s conversion services through 2018, all of PVNGS’s enrichment services through 2020 and all of PVNGS’s fuel assembly fabrication services through 2016.
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The Nuclear Waste Policy Act of 1982 (“NWPA”) required the DOE to accept, transport, and dispose of spent nuclear fuel and high level waste generated by the nation’s nuclear power plants by 1998. The DOE’s obligations are reflected in a Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (“Standard Contract”) with each nuclear power plant. The DOE failed to begin accepting PVNGS’s spent nuclear fuel by 1998, and APS (on behalf of itself and the other PVNGS participants) filed a lawsuit for DOE’s breach of the PVNGS Standard Contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.2 million in damages to the PVNGS participants for costs incurred through December 2006. See Note 16.
The DOE had planned to meet its NWPA and Standard Contract disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In June 2008, DOE submitted its application to the NRC to authorize construction of the Yucca Mountain repository. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application. None of these lawsuits have been conclusively decided by the courts.
PVNGS has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in December 2047 (assuming the NRC approves APS’s request for renewed operating licenses). If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, the PVNGS participants will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
In addition to the spent fuel stored at PVNGS’s on-site ISFSI, PVNGS also generates certain types of low level radioactive waste that are stored on-site. Currently, the Class B and Class C waste (the higher radioactivity of the low level wastes) is stored on-site since industry access to a disposal site was eliminated several years ago. The NRC is considering regulations that would allow the industry to eliminate much of this waste by blending it with lower level Class A waste so that it can be disposed of at a facility such as the one PVNGS utilizes in Utah.
Water Supply
See Note 16 for information about PNM’s water supply.
RATES AND REGULATION
The items below describe certain of the more significant rate and regulatory matters that are relevant to the Company. See Notes 16 and 17 for a discussion of additional rate and regulatory matters.
PNMR
First Choice
First Choice is a member of ERCOT, the ISO responsible for maintaining reliable operations of the bulk electric power grid in the Texas deregulated electricity market. ERCOT does not operate a centrally dispatched pool and does not procure energy on behalf of its members other than to maintain the reliable operation of the transmission system. ERCOT also serves as a clearinghouse for procuring ancillary services and congestion revenue rights.
Members of ERCOT include independent REPs, investor owned utilities, municipals, cooperatives, independent generators, independent power marketers, and consumers. The electric market served by ERCOT operates under the reliability standards set by the North American Electric Reliability Council. The PUCT has primary jurisdictional authority over the electric market served by ERCOT and the reliability of electricity across Texas’ main interconnected power grid.
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First Choice provides energy to retail customers in ERCOT. As a result of the deregulated electricity market in Texas, there are no provisions for the specific recovery of fuel and purchased power costs by First Choice. The rates charged to customers are not regulated by the PUCT, but are negotiated by First Choice with each customer. As a result, purchased power costs will affect First Choice’s operating results.
PNM
Regulation
PNM is subject to the jurisdiction of the NMPRC with respect to its retail electric rates, service, accounting, issuances of securities, construction of major new generation, transmission, and distribution facilities and other matters regarding retail utility services provided in New Mexico. The NMPRC approved PNM implementing new electric rates reflecting a $34.4 million rate increase in May 2008 and also implementing an Emergency FPPAC in June 2008. In the 2008 Electric Rate Case, the NMPRC approved PNM implementing new electric rates reflecting an increase in annual non-fuel revenues of $77.1 million, of which 65% was implemented on July 1, 2009 and the remaining 35% was implemented on April 1, 2010. The NMPRC also approved a more traditional FPPAC. PNM and other parties to its 2010 Electric Rate Case have entered into a stipulation that, if approved by the NMPRC, would resolve all issues related to that case. FERC has jurisdiction over rates and other matters related to wholesale electric sales and cost recovery for a portion of PNM’s transmission network. In October 2010, PNM filed for an increase in transmission rates of $11.1 million annually, which is pending before FERC. See Note 17.
Use of Future Test Year
Senate Bill 477 (“SB 477”) was passed by the New Mexico legislature and became effective in June 2009. SB 477 is designed to promote more timely recovery of reasonable costs of providing utility service in two ways. First, SB 477 requires the NMPRC, when setting rates, to use the test period that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. The NMPRC is required to give due consideration that a future test period may be the one that best meets this requirement. A future test period is defined as a twelve month period beginning no later than the date a proposed rate change is expected to take effect. Traditionally, the NMPRC has used a historical test period, adjusted for known and measurable changes occurring within five to six months after the end of the test period, which reflects costs that could be up to two years old at the time new rates become effective. It is possible that NMPRC staff or intervenors could argue that continued use of a historical test period, adjusted for known and measurable changes, best meets the requirement. Second, SB 477 requires the NMPRC to include construction work in progress in rate base, without an offset for allowance for funds used during construction, for environmental improvement projects and generation and transmission projects for which a certificate of public convenience and necessity has been issued. This provision will allow utilities to collect costs as projects are being built rather than waiting until they are finished to include them in rate base, so long as the projects will be in service no later than two years after the filing date of the rate case.
The use of a future test year should help PNM to mitigate the adverse effects of regulatory lag, which is inherent when using a historical test year, by focusing on what costs are likely to be when new rates go into effect rather than what they were in the past. The mitigation of the adverse effects of regulatory lag should result in PNM’s earnings more closely approximating the rate of return allowed by the NMPRC. PNMR believes that achieving earnings that approximate its allowed rate of return is an important factor in attracting equity investors, as well as being considered by credit rating agencies and financial analysts. PNM currently expects it will access the credit and capital markets in order to finance at least a portion of the anticipated construction expenditures discussed in Capital Requirements under Liquidity and Capital Resources below. To the extent such financing includes the issuance of debt securities that are rated below investment grade, the debt would carry a higher interest rate than if the securities were investment grade. Those higher interest costs would then be included in requests for rate relief, placing additional upward pressure on rates charged to customers.
As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that are inherent in the forecasting process. PNM is required to forecast both operating and capital expenditures that necessitates reliance on many assumptions concerning future conditions. Among others, these would include assumptions about future economic conditions in PNM’s service territory, levels of employment, load growth and conservation, weather, usage patterns of customers, availability and technology regarding renewable energy sources, interest rates and other financing costs, access to capital markets, inflation, and impacts
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of regulatory actions. In the rate making process, PNM’s assumptions are subject to challenge by regulators and intervenors who may assert different interpretations or assumptions.
Renewable Portfolio Standard
The Renewable Energy Act of 2004 was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015, and 20% by 2020. The act provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities recovery of costs incurred consistent with approved procurement plans and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. PNM files required renewable energy plans with the NMPRC annually. PNM’s 2010 plan requests variances from certain aspects of the NMPRC requirements, which request is pending before the NMPRC. See Note 17.
TNMP
Regulation
In Texas, TNMP provides regulated transmission and distribution services and is subject to the jurisdiction of the PUCT and certain municipalities with respect to rates and service. TNMP is subject to traditional cost-of-service regulation in Texas. TNMP’s transmission and distribution activities in Texas are not subject to FERC regulation, because those activities occur solely within the ERCOT system of Texas.
In August 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues. TNMP amended its request by $15.7 million to include recovery of costs related to Hurricane Ike, as well as anticipated debt financing costs. In August 2009, the PUCT approved a settlement that permits TNMP to increase revenues by $12.7 million annually. This increase reflects interest and other costs associated with its March 2009 debt refinancing and adjusts the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The rate increase includes recovery of $17.6 million of Hurricane Ike restoration costs plus carrying costs over five years. The PUCT approved an interim adjustment to TNMP’s transmission rates of $5.5 million on May 14, 2010. On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues. On January 27, 2011, the PUCT approved a revenue increase of $10.25 million beginning February 1, 2011. See Note 17.
ENVIRONMENTAL MATTERS
Electric utilities are subject to stringent laws and regulations for protection of the environment by local, state, federal, and tribal authorities. In addition, PVNGS is subject to the jurisdiction of the NRC, which has the authority to issue permits and licenses and to regulate nuclear facilities in order to protect the health and safety of the public from radioactive hazards and to conduct environmental reviews pursuant to the National Environmental Policy Act. The liabilities under these laws and regulations can be material and, in some instances, may be imposed without regard to fault, or may be imposed for past acts, whether or not such acts were lawful at the time they occurred. See MD&A - Critical Accounting Policies for a discussion of applicable accounting policies and - Other Issues Facing the Company - Climate Change Issues for information on GHG. In addition, see Notes 16 and 18 for information related to the following matters, incorporated in this item by reference.
Note 16
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PVNGS Decommissioning Funding
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Nuclear Spent Fuel and Waste Disposal
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Environmental Matters under the caption “The Clean Air Act”
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Endangered Species Act
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Santa Fe Generating Station
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Environmental Matters under the caption “Coal Combustion Waste Disposal”
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Gila River Indian Reservation Superfund Site
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Note 18
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Environmental Issues
COMPETITION
Regulated utilities are generally not subject to competition from other utilities in areas that are under the jurisdiction of state regulatory commissions. In New Mexico, PNM does not have competition for services provided to its retail electric customers. In Texas, TNMP is not currently in any direct retail competition with any other regulated electric utility. However, the Company is subject to customer conservation activities and initiatives to utilize alternative energy sources. PNMR is subject to competition in the wholesale markets and the deregulated electricity market in Texas. Additional information relating to the competitive environment in which the Company operates in is contained in MD&A.
The Company is subject to varying degrees of competition in certain territories adjacent to or within the areas it serves with other utilities in its region as well as with rural electric cooperatives and municipal utilities. The Company is involved in the generation and sale of electricity into the wholesale market. It is subject to competition from regional utilities with similar opportunities to generate and sell energy at market-based prices and larger trading entities that do not own or operate generating assets. The Texas electricity market has been open to retail competition since 2002. The Company is exposed to competition in the unregulated Texas retail electricity market through First Choice, which serves customers at competitive rates. In order to compete effectively in the Texas retail electricity market, First Choice must be able to attract and retain customers on the basis of cost and service, while managing the cost of its energy supply.
Since 2002, electric consumers in Texas have been encouraged to switch from their traditional retail energy provider, such as TNMP, to a competitive REP, such as First Choice. Currently under TECA, consumers whose chosen retail energy provider has exited the Texas market are provided electric service by a “provider of last resort.” Rates of the provider of last resort are regulated by the PUCT and are fixed for the two-year period that each provider of last resort serves. First Choice and other REPs currently market retail electricity at competitive rates, which has resulted in increased pressure on margins.
EMPLOYEES
The following table sets forth the number of employees of PNMR, PNM, and TNMP and for each business segment as of December 31, 2010:
(1) Represents employees of PNMR Services Company.
As of December 31, 2010, PNM Electric had 642 employees in its power plant and operations areas that are currently covered by a collective bargaining agreement with the IBEW that was entered into in May 2009 and expires April 30, 2012. PNMR has no other employees represented by unions.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
Statements made in this filing that relate to future events or PNMR’s, PNM’s, or TNMP’s expectations, projections, estimates, intentions, goals, targets, and strategies, are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates and PNMR, PNM, and TNMP assume no obligation to update this information.
Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM, and TNMP caution readers not to place undue reliance on these statements. PNMR’s,
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PNM’s, and TNMP’s business, financial condition, cash flow, and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:
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Conditions affecting the Company’s ability to access the financial markets and the Company’s or Optim Energy’s ability to negotiate new credit facilities for those expiring in 2012, including actions by ratings agencies affecting the Company’s credit ratings,
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The potential unavailability of cash from PNMR’s subsidiaries or Optim Energy due to regulatory, statutory or contractual restrictions,
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The impacts of the decline in the values of marketable equity securities on the trust funds maintained to provide nuclear decommissioning funding and pension and other postretirement benefits, including the levels of funding and expense,
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The recession, its disruption in the credit markets, and its impacts on the electricity usage of the Company’s customers,
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State and federal regulatory and legislative decisions and actions, including the outcomes of PNM’s pending electric rate case and transmission rate case, and appeals of prior regulatory proceedings,
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The ability of PNM to successfully defend its utilization of a future test year in its current electric rate filing with the NMPRC, including PNM’s ability to withstand challenges by regulators and intervenors, in the event the pending stipulation in that case is not approved,
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The ability of PNM and TNMP to recover their costs and earn their allowed returns in their regulated jurisdictions,
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The ability of PNM to meet the renewable energy requirements established by the NMPRC, including the resource diversity requirement, within the specified cost parameters,
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The risk that replacement power costs incurred by PNM related to not meeting the specified capacity factor for its generating units under its Emergency FPPAC will not be approved by the NMPRC,
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The risk that PNM may not be able to recover costs of renewal of rights-of-way on Native American lands through rates charged to customers,
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The ongoing risks relating to PNMR’s ownership interest in Optim Energy, including uncertainties surrounding PNMR’s assessment of strategic alternatives for its investment in Optim Energy, the risk that a strategic transaction involving Optim Energy may not be consummated, uncertainty regarding potential additional contributions to Optim Energy, and the possibility that PNMR might recognize additional gains or impairments depending on market conditions, the form and structure of a strategic transaction, and relative fair values,
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The risk that Optim Energy requires additional financial sources to expand its generation capacity or otherwise but is unable to identify and implement profitable acquisitions or that PNMR and ECJV will not agree to make additional capital contributions to Optim Energy,
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Regulation or legislation relating to climate change, reduction of GHG, CCBs, and other power plant emissions, including the risk that the Company and Optim Energy may have to commit to substantial capital investments and additional operating costs to comply with new environmental requirements including possible future requirements to address regional haze regulations and related BART requirements and concerns about global climate change, and the resultant impacts on the operations and economic viability of generating plants in which PNM and Optim Energy have interests,
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The performance of generating units, including PVNGS, SJGS, Four Corners, and Optim Energy generating units, and transmission systems,
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The risks associated with completion of generation, transmission, distribution, and other projects, including construction delays and unanticipated cost overruns,
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Uncertainty regarding the requirements and related costs of decommissioning power plants owned or partially owned by PNM and Optim Energy and coal mines supplying certain PNM power plants, as well as the ability to recover decommissioning costs through rates charged to customers,
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Uncertainty surrounding the status of PNM’s participation in jointly-owned projects resulting from the scheduled expiration of the operational documents for the projects beginning in 2015 and potential changes in the objectives of the participants in the projects,
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The risk that recently enacted reliability standards regarding available transmission capacity may reduce certain PNM transmission rights used to transmit its generation resources and provide access to transmission customers resulting in a need to purchase additional transmission capacity, reduce sales of transmission capacity, or operate generation less economically,
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Changes in ERCOT protocols,
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Changes in the cost of power acquired by First Choice,
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The ability of First Choice to attract and retain customers,
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Collections experience,
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Fluctuations in interest rates,
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Weather,
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Water supply,
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Changes in fuel costs,
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Availability of fuel supplies,
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The effectiveness of risk management and commodity risk transactions,
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Seasonality and other changes in supply and demand in the market for electric power,
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The impact of mandatory energy efficiency measures on customer energy usage,
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Variability of wholesale power prices and natural gas prices,
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Volatility and liquidity in the wholesale power markets and the natural gas markets,
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Uncertainty regarding the ongoing validity of government programs for emission allowances,
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Changes in the competitive environment in the electric industry,
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The outcome of legal proceedings,
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Insurance coverage available for claims made in litigation,
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Changes in applicable accounting principles, and
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The performance of state, regional, and national economies.
See Item 7A. Quantitative and Qualitative Disclosure About Market Risk for information about the risks associated with the use of derivative financial instruments.
SECURITIES ACT DISCLAIMER
Certain securities described in this report have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be reoffered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933 and applicable state securities laws. This Form 10-K does not constitute an offer to sell or the solicitation of an offer to buy any securities.
ITEM 1A.
ITEM 1A. RISK FACTORS
The business and financial results of PNMR, PNM, and TNMP are subject to a number of risks and uncertainties, including those set forth below and in MD&A, Note 16 and Note 17. Optim Energy, which is 50% owned by PNMR, is subject to many of the same risks and uncertainties.
Financial Factors
The economic recession and disruption in the credit and capital markets may impact our growth strategy and ability to raise capital and negotiate new credit facilities for those expiring in 2012.
What has been characterized as a “credit crisis” developed in the latter part of 2008 in the United States, along with the most significant economic recession in decades. It is generally perceived that the recession has ended and that the credit markets have returned to a more normal state. PNMR and its operating subsidiaries rely on access to both short-term money markets and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations, which could include capital requirements for energy infrastructure investments and funding new projects. If PNMR, its operating subsidiaries, or Optim Energy are not able to access capital at competitive rates, or at all, PNMR’s ability to finance capital requirements, if needed, and its ability to implement its growth strategy will be limited. Additional disruptions in the credit markets, which could negatively impact our access to capital could be caused by:
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a further or “double-dip” economic recession,
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declines in the health of the banking sector generally, and the failure of specific banks who are parties to our credit facilities,
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the bankruptcy of an unrelated energy company,
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increased market prices for electricity and gas,
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terrorist attacks or threatened attacks on facilities of PNMR’s operating subsidiaries or those of unrelated energy companies, and
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deterioration in the overall health of the utility industry.
Market disruptions may increase the cost of borrowing or adversely affect our ability to raise capital through the issuance of securities or other borrowing arrangements, which could have a material adverse effect on business, financial position, results of operations and liquidity.
Any failure to renegotiate our credit facilities could harm our business, financial condition and results of operations.
As of February 18, 2011, the Company had consolidated short-term debt outstanding of $240.0 million through existing revolving credit facilities. The $542.0 million PNMR Facility and the $386.0 million PNM Facility both primarily expire in August 2012. These facilities, along with the TNMP Revolving Credit Facility, which expires in December 2015, provide the Company short-term borrowing capacity and also allow letters of credit to be issued, which reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company’s business is seasonal with more revenues and cash flows from operations being generated in the summer months when air conditioning loads are greater. In general, the Company relies on these credit facilities as the initial source to finance construction expenditures resulting in increased borrowings under the facilities over time. The PNMR and PNM credit facilities will need to be renegotiated or replaced prior to their expiration in order to provide sufficient liquidity to finance operations and construction expenditures. Also, the bank financing arrangement of Optim Energy expires in May 2012 and will need to be renegotiated or replaced. The availability of such credit facilities and their terms and conditions will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results. Industry experts suggest that the reduction in the number of banks and currently available credit coupled with numerous bank credit facilities across the utility industry expiring through 2012 could result in substantially higher pricing and shorter maturities of credit facilities. The Company is projecting total construction expenditures for the years 2011-2015 to be $1,396.4 million. The Company is exploring financial alternatives to meet these anticipated expenditures and currently believes that internal cash generation, credit arrangements, and access to the public and private capital markets will provide sufficient resources to meet capital requirements. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under current or then existing liquidity arrangements.
If our cash flow and credit and capital resources are insufficient to fund our capital expenditure plans, we may be forced to delay important capital investments, sell assets, seek additional equity or debt capital, or restructure our debt. In addition, any failure to make scheduled payments on our outstanding indebtedness would likely result in reductions of our credit ratings, which could harm our ability to incur additional indebtedness on acceptable terms and would result in an increase in the interest rates applicable under our credit facilities. Our cash flow and capital resources may be insufficient to pay interest and principal on our debt in the future. If that should occur, our capital raising or debt restructuring measures may be unsuccessful or inadequate to meet our scheduled debt service obligations, which could cause us to default on our obligations and further impair our liquidity.
Future reduction in our credit ratings could materially and adversely affect our business, financial position, results of operations and liquidity.
PNMR, PNM, and TNMP cannot be sure that any of their current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. Downgrades could result in:
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increased borrowing costs, which would negatively impact results of operation and cash flows,
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required payment of a higher interest rate in future financings, a smaller potential pool of investors, and decreased funding sources,
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required provision of additional support in the form of letters of credit, cash or other collateral to various counterparties, and
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limited access to, or increased costs of access to, the credit markets.
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Declines in values of marketable securities held in trust funds for pension and other postretirement benefits and in the NDT could result in sustained increases in costs and funding requirements for those obligations, which may affect our results of operations.
The Company targets 57.5% of its pension trust funds and 70.0% of its trust funds for other postretirement benefits to be invested in marketable equity securities. There was a significant decline in the general price levels of marketable equity securities in the second half of 2008 and early 2009. Although market prices generally improved later in 2009 and in 2010, increased levels of funding were required beginning in 2010 with additional amounts recorded as expense. Over one-half of funds held in the NDT are invested in marketable equity securities. The declines in market values resulted in the recognition of losses as impairments of certain securities held in the NDT. Further declines in market value could result in additional impairments.
PNMR may be unable to meet its ongoing and future financial obligations and to pay dividends on its common and convertible preferred stock if its subsidiaries or Optim Energy are unable to pay upstream dividends or distributions to PNMR.
PNMR is a holding company and has no operations of its own. PNMR’s ability to meet its financial obligations and to pay dividends on its common and convertible preferred stock at the current rate primarily depends on the net income and cash flows of its subsidiaries and Optim Energy and their ability to pay upstream dividends or distributions. Prior to providing funds to PNMR, PNMR’s subsidiaries and Optim Energy have financial obligations that must be satisfied, including among others, debt service and, in the case of PNM, preferred stock dividends.
PNM can pay dividends to PNMR from earnings as well as equity contributions made by PNMR. The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including the restriction that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC has also restricted PNM from paying dividends in any year, as determined on a rolling four quarter basis, in excess of net earnings without prior NMPRC approval. Additionally, PNM has various financial covenants that limit the transfer of assets, through dividends or other means.
In addition, the ability of PNMR to declare dividends depends upon the extent to which cash flows will support dividends, the availability of retained earnings, the Company’s financial circumstances and performance, the NMPRC’s and PUCT’s decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of federal regulatory decisions, Congressional and legislative acts, and economic conditions in the United States. Conditions imposed by the NMPRC or PUCT, future growth plans and the related capital requirements, and business considerations may also affect PNMR’s ability to pay dividends.
Impairments of tangible and intangible long-lived assets of PNMR, PNM, and TNMP could adversely affect their business, financial position, liquidity, and results of operations.
PNMR, PNM, and TNMP evaluate their intangible long-lived assets, including goodwill and non-amortizing intangible assets, for impairment annually or, along with tangible long-lived assets, whenever indicators of impairment exist. The market capitalization of PNMR’s common stock has been significantly below book value since 2008, which is an indicator that intangible assets may be impaired. Other potential impairment indicators could include changing customer purchase commitments and market share; fluctuating market and commodity prices resulting from weather patterns; changing fuel costs; increased environmental regulation; industry deregulation; and other economic and market conditions and trends. In addition, changes in the ERCOT market in which First Choice operates significantly impacts its results of operations. Also, Optim Energy made a strategic decision not to pursue the Twin Oaks expansion and wrote off its development rights as an impairment. After tax impairment losses for PNMR, its consolidated subsidiaries, and PNMR’s share of Optim Energy totaled $212.1 million for the year ended December 31, 2008. No impairments were recorded in 2009. No impairments of intangible assets or tangible long-lived assets were recorded in 2010 although as described in Note 22, PNMR determined its investment in Optim Energy was fully impaired at December 31, 2010, resulting in a pre-tax loss of $188.2 million ($113.7 million after-tax).
If further indicators of impairment become evident, additional analysis could result in future charges. In addition, the impairment analyses already performed were based on operating results expected to occur in the future. If the anticipated future results are not achieved, we may be required to perform additional assessments that could
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result in further impairment charges. Significant impairments adversely affect business, financial position, liquidity and results of operations.
There are risks associated with PNMR’s interest in Optim Energy.
As a result of the adverse market conditions experienced by Optim Energy, PNMR (in collaboration with Optim Energy and ECJV) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. Discussions regarding various alternatives have been held with several potential parties. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize additional impairments based on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.
Regulatory Factors
Failure of PNMR’s PNM and TNMP subsidiaries, which are subject to rate regulation by state regulators, to adequately recover the costs incurred to provide service to customers and to earn a fair return on invested capital could have a significant impact on the Company’s future financial condition and results of operations.
Critical to PNMR’s success is the financial health of its regulated operating subsidiaries, which is highly dependent on continued favorable regulatory treatment. Although the NMPRC approved rate increases for PNM in 2008 and 2009 and the PUCT approved rate increases for TNMP in 2009 and 2011, these were the first rate increases for the regulated operations in a number of years and there can be no assurance applications for rate increases in the future will be approved. PNM currently has an additional rate increase pending before the NMPRC. Furthermore, the Company anticipates a trend toward increasing costs of providing electric service due to new asset construction and deployment, increased rights-of-way renewal costs, higher costs of generation from renewable resources, energy efficiency mandates, possible increases to fuel costs, potential environmental compliance costs, increases in pension and benefit costs, and depreciation. If regulators do not allow the increased costs to be recovered from customers in a timely manner, the Company’s liquidity and results of operations could be negatively impacted.
PNM’s current electric rate case pending with the NMPRC proposes to establish rates utilizing a future test year. As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that are inherent in the forecasting process. PNM forecasted both operating and capital expenditures that necessitated reliance on many assumptions concerning future conditions and operating results. In the ratemaking process, regulators and intervenors can challenge PNM’s assumptions and may assert different interpretations or assumptions. PNM and six other parties have entered into a stipulation that, if approved by the NMPRC, would resolve all issues in the current electric rate case. However, other parties oppose the stipulation and it is uncertain if the NMPRC will approve it. If the stipulation is not approved, PNM would need to litigate its positions through a case before the NMPRC, which would be subject to the risks inherent in such a proceeding. If PNM cannot successfully support the use of a future test year in current and future rate filings, including defending its ability to reasonably forecast operating and capital expenditures and to withstand challenges by regulators and intervenors, cash flows and results of operations may be negatively impacted.
PNM may not be able to recover the costs of renewing rights-of-way, primarily on Native American lands, in rates charged to customers, which could negatively impact its liquidity and results of operations.
Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. Several of the agreements granting the rights-of-way were recently renewed at prices that are higher than historical levels. If PNM is not successful in recovering the costs of the rights-of-way renewals in rates approved by the NMPRC, its liquidity and results of operations will be negatively impacted.
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Costs of environmental compliance, liabilities, and litigation could exceed estimates by PNMR, its operating subsidiaries, and Optim Energy, which could adversely affect their business, financial position, results of operations, and liquidity. In addition, although there is uncertainty about the timing and form of regulations regarding climate change, CCBs, and other power plant emissions, such regulations could have a material impact on operations.
Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. PNMR, PNM, TNMP, and Optim Energy cannot predict how they would be affected if existing environmental laws and regulations were to be revised, or if new environmental laws and regulations seeking to protect the environment were to be adopted.
As discussed in Note 16, the EPA has recently issued its proposed BART determinations for both SJGS and Four Corners under the program to address regional haze in the “four corners” area. If the proposals are finalized in the form issued, they would require the installation of SCR technology at both SJGS and Four Corners in order to reduce the levels of NOx emitted. In addition, the BART proposal for SJGS would require installation within a three year timeframe, which the Company believes would be extremely difficult to accomplish. The Company is unable to predict the final form of regulations that may be issued, but the installation of additional pollution control equipment at SJGS and Four Corners would likely require significant capital expenditures that the Company would expect to be recovered through rates. If such costs are not allowed to be recovered from customers, the Company’s financial position, results of operation, and cash flows would be negatively impacted. It is also possible that the requirements to comply with BART combined with other environmental and business considerations could jeopardize the economic viability of the plants or the ability and willingness of individual participants to continue participation in the plants.
In addition, while there continues to be significant debate regarding the existence and extent of the emission of so-called GHG (particularly CO2) from fossil-fired generation facilities, PNMR and its operating subsidiaries believe that future governmental regulations applicable to their operations could limit GHG, although the framework and timing of regulation is currently unclear. A number of legislative bills have been introduced in the U.S. Congress that would require substantial costs to be incurred across the utility industry in order to comply, assuming that technology is available. Material changes in existing environmental laws and regulations, as well as new environmental laws and regulations, including the regulation of GHG, could increase financing requirements or otherwise adversely affect the business, financial position, results of operations, and liquidity of PNMR, its operating subsidiaries, and Optim Energy, unless increased environmental costs are recovered in customer rates or otherwise. Although the Company has begun the process of assessing the impacts of potential climate change legislation or regulation, the assessment is very preliminary and is based on numerous speculative assumptions regarding the final form of legislation or regulation. Revised or additional environmental laws and regulations could also result in additional operating restrictions on facilities and increased compliance costs that may not be fully recoverable in rates or otherwise, thereby reducing earnings.
CCBs, consisting of fly ash, bottom ash, and gypsum, from operation of PNM’s SJGS are currently being disposed of in the surface mine pits adjacent to the plant. The EPA is considering a proposal to regulate CCBs, but the timing of the release of EPA’s proposal is unclear. It is possible that the EPA could classify CCBs as a hazardous waste. PNM cannot predict the outcome of the EPA’s actions regarding CCB regulation and whether such actions will have a material adverse impact on its operations or financial position. However, if the regulation ultimately prevents the CCBs from SJGS to be disposed of in the adjacent mine, the increased costs of disposal could be significant, which would negatively impact PNM’s customers and the Company. The Company’s results of operations would be negatively impacted unless the costs are recovered in PNM’s customer rates.
In addition, PNM or TNMP may be designated as a responsible party for environmental clean up at a site identified by a regulatory body. PNMR, PNM, and TNMP cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. Failure to comply with environmental laws and regulations, even if caused by factors beyond PNM’s or TNMP’s control, may result in the assessment of civil or criminal penalties and fines.
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PNMR, PNM, and TNMP are subject to complex government regulation, which may have a negative impact on their business, financial position and results of operations.
PNMR, PNM, and TNMP are subject to comprehensive regulation by several federal, state, and local regulatory agencies, which significantly influence their operating environment and may affect their ability to recover costs from utility customers. In particular, the NMPRC, PUCT, FERC, NRC, EPA, ERCOT, NMED, TCEQ, and NERC regulate many aspects of their utility operations, including siting and construction of facilities, the purchase of power under long-term contracts, conditions of service, the issuance of securities, and the rates that the regulated entities can charge customers. PNMR, PNM, and TNMP are required to have numerous permits, approvals, and certificates from these agencies to operate their business. The rates that PNM and TNMP are allowed to charge for their retail services significantly influence PNMR’s and those subsidiaries’ business, financial position, results of operations, and liquidity. Due to continuing federal regulatory reforms, the public utility industry continues to undergo change. Although Optim Energy’s operations are generally not subject to regulation by the utility regulatory agencies, its operations are subject to regulation by other regulators, such as environmental authorities.
The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority, depending upon the NRC’s assessment of the severity of the situation, to impose monetary civil penalties or a progressively increased inspection regime, which could ultimately result in the shut down of a unit, until compliance is achieved, or both. PVNGS was subject to this heightened scrutiny from early 2007 through March 2009, when it exited the NRC’s enhanced inspection regime. Increased costs resulting from penalties, a heightened level of scrutiny, and implementation of plans to achieve compliance with NRC requirements, could adversely affect PNM’s financial condition, results of operations, and cash flows.
Under the Energy Policy Act of 2005, FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. The Company monitors and participates in the FERC and other proceedings involving implementation of the Energy Policy Act, in order to assess the implications of the law and rules on its operations.
FERC issued an order revising the determination of total transmission capability under the reliability standards for transmission systems. The order could potentially reduce the total transmission capacity that we use to deliver our generation resources to our customers. If such reductions occur, we might have to acquire additional transmission rights or assets, which could require substantial investments and a significant amount of time to accomplish.
PNMR and its subsidiaries are unable to predict the impact on their business and operating results from the future regulatory activities of any agency that regulates them or from the implementation of the Energy Policy Act. Changes in regulations or the imposition of additional regulations may require PNMR and its regulated subsidiaries to incur additional expenses or change business operations, and therefore may have an adverse impact on PNMR’s and those subsidiaries’ results of operations.
Operational Factors
General economic conditions of the state, region and nation can affect our customers and suppliers. For example, economic recession or downturn may affect the actions of our customers and result in decreased consumption and increased bad debt expense, and could also negatively impact our suppliers, all of which could negatively impact us.
Economic activity is a key factor in PNMR subsidiaries’ performance. Decreased economic activity can lead to declines in energy consumption, which could adversely affect future revenues, earnings and growth. Rises in unemployment rates both inside our service territories and nationwide could result in commercial customers ceasing operations and lower levels of income for our residential customers, causing them to be unable to pay their bills on time, which could impact our cash flows and increase our bad debt expense, which will impact results of operations. Decreased consumption, late or absence of payments and increases in bad debt expense would all negatively impact our results.
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Economic conditions also impact the supply of commodities and materials needed to construct or acquire utility assets or make necessary repairs. Recession may affect the supply of concrete, copper, steel, and aluminum. The costs of those items are also affected by economic conditions and could increase significantly over forecasted amounts.
The financial performance of PNMR, PNM, and TNMP may be adversely affected if their power plants and transmission and distribution system are not successfully operated. Further, the financial performance of Optim Energy may be adversely affected if its power plants are not successfully operated.
The financial performance of PNMR, PNM, and TNMP, as well as that of Optim Energy, depends on the successful operation of their generation, transmission, and distribution assets. The financial performance of PNMR and PNM may also be adversely affected if the NRC imposes restrictions on operation of PVNGS or any of the three units at the plant. Unscheduled or longer than expected maintenance outages, other performance problems with the electric generation assets, severe weather conditions, accidents and other catastrophic events, disruptions in the delivery of fuel, and other factors could reduce generation capacity and therefore limit the ability to sell power. Diminished generation capacity could also result in PNM’s aggregate net open forward electric sales position, including its retail load requirements, being larger than forecasted generation capacity. If this were to occur, purchases of electricity in the wholesale market by PNM would be required under contracts priced at the time of execution or, if in the spot market, at the then-current market price. There can be no assurance that sufficient electricity would be available at reasonable prices, or at all, if such a situation were to occur. Failures of transmission or distribution facilities may also cause interruptions in the services that PNM and TNMP provide. These potential generation, distribution, and transmission problems, and any potentially related service interruptions, could result in lost revenues and additional costs.
Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation capabilities.
Through its operating subsidiaries, PNMR is currently obligated to supply power to retail customers and certain wholesale customers. At peak times, the demand for power required to meet this obligation could exceed PNMR’s available generation capacity. Market or competitive forces may require that PNMR’s operating subsidiaries purchase capacity on the open market or build additional generation capabilities. Because regulators or market conditions may not permit the operating subsidiaries to pass all of these purchases or construction costs on to their customers, the operating subsidiaries may not be able to recover any of these costs or may have exposure to regulatory lag associated with the time between the incurrence of costs of purchased or constructed capacity and the recovery in customers’ rates. These situations could have negative impacts on net income and cash flows for PNMR and the affected operating subsidiary.
Costs of decommissioning, remediation, and restoration of nuclear and fossil-fueled power plants, as well as related coal mines could exceed estimates of PNMR, its subsidiaries, and Optim Energy, which could negatively impact results of operations and liquidity if regulators do not allow the increased costs to be recovered from customers.
PNM has interests in a nuclear power plant, two coal-fired power plants, and several natural gas-fired power plants. PNM is obligated to pay for the costs of decommissioning its share of the nuclear power plant as well as its share of the fossil-fueled power plants. PNM is also obligated to pay for the costs of decommissioning the mines that supply coal to the coal-fired power plants. Rates charged by PNM to its customers, as approved by the NMPRC, include a provision for recovery of certain costs of decommissioning, remediation, and restoration. As discussed in Note 17, the NMPRC has established a cap on surface mine decommissioning cost. In the event the costs exceed current estimates and PNM is unsuccessful in recovering the costs through increased rates, results of operations will be negatively impacted.
Optim Energy has interests in a coal-fired power plant and two gas-fired power plants and is obligated for decommissioning of its share of these facilities. Since Optim Energy is not subject to rate regulation, cost recovery can only be achieved through power sales at market-based rates. To the extent market-based rates are not adequate to recover the costs of decommissioning results of operations will be negatively impacted.
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The operating results of PNMR and its operating subsidiaries and Optim Energy are affected by weather conditions and regional drought and may fluctuate on a seasonal and quarterly basis.
Electric power generation, transmission, and distribution are generally seasonal businesses with demand for power from PNMR’s and Optim Energy’s electric operations traditionally peaking during the hot summer months. As a result, the operating results of PNMR, its operating subsidiaries, and Optim Energy will likely fluctuate substantially on a seasonal basis.
In addition, PNMR and its operating subsidiaries have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net earnings, available cash, and borrowing ability of PNMR and its operating subsidiaries.
Drought conditions in New Mexico generally, and especially in the “four corners” region, in which SJGS and Four Corners are located, may affect the water supply for PNM’s generating plants. If adequate precipitation is not received in the watershed that supplies that region, PNM may have to decrease generation at these plants, which would require the purchase of power to serve PNM’s customers and/or reduce PNM’s ability to sell excess power on the wholesale market and reduce its revenues. Drought conditions or actions taken by regulators or legislators could limit PNM’s supply of water, and PNM’s and PNMR’s business may be adversely impacted. Although PNM has been able to maintain adequate access to water through supplemental contracts and voluntary shortage sharing agreements with tribes and other water users in the “four corners” region, PNM cannot be certain that it will be able to do so in the future.
TNMP, First Choice, and Optim Energy have operations in the Gulf coast area of Texas, which experiences periodic hurricanes. In addition to potentially causing physical damage to Company or Optim Energy owned facilities, which disrupt the ability to transmit, distribute, and/or generate energy, hurricanes can reduce customers’ usage and demand for energy. These factors could reduce results of operation and cash flows.
The ability of First Choice to attract and retain customers, its ability to collect amounts billed to customers, and its ability to manage the spread between the costs of energy supply and the sales price to customers could have a significant adverse effect on PNMR’s business, financial position, results of operations, and liquidity.
PNMR is exposed to competition in the unregulated Texas retail electricity market through First Choice, which serves customers at competitive rates. In order to compete effectively in the Texas retail electricity market, First Choice must be able to attract and retain customers on the basis of cost and service, while managing the cost of its energy supply. The rates charged to many of First Choice’s customers are fixed for the term of the contract and do not include automatic adjustments for changes in the cost of its energy supply. In the event of rapid increases in the costs First Choice incurs to obtain the energy supplied to customers, the results of operations of First Choice could be negatively impacted unless increased costs have been successfully hedged. The competitive nature of the Texas market results in significant turnover in the customer base of First Choice. There is no provision under Texas regulation that requires customers to pay their previous REP before obtaining service from another REP. This was exacerbated by the impacts of Hurricane Ike and depressed economic conditions and resulted in significant increases in the levels of uncollectible accounts and bad debt expense in late 2008 and early 2009. The ability of First Choice to compete successfully in the Texas market could have a significant effect on PNMR’s business, financial position, results of operations, and liquidity.
There are inherent risks in the ownership and operation of nuclear facilities, such as environmental, health, fuel supply, spent fuel disposal, regulatory and financial risks, and the risk of a terrorist attack.
PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. PVNGS is subject to environmental, health, and financial risks such as the ability to obtain adequate supplies of nuclear fuel, the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks, unscheduled outages due to equipment failures, and other problems. PNM maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage. See Note 16. Although the decommissioning trust funds are designed to provide adequate funds for decommissioning at the end of the expected life of the PVNGS units, there is the risk of insufficient decommissioning trust funds in the event of early decommissioning of the units.
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Although the PVNGS participants have no reason to anticipate a serious nuclear incident at PVNGS, if an incident did occur, it could materially and adversely affect the results of operations and financial condition of PNM and PNMR. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
The operation of each of the three PVNGS units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses are valid for a period of approximately 40 years. APS, on behalf of the PVNGS participants, applied for renewed operating licenses for each unit on December 15, 2008 for a period of 20 years beyond the expirations of the current licenses. The NRC is currently reviewing the application. The PVNGS participants do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
PNM’s PVNGS leases describe certain events, including “Events of Loss” and “Deemed Loss Events”, the occurrence of which could require PNM to pay the lessors and the equity investors, in return for the investors’ interest in PVNGS, cash in the amount provided in the leases and take ownership of the underlying assets.
The “Events of Loss” generally relate to casualties, accidents, and other events at PVNGS, including the occurrence of specified nuclear events, which would severely, adversely affect the ability of the operating agent, APS, to operate, and the ability of PNM to earn a return on its interests in, PVNGS. The “Deemed Loss Events” consist mostly of legal and regulatory changes (such as issuance by the NRC of specified violation orders, changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). PNM believes that the probability of such “Events of Loss” or “Deemed Loss Events” occurring is remote for the following reasons: (1) to a large extent, prevention of “Events of Loss” and some “Deemed Loss Events” is within the control of the PVNGS participants, including PNM, and the PVNGS operating agent, through the general PVNGS operational and safety oversight process and (2) with respect to other “Deemed Loss Events,” which would involve a significant change in current law and policy, PNM is unaware of any pending proposals or proposals being considered for introduction in Congress, or in any state legislative or regulatory body that, if adopted, would cause any of those events. See Note 7.
Governance Factors
Provisions of PNMR’s organizational documents, as well as several other statutory and regulatory factors, will limit another party’s ability to acquire PNMR and could deprive PNMR’s shareholders of the opportunity to gain a takeover premium for shares of PNMR’s common stock.
PNMR’s restated articles of incorporation and by-laws include a number of provisions that may have the effect of discouraging persons from acquiring large blocks of PNMR’s common stock or delaying or preventing a change in control of PNMR. The material provisions that may have such an effect include:
•
authorization for the Board to issue PNMR’s preferred stock in series and to fix rights and preferences of the series (including, among other things, whether, and to what extent, the shares of any series will have voting rights, subject to certain limitations, and the extent of the preferences of the shares of any series with respect to dividends and other matters),
•
advance notice procedures with respect to any proposal other than those adopted or recommended by PNMR’s Board, and
•
provisions specifying that only a majority of the Board, the chairman of the Board, the chief executive officer, or holders of not less than one-tenth of all of PNMR's shares entitled to vote may call a special meeting of stockholders.
Under the New Mexico Public Utility Act, NMPRC approval is required for certain transactions that may result in PNMR’s change in control or exercise of control. Certain acquisitions of PNMR’s outstanding voting securities would also require FERC approval.
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ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
PNMR
The significant properties owned by PNMR include those owned by PNM and TNMP and are disclosed below.
PNM
Electric
PNM’s owned and leased capacity in electric generating stations in commercial service as of December 31, 2010 is:
(a) SJGS Units 1, 2 and 3 are 50% owned by PNM; SJGS Unit 4 is 38.5% owned by PNM.
(b) Four Corners Units 4 and 5 are 13% owned by PNM. Units 4 and 5 at Four Corners are jointly owned with SCE, APS, SRP, Tucson and EPE and are operated by APS. PNM has no ownership interest in Four Corners Units 1, 2 or 3.
(c) The NMPRC has approved the June 1, 2012 abandonment of the Las Vegas Generating Station.
(d) 50% of Afton’s capacity is currently designated to serve customers formerly served by TNMP (“PNM South”) and the other 50% designated to serve PNM’s remaining retail customers (PNM North”).
(e) PNM’s Lordsburg plant was built to serve wholesale customers and other sales rather than New Mexico retail customers, but became included in the retail rates in July 2009. See Note 17.
(f) PNM is entitled to 10.2% of the power and energy generated by PVNGS. PNM has ownership interests of 2.3% in Unit 1, 4.6% in Unit 2 and 10.2% in Unit 3 and has leasehold interests of 7.9% in Unit 1 and 5.6% in Unit 2.
(g) PNM is entitled to the energy and capacity of Delta under a PPA that is deemed to be an operating lease.
(h) PNM owns 33.3% of Luna. Luna became included in retail rates in July 2009. See Note 17.
(i) PNM has a PPA that entitles it to the entire output of Valencia. Valencia became included in retail rates under the 2008 Electric Rate Case. Valencia is a variable interest entity and is consolidated by PNM as required by GAAP. Therefore, Valencia is reflected in the above table as if it were owned. See Sources of Power above and Note 9 and Note 17.
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Fossil-Fueled Plants
SJGS is located in northwestern New Mexico, and consists of four units operated by PNM. Units 1, 2, 3 and 4 at SJGS have net rated capacities of 340 MW, 340 MW, 497 MW and 507 MW. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA and 8.2% by Tri-State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by M-S-R Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico and 7.028% by UAMPS.
Four Corners and a portion of the facilities adjacent to SJGS are located on land held under easements from the United States and also under leases from the Navajo Nation. APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest to 2041. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which occurred on February 15, 2011 and is awaiting final signature by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant which the Four Corners participants will pursue. A federal environmental review will be conducted as part of the DOI review process.
The power from Reeves, Lordsburg, Delta, and Valencia is used primarily for peaking and transmission support. See Item 1. Business. - Sources of Power.
Nuclear Plant
PNM is participating in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), Salt River Project, EPE, SCE, SCPPA and the Department of Water and Power of the City of Los Angeles. See Note 16 in the Notes to Consolidated Financial Statements for information on other PVNGS matters.
Transmission and Distribution
As of December 31, 2010, PNM owned, jointly owned, or leased, 3,188 circuit miles of electric transmission lines, 5,822 miles of distribution overhead lines, 5,519 cable miles of underground distribution lines (excluding street lighting), and 272 substations.
Other Information
PNM’s electric transmission and distribution lines are generally located within easements and rights-of-way on public, private, and Native American lands. PNM leases interests in PVNGS Units 1 and 2 and related property, Delta, EIP and associated equipment, data processing, communication, office and other equipment, office space, vehicles, and real estate. PNM also owns and leases service and office facilities in Albuquerque and in other areas throughout its service territory. See Note 7 and Note 16.
TNMP
TNMP’s facilities consist primarily of transmission and distribution facilities located in its three non-contiguous Texas service areas. TNMP also owns and leases service and office facilities in other areas throughout its service territory. As of December 31, 2010, TNMP owned 958 circuit miles of overhead electric transmission lines, 7,045 pole miles of overhead distribution lines, 1,057 circuit miles of underground distribution lines, and 103 substations.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Note 16 and Note 17 for information related to the following matters for PNMR, PNM, and TNMP, incorporated in this item by reference.
Note 16
•
Regional Haze - SJGS
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• Regional Haze - Four Corners
• Citizen Suit Under the Clean Air Act
• Navajo Nation Environmental Issues
• Four Corners Notice of Intent to Sue
• Santa Fe Generating Station
• Coal Combustion Waste Disposal - Sierra Club Allegations
• Gila River Indian Reservation Superfund Site
• PVNGS Water Supply Litigation
• San Juan River Adjudication
• Western United States Wholesale Power Market
• Begay v. PNM et al
• Transmission Issues
Note 17
• PNM - 2007 Electric Rate Case
• PNM - Emergency FPPAC
• PNM - 2010 Electric Rate Case
• PNM - Transmission Rate Case
• TNMP Competitive Transition Charge True-Up Proceeding
• TNMP - Interest Rate Compliance Tariff
• TNMP - Advance Meter System Deployment and Surcharge Request
• TNMP - 2010 Rate Case
• TNMP - Remand of ERCOT Transmission Rates for 1999 and 2000
SUPPLEMENTAL ITEM - EXECUTIVE OFFICERS OF PNM RESOURCES, INC.
All officers are elected annually by the Board of PNMR. Executive officers, their ages as of February 18, 2011 and offices held with PNMR for the past five years, or other companies if less than five years with PNMR, are as follows:
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PART II
ITEM 5.
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
PNMR’s common stock is traded on the New York Stock Exchange (Symbol: PNM). Ranges of sales prices of PNMR’s common stock, reported as composite transactions, and dividends declared on the common stock for 2010 and 2009, by quarters, are as follows:
Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.125 per share in July 2009 and July 2010, which are reflected as being in the second quarter above. The Board declared dividends on common stock considered to be for the third quarter of $0.125 per share in September 2009 and September 2010, which are reflected as being in the third quarter above. On December 14, 2010 and February 17, 2011 the Board declared quarterly dividends of $0.125 per share. PNMR targets a payout ratio of 50% to 60% of consolidated earnings. Beginning with the dividend declared on December 9, 2008, the Series A convertible preferred stock is entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock.
On February 18, 2011, there were 12,671 holders of record of PNMR’s common stock.
See Note 5 for a discussion on limitations on the payments of dividends and the payment of future dividends, as well as dividends paid by PNM and TNMP.
See Part III. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Cumulative Preferred Stock
PNMR and PNM are not aware of any active trading market for their preferred stock. Quarterly cash dividends were paid on PNM’s outstanding cumulative preferred stock at the stated rates during 2009 and 2010. Holders of PNMR’s Series A convertible preferred stock, which was issued in November 2008, receive dividend payments that are equivalent to the dividends that would have been received on the number of shares of common stock into which the preferred stock was convertible. TNMP does not have any cumulative preferred stock outstanding.
Sales of Unregistered Securities
None.
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ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data and comparative operating statistics for PNMR should be read in conjunction with the Consolidated Financial Statements and Notes thereto and MD&A. PNMR results include results for the Twin Oaks business from the date of acquisition on April 18, 2006 through May 31, 2007, when it was contributed to Optim Energy. On January 30, 2009, PNM completed the sale of its gas operations, which are considered discontinued operations and excluded from continuing operations information in the table below.
PNM RESOURCES, INC. AND SUBSIDIARIES
Note: The book value per common share at year end, tangible book value per share at year end, average number of common shares outstanding, and return on average common equity reflect the Series A convertible preferred stock as if it was converted into common stock at the date of its issuance on November 17, 2008.
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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
Notes:
Altura Wholesale includes Twin Oaks from April 18, 2006, the date of acquisition, through May 31, 2007, when Altura was contributed to Optim Energy.
Effective January 1, 2007, TNMP’s New Mexico operations were transferred to PNM Electric.
First Choice revenues have been reclassified to be consistent with the current year presentation.
PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.
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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
Notes:
Altura Wholesale includes Twin Oaks from April 18, 2006, the date of acquisition, through May 31, 2007, when Altura was contributed to Optim Energy.
Effective January 1, 2007, TNMP’s New Mexico operations were transferred to PNM Electric.
Under TECA, customers of TNMP Electric in Texas can choose First Choice or any other REP to provide energy. However, TNMP Electric delivers energy to customers within its service area regardless of the REP chosen. Therefore, TNMP Electric earns revenue for energy delivery and First Choice earns revenue on the usage of that energy by its customers. The MWh reported above for TNMP Electric and First Choice include 1,012,842, 1,131,907, 1,563,260, 2,018,110, and 2,332,098 MWh used by customers of TNMP Electric in 2010, 2009, 2008, 2007, and 2006, who have chosen First Choice as their REP.
First Choice MWh sales have been reclassified to be consistent with the current year presentation.
PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.
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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
Notes:
Altura Wholesale includes Twin Oaks from April 18, 2006, the date of acquisition, through May 31, 2007, when Altura was contributed to Optim Energy.
Effective January 1, 2007, TNMP’s New Mexico operations were transferred to PNM Electric.
The customers reported above for TNMP Electric and First Choice include 70,366, 80,718, 92,090, 126,855, and 145,795 customers of TNMP Electric at December 31, 2010, 2009, 2008, 2007, and 2006, who have chosen First Choice as their REP. These TNMP Electric customers are also included in the First Choice customers.
TNMP and First Choice customers have been reclassified to be consistent with the current year presentation.
PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.
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ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-K General Instruction I (2). A reference to a “Note” in this Item 7 refers to the accompanying Notes to Consolidated Financial Statements included in Item 8, unless otherwise specified. Certain of the tables below may not appear visually accurate due to rounding.
MD&A FOR PNMR
BUSINESS AND STRATEGY
PNMR provides electricity and energy efficiency products and services in core regulated and unregulated markets to help customers meet and manage their energy needs. PNM sold its gas operations on January 30, 2009 and is now focused on its regulated electric business going forward.
Regulated Operations
PNM
Critical to PNMR’s success for the foreseeable future is the financial health of PNM, PNMR’s largest subsidiary, which is highly dependent on continued favorable regulatory treatment. PNM anticipates a trend toward increasing costs of providing electric service and a period of plant expansion, primarily from renewable energy sources under the RPS established pursuant to New Mexico’s Renewable Energy Act and related regulations of the NMPRC. PNM also anticipates increases in costs related to rights-of-way, pension and benefits, and depreciation. PNM will seek to recover these increased costs of providing service to regulated customers through future rate filings. The impact that rate increases may have on customers’ usage and their ability to pay is unknown.
PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represents a 22% increase for PNM North and 20% increase for PNM South. The filed revenue requirements are based on a future test period ending December 31, 2011. PNM also proposed to implement a FPPAC for PNM South. This is the first rate case filing in New Mexico proposing a future test year consistent with the recently enacted SB 477. See Part I, Rates and Regulation. On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would resolve all issues in the 2010 Electric Rate Case and provide a rate path for PNM through 2013. Other parties have filed statements opposing the stipulation. This stipulation, which reflects some aspects of a future test year, is subject to approval of the NMPRC. The stipulation would allow PNM to increase rates by $45.0 million beginning May 15, 2011 and by an additional $40.0 million beginning January 1, 2012. The proposed rates are designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers would also be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1 2012. PNM would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and December 31, 2012. PNM’s next general rate adjustment could not go into effect before January 1, 2014, except that PNM can file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. If the stipulation is approved by the NMPRC, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account, which would be recorded as a regulatory disallowance. On February 22, 2011, the NMPRC issued an order denying a motion that requested the NMPRC, instead of the Hearing Examiner, conduct the hearing on the stipulation. PNM agreed to extend the suspension period for an additional three months to November 10, 2011. The Hearing Examiner has established a procedural schedule that includes a hearing on the stipulation beginning on May 9, 2011. See Note 17. PNM is unable to predict the outcome of this proceeding.
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As discussed in Note 17, in September 2008, PNM filed its 2008 Electric Rate Case requesting the NMPRC to approve an increase in electric service rates to all PNM retail customers except those formerly served by TNMP. The proposed rates were designed to increase annual operating revenue by $123.3 million. PNM also proposed a more traditional FPPAC. In June 2009, the NMPRC approved a stipulation resolving all issues in the rate case, including the inclusion of additional sources of power in determining rates. The approved stipulation allowed for an increase in annual non-fuel revenues of $77.1 million, 65% of which was implemented for bills rendered beginning July 1, 2009 and the remainder of which was implemented April 1, 2010. As an offset to the non-fuel revenue increase, PNM implemented a credit to customers totaling $26.3 million, representing the amount of revenues from past sales of SO2 allowances. This amount is being credited to customers over 21 months beginning July 1, 2009. PNM recorded an expense for the regulatory disallowance and recorded a regulatory liability for the amount to be credited to customers. The stipulation also provided for a more traditional FPPAC that went into effect with the new rates. The new FPPAC has an annual rather than a monthly adjustment mechanism, but is based on forecasted fuel and purchased power costs. The stipulation provides that 100% of off-systems sales revenues from resources included in retail rates be credited against fuel and purchased power costs in the FPPAC.
In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually. If approved, the rate increase would apply to all of PNM’s wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM’s transmission system to transmit power at the wholesale level. The proposed rate increase would not impact PNM’s retail customers. On December 29, 2010, FERC issued an order accepting PNM’s filing and suspending the proposed tariff revisions for five months to become effective June 1, 2011, subject to refund, and providing a schedule to establish hearing and settlement judge procedures. PNM is unable to predict the outcome of this proceeding.
PNM has completed the separation of its merchant operations from its regulated operations to comply with a 2003 NMPRC order. The separation of merchant operations was accomplished in several steps. Afton was transferred from merchant plant status and included in retail rates beginning in May 2008. In June 2008, PNM completed the sale of certain merchant wholesale power, natural gas and transmission contracts. In addition, Luna and Lordsburg, which had been classified as merchant plant, were included in retail rates beginning in July 2009. See Note 17. The NMPRC did not require that PNM’s interest in PVNGS Unit 3, which is permanently excluded from retail rates, be separated from PNM. PNM sells the capacity and energy from its entire ownership interest in PVNGS Unit 3 in the wholesale markets.
PNM also serves customers in New Mexico formerly served by TNMP. When PNMR acquired TNMP, PNM was required to maintain the former TNMP customers under rates separate from the rest of PNM. Pursuant to a stipulation approved by the NMPRC, PNM was prohibited from consolidating the cost of service for the two areas until January 1, 2015, unless the consolidation would not result in shifting more than $1.5 million in revenue requirements from the former TNMP customers to other PNM customers. In addition, the stipulation provided that PNM would not seek rate changes for the former TNMP customers that would go into effect before January 1, 2011. During 2009, the NMPRC requested the parties to the stipulation meet to discuss ways and means of mitigating possible large rate increases to the former TNMP customers that may occur when the rate moratorium expires. The parties have been meeting periodically under the direction of a NMPRC Hearing Examiner, who was appointed by the NMPRC to serve as mediator for the discussions. The stipulation in the 2010 Electric Rate Case discussed above would, if approved by the NMPRC, provide for a rate increase to the former TNMP customers on the same percentage basis as PNM’s other customers. See Note 17.
TNMP
TNMP’s financial health is also highly dependent on continued favorable regulatory treatment. On August 29, 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues. Subsequently, TNMP supplemented its filing to request an additional revenue increase of $15.7 million to recover costs caused by Hurricane Ike and costs related to the financing completed in March 2009. In June 2009, TNMP and the other parties in the rate case reached a unanimous settlement resolving all issues in the rate case and permitting TNMP to increase its rates by $12.7 million annually. This increase reflects interest and other costs associated with debt refinancing in March 2009 and the settlement adjusts the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The
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rate increase includes recovery of Hurricane Ike restoration costs plus carrying costs over five years. The settlement was approved by the PUCT in August 2009.
TNMP now has the ability to update its transmission rates twice a year to reflect changes in its invested capital. On March 2, 2010, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $33.8 million, with a total revenue requirement increase of $5.5 million. The requested updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The PUCT approved the interim adjustment on May 14, 2010.
On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In its request, TNMP also asked for permission to update its catastrophe reserve fund that would be utilized to pay for a utility system’s costs in recovering from natural disasters and acts of terrorism. Additionally, TNMP requested a rate rider to recover costs to storm harden its system. In December 2010, the parties announced that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million beginning February 1, 2011, a return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 2011.
Competitive Businesses
First Choice
As a REP, First Choice operates in the highly competitive Texas retail market, which experienced extreme price volatility and transmission congestion in 2008. ERCOT controls the transmission of power in the areas that First Choice supplies. ERCOT historically has operated through a series of geographic zones, which has led to congestion of the transmission system when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market. These situations caused First Choice to incur losses in its speculative trading portfolio and led First Choice to exit its speculative activities in the second quarter of 2008. These anomalies also negatively impacted the margins realized from end use customers. These conditions were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in very high levels of customer turnover and levels of uncollectible accounts significantly higher than historical experience. ERCOT has made changes in its control protocols and changed from the zonal system to a nodal system in December 2010, both of which should reduce congestion and price volatility. During 2009 and 2010, the Texas retail market was more stable and First Choice does not anticipate the levels of extreme congestion and price volatility will reoccur in the near future. In addition, both power and natural gas prices decreased significantly, resulting in a substantial increase in margins realized by First Choice in 2009 and continuing to a lesser degree in 2010. These factors and the increased focus on growing commercial accounts, customer credit standards, and improved customer service have contributed to an improvement in the results of operations at First Choice. However, similar to how the ERCOT market conditions - along with First Choice's buying and selling positions within that market - had a negative impact on the business in 2008, those same factors worked in First Choice’s favor in 2009 and somewhat in 2010. For 2011, First Choice expects market conditions to continue to be a key factor for the business and believes margins will continue to decline as they return to more historic levels.
Optim Energy
PNMR has previously reported that it intended to capitalize on growth opportunities in its unregulated business through its participation and ownership in Optim Energy. PNMR’s 50 percent ownership of Optim Energy allows it to participate in the operation of Optim Energy’s assets and business and the formulation of Optim Energy’s business strategy. Optim Energy owns electric generating assets in one of the nation’s growing power markets, and its strategy has been focused on acquiring or developing additional assets in that market. Consistent with this strategy, Optim Energy acquired the Twin Oaks plant from PNMR in June 2007, purchased the Altura Cogen plant in August 2007, and completed co-developing an electric generation unit at Cedar Bayou in June 2009. Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit.
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In 2009, however, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. The adverse market conditions continued throughout 2010. In response to those adverse conditions, in October 2009, Optim Energy changed its strategy and near-term focus. Optim Energy is currently focused on utilizing cash flow from operations to reduce debt and optimizing its current generation assets as a stand-alone independent power producer. Optim Energy’s goal is to optimize its performance under current market conditions with the expectation of being able to take advantage of any economic recovery in the power and gas markets over the next several years.
In addition to the continuing adverse market conditions evidenced by low power and natural gas prices, recently reported sales of electric generating resources within the ERCOT market have been transacted at prices (per KW of generating capacity) that are substantially below the amounts recorded for electric generating plants underlying PNMR’s investment in Optim Energy. As discussed in Note 22, PNMR performed an impairment analysis in accordance with GAAP of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis of the discounted cash flows of Optim Energy, recent sales of comparable generating assets, and the preliminary discussions regarding strategic alternatives for Optim Energy discussed in Strategy below indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax loss of $188.2 million ($113.7 million after-tax), which is reflected within Other Income and Deductions on the Consolidated Statements of Earnings (Loss) of PNMR.
Strategy
As a result of the adverse market conditions experienced by Optim Energy described above, PNMR (in collaboration with Optim Energy and ECJV) has been assessing various strategic alternatives relating to PNMR’ ownership interest in Optim Energy. Discussions regarding various alternatives have been held with several potential parties. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize gains or additional impairments based on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.
Environmental Sustainability
The Company’s focus on the electric businesses also includes environmental sustainability efforts. These efforts include environmental upgrades, improving energy efficiency, expanding the renewable energy portfolio of generation resources, and proactively addressing climate change. In early 2009, PNM completed environmental upgrades to each of the four units at SJGS. PNM’s share of the costs of these upgrades, which reduced the levels of NOx, SO2, and mercury emissions, amounted to $161 million. As described in Note 17, PNM is subject to the RPS established by New Mexico’s Renewable Energy Act and related regulations issued by the NMPRC, which require utilities to achieve certain levels of energy sales from renewable sources within its generation mix, including wind, solar, distributed generation, and other sources. PNM is actively engaged in activities to meet the NMPRC standard. PNM has also established various programs to promote energy efficiency, subject to the approval of the NMPRC. The Company monitors initiatives regarding legislation or regulation regarding climate change, including GHG, and participates in organizations and forums concerning climate change. The Company is supportive of a federal program that includes an economy-wide system of limitations on GHG that would include a cap and trade provision and a system of allowances and offsets designed to mitigate rate increases to utility customers. The Company is exploring various methods to mitigate its GHG in anticipation of climate change legislation or regulation, including increasing energy efficiency programs and increased reliance on renewable energy resources. See Climate Change Issues under Other Issues Facing the Company below for additional discussion of climate change matters. All of these efforts involve costs that the Company believes should be recoverable through rates charged to customers to the extent the costs are attributable to regulated operations. However, recovery of these costs is subject to the approval of regulators and will cause upward pressure on rates.
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Economic Conditions
In the last half of 2008 and early 2009, global economic conditions deteriorated dramatically, encompassing the U.S. residential housing market, and global and domestic equity and credit markets, which resulted in reduced usage of electricity by the Company’s customers. The tightening of the credit markets coupled with extreme volatility in commodity markets has had a direct, negative impact on several of First Choice’s competitors in the ERCOT retail market.
Although New Mexico and Texas do not seem to be impacted as greatly as some other areas of the United States, with unemployment rates that are somewhat lower than the rest of the nation, the territories served by the Company’s electric businesses have been impacted by the recession and general economic downturn. The Company believes that electric sales volume will increase modestly in the immediate future.
The disruption in the credit markets in late 2008 and early 2009 had a significant adverse impact on numerous financial institutions, including several of the financial institutions that have dealings with the Company. The Company’s existing liquidity instruments have not been materially impacted by the credit environment and management does not expect that the Company will be materially impacted in the near future. The PNMR Facility and PNM Facility expire in 2012 and will need to be renegotiated or replaced in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such credit facilities and their terms and conditions will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results. The Company is closely monitoring its liquidity and the credit markets. In late 2008 and early 2009, there was also a significant decline in the level of prices of marketable equity securities, including those held in trusts maintained for future payments of benefits under the Company’s pension and retiree medical plans. Although the general price levels of marketable equity securities have recovered somewhat, the stock market decline could result in increased levels of funding and expense applicable to these trusts.
RESULTS OF OPERATIONS - PNMR
Executive Summary
A summary of net earnings (loss) attributable to PNMR is as follows:
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The components of the changes in earnings (loss) from continuing operations attributable to PNMR by segment are:
Results of operations from our regulated utilities improved in 2010 due largely to rate increases. On April 10, 2010, PNM Electric implemented the second phase, or 35%, of a $77.1 million non-fuel base rate increase for retail customers, except those formerly served by TNMP. On May 14, 2010, TNMP implemented a $5.5 million increase to its annual transmission rates. In addition, increased retail loads driven by favorable weather and an increase in the average number of customers contributed to higher earnings at PNM. Increases at PNM and TNMP were offset by reduced earnings at First Choice, primarily due to mark-to-market losses on unrealized economic hedges and lower retail margins. As discussed in Note 22, PNMR determined its investment in Optim Energy was fully impaired as of December 31, 2010, resulting in a pre-tax loss of $188.2 million ($113.7 million after-tax).
Results of operations in 2009 reflected rate increases at our regulated utilities and strong performance at First Choice. On July 1, 2009, PNM Electric implemented the first phase of a $77.1 million non-fuel base rate increase for retail customers, except those formerly served by TNMP. PNM Electric was also granted a more traditional FPPAC, which replaced the Emergency FPPAC that terminated on July 1, 2009. On September 1, 2009, TNMP implemented a $6.8 million base rate increase. Additionally, retail margins at First Choice significantly improved. Increases in 2009 were partially offset by regulatory disallowances of $16.2 million, after income taxes, primarily relating to prior sales of SO2 emission allowances that resulted from the settlement of PNM’s 2008 Electric Rate Case and a $19.3 million after-tax charge related to the settlement of the California energy crisis legal proceeding by PNM. In addition, Optim Energy reduced the value of its held for sale NOx emission allowances. PNMR’s share of the after-tax charge was $15.6 million.
Results of operations were negatively impacted by several major factors during 2008. Impairments of goodwill and other intangible assets were recorded at PNM, TNMP, and First Choice, as well as at Optim Energy. After-tax impairment losses reduced net earnings by $212.1 million. PNM Electric recorded regulatory disallowances of $18.3 million after-tax resulting from its 2007 Electric Rate Case. General declines in the stock market negatively impacted the values of investments in the NDT resulting in an after-tax decrease in earnings of $16.2 million in 2008 compared to 2007. As a result of anomalies in the Texas energy market, First Choice experienced after-tax losses in its speculative trading operations, which were terminated in 2008, of $32.1 million in 2008. Optim Energy wrote-off its inventory of emissions allowances related to CAIR as a result of that program being invalidated. PNMR’s share of the after-tax loss was $9.6 million.
Income tax expense or benefit for 2008 was significantly impacted by the impairments of goodwill since the expense recorded for the impairments is not deductible for income tax purposes. The consolidated effective income tax rates for 2008 were 23.38% for PNMR, 14.47% for PNM, and 476.65% for TNMP. Excluding the losses due to goodwill impairment, the effective income tax rates would have been 42.43% for PNMR, 55.16% for PNM, and 30.25% for TNMP. The consolidated effective income tax rates for 2009 were 30.41% for PNMR, 30.08% for PNM, and 39.63% for TNMP.
The increase in the number of common and common equivalent shares is primarily due to new issuances of PNMR common stock in connection with the equity-linked units in 2008. See Note 6.
Segment Information
The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 3 for more information on PNMR’s operating segments.
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The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements in Item 1 and to Part II, Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board. The Board’s Finance Committee sets the risk limit parameters. The RMC, comprised of corporate and business segment officers, oversees all of the risk management activities, which include commodity risk, credit risk, interest rate risk, and business risk. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. The Company has risk control organizations, which are assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions, on an enterprise-wide basis.
The RMC’s responsibilities specifically include: establishment of policies regarding risk exposure levels and activities in each of the business segments; authority to approve the types of derivatives entered into; authority to establish a general policy regarding counterparty exposure and limits; authorization and delegation of transaction limits; review and approval of controls and procedures for derivative activities; review and approval of models and assumptions used to calculate mark-to-market and market risk exposure; authority to approve and open brokerage and counterparty accounts for derivatives; review of hedging and risk activities; the extent and type of reporting to be performed for monitoring of limits and positions; and quarterly reporting to the Audit and Finance Committees on these activities. The RMC also proposes risk limits, such as VaR and GEaR, to the Finance Committee for its approval.
It is the responsibility of each business segment to create its own control procedures and policies within the parameters established by the Corporate Financial Risk Management Policy, approved by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Risk Management Department and the Vice President and Treasurer. Each business segment’s policies address the following controls: authorized instruments and markets; authorized personnel; policies on segregation of duties; policies on mark-to-market accounting; responsibilities for deal capture; confirmation responsibilities; responsibilities for reporting results; statement on the role of derivative transactions; and limits on individual transaction size (nominal value).
To the extent an open position exists, fluctuating commodity prices can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with certainty the impact that its risk management decisions may have on its businesses, operating results or financial position.
Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 8. Note 8 also contains a summary of the fair values of mark-to-market energy related derivative contracts included in the Consolidated Balance Sheets.
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The following table details the changes in the net asset or liability balance sheet position for mark-to-market energy transactions other than cash flow hedges:
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The following table provides the maturity of the net assets (liabilities) other than cash flow hedges, giving an indication of when these mark-to-market amounts will settle and generate (use) cash. The following values were determined using broker quotes and option models:
Fair Value of Mark-to-Market Instruments at December 31, 2010
The fair value of commodity derivative instruments designated as cash flow hedging instruments decreased $21.0 million for PNMR and PNM for the year ended December 31, 2010 and $17.8 million for PNMR and $20.2 million for PNM for the year ended December 31, 2009.
Risk Management Activities
PNM measures the market risk of its long-term contracts and wholesale activities using a VaR calculation to measure price movements. The VaR calculation reports the possible market loss for the respective transactions. This calculation is based on the transaction’s fair market value on the reporting date. Accordingly, the VaR calculation is not a measure of the potential accounting mark-to-market loss. PNM utilizes the Monte Carlo VaR simulation model. The Monte Carlo model utilizes a random generated simulation based on historical volatility to generate portfolio values. The quantitative risk information, however, is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The VaR methodology employs the following critical parameters: historical volatility estimates, market values of all contractual commitments, appropriate market-oriented holding periods, and seasonally adjusted and cross-commodity correlation estimates. The VaR calculation considers PNM’s forward positions, if any. PNM uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The two-tailed confidence level established is 95%. For example, if VaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market simulations the pre-tax gain or loss in liquidating the portfolio would not exceed $10.0 million in the three days that it would take to liquidate the portfolio.
PNM measures VaR for all transactions that are not directly asset-related and have economic risk. PNM did not have any non-asset backed transactions for the year ended December 31, 2010. For the year ended December 31, 2009, the average, high, and low VaR amount for these transactions was less than $0.1 million. The total VaR amount for these transactions at December 31, 2009 was zero.
First Choice measures the market risk of its retail sales commitments and supply sourcing activities using a GEaR calculation to monitor potential risk exposures related to taking contracts to settlement and a VaR calculation to measure short-term market price impacts.
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Because of its obligation to serve customers, First Choice must take certain contracts to settlement. Accordingly, a measure that evaluates the settlement of First Choice’s positions against earnings provides management with a useful tool to manage its portfolio. First Choice uses a hold-to-maturity at risk for 12 months calculation for its GEaR measurement. The calculation utilizes the same Monte Carlo simulation approach described above at a 95% confidence level and includes the retail load and supply portfolios. Management believes the GEaR results are a reasonable approximation of the potential variability of earnings against forecasted earnings. The quantitative risk information, however, is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The GEaR calculation considers First Choice’s forward position for the next twelve months and holds each position to settlement. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. For example, if GEaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market scenarios calculated by the model the losses against the Company’s forecasted earnings over the next twelve months would not exceed $10.0 million.
For the year ended December 31, 2010, the average GEaR amount was $3.4 million, with high and low GEaR amounts for the period of $6.8 million and $1.5 million. The total GEaR amount at December 31, 2010 was $1.9 million. For the year ended December 31, 2009, the average GEaR amount for these transactions was $5.0 million, with high and low GEaR amounts for the period of $11.4 million and $1.7 million. The total GEaR amount for these transactions at December 31, 2009 was $1.9 million.
First Choice utilizes a VaR measure to manage its market risk. The VaR limit is based on the same total portfolio approach as the GEaR measure; however, the VaR measure is intended to capture the effects of changes in market prices over a holding period, which through June 30, 2010 was ten days. This holding period was considered appropriate given the nature of First Choice’s supply portfolio and the constraints faced by First Choice in the ERCOT market. In July 2010, First Choice modified the method of calculating VaR to consider First Choice’s positions over the life of the total portfolio and is intended to capture the effects of changes in market prices over a three day holding period. These changes, which did not significantly impact the VaR amounts, are considered appropriate given the nature of First Choice’s supply portfolio and the developing ERCOT market. The VaR calculations utilize the same Monte Carlo simulation approach described above at a 95% confidence level. The VaR amount for these transactions was $0.1 million at December 31, 2010. For the year ended December 31, 2010, the high, low and average VaR amounts were $2.3 million, $0.1 million and $0.2 million. The VaR amount for these transactions was $0.7 million at December 31, 2009. For the year ended December 31, 2009, the high, low and average VaR amounts were $2.0 million, $0.2 million and $0.8 million.
The Company’s risk measures are regularly monitored by the Company’s RMC. The RMC has put in place procedures to ensure that increases in risk measures that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures. VaR or GEaR limits were not exceeded during the year ended December 31, 2010 or 2009.
The VaR and GEaR limits represent an estimate of the potential gains or losses that could be recognized on the Company’s portfolios, subject to market risk, given current volatility in the market, and are not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.
Credit Risk
The Company conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. Credit exposure is regularly monitored by the RMC. The RMC has put procedures in place to ensure that increases in credit risk that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures.
The following table provides information related to credit exposure as of December 31, 2010. The table further delineates that exposure by the credit worthiness (credit rating) of the counterparties and provides guidance as to the concentration of credit risk to individual counterparties.
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Schedule of Credit Risk Exposure
December 31, 2010
(1) The Rating included in “Investment Grade” is for counterparties with a minimum S&P rating of BBB- or Moody’s rating of Baa3. If the counterparty has provided a guarantee by a higher rated entity (e.g., its parent), determination is based on the rating of its guarantor. The category “Internal Ratings - Investment Grade” includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company’s credit policy.
(2) The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than full requirements customers), forward sales and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses (pursuant to contract terms). Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by available credit collateral. Credit collateral includes advance payments, cash deposits, letters of credit, and parental guarantees received from counterparties. Amounts are presented before the application of such credit collateral instruments. At December 31, 2010, PNMR and PNM held credit collateral of zero to offset their credit exposure.
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The following table provides an indication of the maturity of credit risk by credit ratings of the counterparties.
Maturity of Credit Risk Exposure
December 31, 2010
The Company provides for losses due to market and credit risk. Net credit risk for PNMR’s and PNM’s largest counterparties as of December 31, 2010 was $4.5 million.
Interest Rate Risk
The Company has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of long-term debt instruments for PNMR, PNM, and TNMP would increase by 4.2%, 5.2%, and 2.7%, if interest rates were to decline by 50 basis points from their levels at December 31, 2010. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. As described in Note 6, TNMP has long-term debt of $50.0 million that bears interest at a variable rate. However, TNMP has also entered into a hedging arrangement that effectively results in this debt bearing interest at a fixed rate, thereby eliminating interest rate risk. In addition, in January 2010, PNM entered into a one year floating-to-fixed interest rate swap with a notional amount of $100.0 million associated with PNM’s unsecured revolving credit facility. At February 18, 2011, PNMR, PNM, and TNMP had $20.0, $220.0 million, and zero of short-term debt outstanding under their revolving credit facilities and local lines of credit, which allow for a maximum aggregate borrowing capacity of $547.0 million for PNMR, $386.0 million for PNM, and $75.0 million for TNMP. These facilities bear interest at variable rates, which averaged 1.52% for PNMR and 0.91% for PNM on February 18, 2011 borrowings, and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.
The securities held by PNM in the NDT and in trusts for pension and other post-employment benefits had an estimated fair value of $612.8 million at December 31, 2010, of which 29.2% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2010, the decrease in the fair value of the fixed-rate securities would be 5.0%, or $8.9 million. The securities held by TNMP in trusts for pension and other post-
A-69
employment benefits had an estimated fair value of $69.0 million at December 31, 2010, of which 24.7% were fixed-rate debt securities that subject TNMP to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2010, the decrease in the fair value of the fixed-rate securities would be 6.4%, or $1.1 million.
PNM and TNMP do not directly recover or return through rates any losses or gains on the securities, including equity and alternative investments discussed below, in the trusts for nuclear decommissioning or pension and other post-employment benefits. However, the overall performance of these trusts does enter into the periodic determinations of expense and funding levels, which are factored into the rate making process to the extent applicable to regulated operations. PNM and TNMP are at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market and alternatives investment risks discussed below to the extent not ultimately recovered through rates charged to customers.
Equity Market Risk
The NDT and trusts established for PNM’s pension and post-employment benefits hold certain equity securities at December 31, 2010. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 57.9% of the securities held by the various PNM trusts as of December 31, 2010. The trusts established for TNMP’s pension and post-employment benefits hold certain equity securities. These equity securities expose TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 55.6% of the securities held by the TNMP trusts as of December 31, 2010. There was a significant decline in the general price levels of marketable equity securities in late 2008 and in early 2009. The impacts of these declines were considered in the funding and expense valuations performed for 2009 and 2010 and resulted in reduced income or increased expense related to the pension plans being recorded and will require increased levels of funding beginning in 2010. See Note 12.
Alternatives Investment Risk
The Company has a target of investing 20% of its pension assets in the alternatives asset class, which amounted to 20.4% as of December 31, 2010. This includes real estate, private equity, and hedge funds. These investments are limited partner structures that are multi-manager multi-strategy funds. This investment approach gives broad diversification and minimizes risk compared to a direct investment in any one component of the funds. The general partner oversees the selection and monitoring of the underlying managers. The Company’s Corporate Investment Committee, assisted by its investment consultant, monitors the performance of the funds and general partner’s investment process. There is risk associated with these funds due to the nature of the strategies and techniques and the use of investments that do not have readily determinable fair value. The valuation of the alternative asset class has also been impacted by the significant decline in the general price levels of marketable equity securities.
A-70
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
INDEX
Page
Management’s Annual Reports on Internal Control Over Financial Reporting
B-2
Reports of Independent Registered Public Accounting Firm
B-5
Financial Statements:
PNM Resources, Inc. and Subsidiaries
Consolidated Statements of Earnings (Loss)
B-10
Consolidated Balance Sheets
B-11
Consolidated Statements of Cash Flows
B-13
Consolidated Statements of Changes in Equity
B-15
Consolidated Statements of Comprehensive Income (Loss)
B-16
Public Service Company of New Mexico and Subsidiaries
Consolidated Statements of Earnings (Loss)
B-17
Consolidated Balance Sheets
B-18
Consolidated Statements of Cash Flows
B-20
Consolidated Statements of Changes in Equity
B-22
Consolidated Statements of Comprehensive Income (Loss)
B-23
Texas-New Mexico Power Company and Subsidiaries
Consolidated Statements of Earnings (Loss)
B-24
Consolidated Balance Sheets
B-25
Consolidated Statements of Cash Flows
B-27
Consolidated Statements of Changes in Common Stockholder’s Equity
B-29
Consolidated Statements of Comprehensive Income (Loss)
B-30
Notes to Consolidated Financial Statements
B-31
Supplementary Data:
Reports of Independent Registered Public Accounting Firm on Schedules
B-121
Schedule I Condensed Financial Information of Parent Company
B-123
Schedule II Valuation and Qualifying Accounts
B-126
B-1
Management’s Annual Report on Internal Control Over Financial Reporting
Management of PNM Resources, Inc. and subsidiaries (“PNMR”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.
Management assessed the effectiveness of PNMR’s internal control over financial reporting based on the Internal Control - Integrated Framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that PNMR’s internal control over financial reporting was effective as of December 31, 2010.
Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on PNMR’s internal control over financial reporting which is included herein.
/s/ Patricia K. Collawn
Patricia K. Collawn,
President and Chief Executive Officer
/s/ Charles Eldred
Charles Eldred
Executive Vice President and
Chief Financial Officer
B-2
Management’s Annual Report on Internal Control Over Financial Reporting
Management of Public Service Company of New Mexico and subsidiaries (“PNM”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.
Management assessed the effectiveness of PNM’s internal control over financial reporting based on the Internal Control - Integrated Framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that PNM’s internal control over financial reporting was effective as of December 31, 2010.
Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on PNM’s internal control over financial reporting which is included herein.
/s/ Patricia K. Collawn
Patricia K. Collawn,
President and Chief Executive Officer
/s/ Charles Eldred
Charles Eldred
Executive Vice President and
Chief Financial Officer
B-3
Management’s Annual Report on Internal Control Over Financial Reporting
Management of Texas-New Mexico Power Company and subsidiaries (“TNMP”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.
Management assessed the effectiveness of TNMP’s internal control over financial reporting based on the Internal Control - Integrated Framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that TNMP’s internal control over financial reporting was effective as of December 31, 2010.
/s/ Patricia K. Collawn
Patricia K. Collawn,
President and Chief Executive Officer
/s/ Thomas G. Sategna
Thomas G. Sategna
Vice President and Controller
B-4
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
PNM Resources, Inc.
Albuquerque, New Mexico
We have audited the internal control over financial reporting of PNM Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2010 of the Company and our reports dated March 1, 2011 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1,
B-5
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Company of New Mexico
Albuquerque, New Mexico
We have audited the internal control over financial reporting of Public Service Company of New Mexico and subsidiaries (the “Company”) as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedules as of and for the year ended December 31, 2010 of the Company and our reports dated March 1, 2011 expressed an unqualified opinion on those consolidated financial statements and financial statement schedules.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1,
B-6
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
PNM Resources, Inc.
Albuquerque, New Mexico
We have audited the accompanying consolidated balance sheets of PNM Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of earnings (loss), changes in equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PNM Resources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1,
B-7
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Public Service Company of New Mexico
Albuquerque, New Mexico
We have audited the accompanying consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of earnings (loss), changes in equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Mexico and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1,
B-8
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Texas-New Mexico Power Company
Lewisville, Texas
We have audited the accompanying consolidated balance sheets of Texas-New Mexico Power Company and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of earnings (loss), statements of changes in common stockholder’s equity, comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Texas-New Mexico Power Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1,
B-9
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-10
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-11
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-12
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-13
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-14
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-15
PNM RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.
B-16
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-17
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-18
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-19
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-20
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-21
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-22
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes, as they relate to PNM, are an integral part of these financial statements.
B-23
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-24
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-25
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-26
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-27
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-28
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER’S EQUITY
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-29
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.
B-30
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(1) Summary of the Business and Significant Accounting Policies
Nature of Business
PNMR is an investor-owned holding company of energy and energy-related businesses. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNM is a public utility with regulated operations primarily engaged in the generation, transmission, and distribution of electricity and, through January 29, 2009, the transmission, distribution, and sale of natural gas. As described in Note 2, PNM completed the sale of its natural gas operations on January 30, 2009. TNMP and First Choice are wholly owned subsidiaries of TNP, which is a holding company that is wholly owned by PNMR. TNMP provides regulated transmission and distribution services in Texas. First Choice is a competitive retail electric provider operating in Texas. PNMR owns 50% of Optim Energy, which is focused on unregulated electric operations, principally within the areas of Texas covered by ERCOT, including the development, operation, and ownership of diverse generation assets and wholesale marketing. See Note 22. PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM.
Financial Statement Preparation and Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.
The Notes to Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. For discussion purposes, this report will use the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such.
Certain amounts in the 2009 and 2008 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2010 financial statement presentation. Prior to its sale, PNM Gas, a segment of PNM, was classified as held for sale and is shown as discontinued operations for all periods presented. See Note 2 and Note 23.
GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.
Principles of Consolidation
The Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNM consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.
PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments, including Optim Energy. These services are billed at cost, except for Optim Energy, which includes a profit element. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 20.
B-31
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Accounting for the Effects of Certain Types of Regulation
The Company maintains its accounting records in accordance with the uniform system of accounts prescribed by FERC and adopted by the NMPRC and PUCT.
Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to its regulated operations. Regulators may assign costs to accounting periods that differ from accounting methods applied by non-regulated utilities. When it is probable that regulators will permit recovery of costs through future rates, costs are deferred as regulatory assets that otherwise would be expensed. Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred. Regulatory assets and liabilities are amortized into earnings over the authorized recovery period. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of FERC, the NMPRC, and the PUCT. Information on “regulatory assets” and “regulatory liabilities” is contained in Note 4.
Cash and Cash Equivalents
Investments in highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.
Utility Plant
Utility plant is stated at cost, which includes capitalized payroll-related costs such as taxes, pension, and other fringe benefits, administrative costs and an allowance for funds used during construction where authorized by rate regulation.
Repairs, including major maintenance activities, and minor replacements of property are expensed when incurred, except as required by regulators for ratemaking purposes. Major replacements are charged to utility plant. Gains or losses resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to the accumulated provision for depreciation.
Allowance for Funds Used During Construction
As provided by the FERC uniform systems of accounts, an allowance for funds used during construction is charged to regulated utility plant for construction projects. This allowance is a non-cash item designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction).
In 2010, 2009, and 2008, PNM recorded $4.6 million, $8.0 million, and $7.9 million of allowance for funds used during construction on certain projects and TNMP recorded $0.2 million, $1.1 million, and $1.0 million.
Capitalized Interest
PNMR capitalizes interest on its construction projects and major computer software projects not subject to the computation of an allowance for funds used during construction. Interest was capitalized at the overall weighted average borrowing rate of 6.7% 6.9% and 6.5% for 2010, 2009, and 2008. PNMR’s capitalized interest was $0.8 million, $0.7 million, and $0.8 million in 2010, 2009, and 2008; PNM’s was $0.4 million, $0.2 million, and $0.5 million; and TNMP’s was zero in 2010 and 2009 and less than $0.1 million in 2008.
B-32
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Carrying Charges on Stranded Costs
TNMP’s estimate of allowable carrying charges on stranded costs that it may recover from its transmission and distribution customers is based on a Texas Supreme Court ruling and the PUCT’s application of that ruling.
Materials, Supplies, and Fuel Stock
Materials and supplies relate to transmission, distribution, and generating assets. Materials and supplies are charged to inventory when purchased and are expensed or capitalized as appropriate when issued. Materials and supplies are valued using an average costing method.
Coal is valued using a rolling weighted average costing method that is updated based on the current period cost per ton. Periodic aerial surveys are performed on the coal piles and adjustments are made. In addition to coal delivered and included in inventory, PNM prepays the SJGS coal supplier for coal mined but not yet delivered. At December 31, 2010 and 2009, prepayments for coal, which are included in other current assets on the Consolidated Balance Sheets of PNMR and PNM, amounted to $30.9 million and $32.1 million.
Inventories consisted of the following at December 31:
Investments
In 1985 and 1986, PNM entered into eleven operating leases for interests in certain PVNGS generation facilities (see Note 7). The 10.3% and 10.15% lessor notes that were issued by the owners of the assets subject to these leases were subsequently purchased by and are now held by the PVNGS Capital Trust, which is consolidated by PNM. Eight leases continue and are classified as operating leases. The PVNGS Capital Trust intends to hold the lessor notes until such notes mature. Similarly, in 1985, PNM entered into two operating leases for the EIP transmission line for which the owners had issued lessor notes. In 2003, PNM acquired a 60% ownership interest in the EIP, collapsing the lease relating to it, and in 2004 purchased the outstanding lessor note relating to the remaining 40% interest. The remaining EIP lessor note bears interest at 10.25%, matures in 2012, and is carried on the Consolidated Balance Sheet in other investments at $4.6 million and $6.7 million as of December 31, 2010 and 2009. Both the PVNGS and EIP lessor notes are carried at amortized cost.
The Company’s other investments, including the NDT, are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in the Company’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions. At December 31, 2010 and 2009, substantially all of these investments were classified as available for sale. PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS. PNM evaluates these investment securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the NDT securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2010, 2009 and 2008, PNM recorded impairment losses on securities held in the NDT of $5.0 million, $8.1 million, and $12.3 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments are included in other comprehensive income, net of any related tax effect.
B-33
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Investment in Optim Energy
PNMR accounts for its investment in Optim Energy using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over Optim Energy and its operations. Through December 31, 2010, PNMR recorded its percentage share of earnings or loss of Optim Energy and carried its investment at cost, adjusted for its share of undistributed earnings or losses. The difference between PNMR’s book value of its investment in Optim Energy and its proportionate share of Optim Energy’s equity was being amortized into results of operations over the useful lives of the underlying assets and contractual periods of the liabilities that resulted in the difference. As described in Note 22, PNMR’s investment in Optim Energy was reduced to zero at December 31, 2010 due to the determination that the investment was fully impaired.
Goodwill and Other Intangible Assets
Under GAAP, the Company does not amortize goodwill. Certain intangible assets are amortized over their estimated useful lives. Goodwill and non-amortizable other intangible assets are evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill and intangible assets might be impaired. Amortizable other intangible assets are amortized over the shorter of their economic or legal lives and are evaluated for impairment when events and circumstances indicate that the assets might be impaired. Impairments recorded in 2008 are discussed in Note 25.
Asset Impairment
Tangible long-lived assets are evaluated in relation to the future undiscounted cash flows to assess recoverability when events and circumstances indicate that the assets might be impaired.
Revenue Recognition
PNM, TNMP, and First Choice record operating revenues, as applicable, in the period of delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales by PNM, TNMP, and First Choice to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates based on regression analyses reflecting historical trends and experience.
PNM’s gas operations, which were sold on January 30, 2009 and are reflected as discontinued operations, purchased gas on behalf of its end-use sales-service customers while other marketers or producers purchased gas on behalf of their end-use transportation-service customers. PNM collected a cost of service revenue for the transportation, delivery, and customer service provided to all on-system end-use customers. Cost of service tariffs were set by the NMPRC while gas commodity rates were subject to the terms of the PGAC with oversight provided by the NMPRC.
PNM’s wholesale electricity sales are recorded as operating revenues and the wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are net settled or “booked-out” are recorded net in earnings. A book-out is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden (see further discussion below in Derivatives). For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.
Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as trading transactions or economic hedges. Trading transactions are defined as derivative instruments used to take advantage of existing market opportunities. Changes in the fair value of trading transactions are reflected on a net basis in operating revenues. The Company
B-34
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
stopped entering into speculative trading transactions during 2008. Economic hedges are defined as derivative instruments, including long-term power agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable consists primarily of trade receivables from customers, principally end users of electricity. In the normal course of business, credit is extended to customers on a short-term basis. The overall credit risk for customers is considered low. The Company calculates the allowance for uncollectible accounts based on historical experience and estimated default rates by customer class applied to corresponding accounts receivable balances net of customer deposit coverage. The accounts receivable balances are reviewed monthly and adjustments to the allowance for uncollectible accounts and bad debt expense are made as necessary. Amounts that are deemed uncollectible are written off.
Depreciation and Amortization
PNM’s provision for depreciation and amortization of utility plant, other than nuclear fuel, is based upon straight-line rates approved by the NMPRC. Nuclear fuel is based on units-of-production. TNMP’s provision for depreciation and amortization of utility plant is based upon straight-line rates approved by the PUCT. Depreciation of non-utility property is computed based on the straight-line method. The provision for depreciation of certain equipment is allocated between depreciation expense and construction projects based on the use of the equipment. Average rates used are as follows:
Amortization of Debt Acquisition Costs
Discount, premium, and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. Gains and losses incurred upon the early retirement of long-term debt are recognized in other income or deductions, except for amounts attributable to NMPRC or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues.
Derivatives
The Company records derivative instruments in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or sale criteria are met. For qualifying hedges, a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.
The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract
B-35
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
cannot permit net settlement, the seller must have the resources to serve the contract and the buyer must be a load serving entity.
In addition, all energy contracts held for trading purposes are presented on a net margin basis in the statement of earnings. Energy contracts that do not meet the definition of a derivative are recognized in current earnings and are not marked to market.
GAAP gives guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. Trading transactions include speculative transactions, which the Company ceased in 2008. Also included in this category are transactions that lock in margin with no forward market risk and are not economic hedges; changes in the fair value of these transactions are reflected on a net basis in operating revenues.
Decommissioning Costs
PNM owns and leases nuclear and fossil-fuel generating facilities. In accordance with GAAP, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Nuclear decommissioning costs and related accruals are based on site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions. PNM’s accruals for PVNGS Units 1, 2, and 3 have been made based on such estimates, the guidelines of the NRC, and the probability of a license extension. PVNGS Unit 3 is excluded from PNM’s retail rates while PVNGS Units 1 and 2 are included. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fueled generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. See Note 15.
In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation as well as the costs for final reclamation of the coal mines. The reclamation costs are based on site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for a discussion of the final reclamation costs.
Pension and Other Postretirement Benefits
See Note 12 for a discussion of pension and postretirement benefits expense, including a discussion of the actuarial assumptions.
Stock-Based Compensation
See Note 13 for a discussion of stock-based compensation expense.
Income Taxes
Income taxes are accounted for using the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current NMPRC and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. Items accorded flow-through treatment under rate
B-36
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
orders, deferred income taxes, and the future ratemaking effects of such taxes, as well as corresponding regulatory assets and liabilities, are recorded in the financial statements. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. See Note 11. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets.
Excise Taxes
The Company pays certain fees or taxes which are either considered to be an excise tax or similar to an excise tax. Substantially all of these taxes are recorded on a net basis in the Consolidated Statements of Earnings.
(2) Acquisitions and Dispositions
PNM Gas Sale
On January 12, 2008, PNM reached a definitive agreement to sell its natural gas operations, which comprised the PNM Gas segment, to NMGC, a subsidiary of Continental, for $620.0 million in cash, subject to adjustment based on the actual level of working capital at closing. PNM received an additional $32.9 million related to working capital true-ups. In a separate transaction conditioned upon the sale of the natural gas operations, PNMR proposed to acquire CRHC, Continental’s regulated Texas electric transmission and distribution business, for $202.5 million in cash. On July 22, 2008, PNMR and Continental agreed to terminate the agreement for the acquisition of CRHC. Under the termination agreement, Continental agreed to pay PNMR $15.0 million upon the closing of the PNM Gas transaction. PNM completed the sale of PNM Gas on January 30, 2009 and recognized a gain of $65.3 million, after income taxes of $33.1 million, that is included in discontinued operations on the Consolidated Statements of Earnings (Loss). This gain reflects the reduction for the increase in the PBO of the PNM pension plan related to the retirement of employees transferred to NMGC. See Note 12. In 2009, PNMR recognized an additional pre-tax gain of $15.0 million ($9.1 million after income taxes) due to the CRHC termination payment, which is included in other income on the Consolidated Statements of Earnings (Loss). In connection with the sale, PNM retained obligations under the frozen PNM pension and executive retirement plans for employees transferred to NMGC. PNM had a regulatory asset related to these plans, which was removed from regulatory assets on the date of the sale and transferred to AOCI. The after-tax charge to AOCI was $64.8 million. PNM also retained obligations for certain contingent liabilities that existed at the date of sale. PNM recognized $5.4 million in expense related to these liabilities in 2009, which is included in discontinued operations on the Consolidated Statements of Earnings (Loss).
PNM used proceeds from the sale to retire short-term debt and paid a dividend of $220.0 million to PNMR. The remaining funds were used to pay income taxes on the gain from the sale. PNMR used the dividend from PNM and the $15.0 million from Continental to retire debt. There were no material prior relationships between the PNMR and Continental parties other than in respect of the transactions described herein. PNM and PNMR Services Company provided certain corporate administrative and customer service support at cost to NMGC under a transition services agreement. The agreement term began January 30, 2009 and terminated in July 2009 with the exception of shared meter reading services, which continued through January 30, 2011. See Note 23 for financial information concerning PNM Gas, which is classified as discontinued operations in the accompanying financial statements.
Other
On June 29, 2007, a wholly-owned subsidiary of PNMR purchased 100% of a trust that owns a 2.27% undivided interest, representing 29.8 MW, in PVNGS Unit 2 and a 0.76% undivided interest in certain PVNGS common facilities, as well as a lease under which such facilities are leased to PNM. The beneficial interest in the trust was purchased for $44.0 million in cash and the assumption of $41.2 million in long-term debt payable to PVNGS Capital Trust. This long-term debt offsets a portion of the investment in PVNGS lessor notes and was eliminated in PNMR’s consolidated financial statements. The funds for the purchase were provided by PNMR. The lease remained in effect and the transaction had no impact on PNM’s consolidated financial statements. As described in Note 17, the Resource Stipulation allowed the Unit 2 interest to be transferred to PNM and the
B-37
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
acquisition costs to be recovered in PNM’s rates beginning with the 2008 Electric Rate Case. In July 2009, PNM purchased the trust from the other PNMR subsidiary for $39.1 million in cash. The purchase price was equal to the book value of the underlying assets less deferred taxes and miscellaneous accruals. The other PNMR subsidiary paid a dividend of that same amount to PNMR. PNMR then made an equity contribution of that amount to PNM. The trust had $32.0 million of debt owing to the PVNGS Capital Trust, which is consolidated by PNM. The transfer had no impact on the financial statements of PNMR. The impacts on the financial statements of PNM were to increase net plant in service by $73.7 million, increase common stock by $39.1 million, reduce investment in the PVNGS lessor notes by $32.0 million, reflecting the elimination of the debt owed by the trust to the PVNGS Capital Trust, and increase deferred income taxes and other accruals by $2.6 million.
(3) Segment Information
The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.
PNM Electric
PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico as well as the sale of transmission to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. This includes the asset optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale rates.
TNMP Electric
TNMP Electric is an electric utility operating in Texas. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides regulated transmission and distribution services in Texas under the TECA.
PNM Gas
PNM Gas distributed natural gas to most of the major communities in New Mexico, subject to traditional rate regulation by the NMPRC. The customer base of PNM Gas included both sales-service customers and transportation-service customers. PNM Gas purchased natural gas in the open market and sold it at cost to its sales-service customers. As a result, increases or decreases in gas revenues resulting from gas price fluctuations did not impact gross margin or earnings. As described in Note 2, PNM completed the sale of its gas operations on January 30, 2009. PNM Gas is reported as discontinued operations in the accompanying financial statements and is not included in the segment information presented below. Financial information regarding PNM Gas is presented in Note 23.
First Choice
First Choice is a certified retail electric provider operating in Texas, which allows it to provide electricity to residential, small commercial, and governmental customers. Although First Choice is regulated in certain respects by the PUCT, it is not subject to traditional rate regulation.
Optim Energy
Optim Energy is considered a separate segment for PNMR. PNMR’s investment in Optim Energy is held in the Corporate and Other segment and is accounted for using the equity method of accounting. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. See Note 22.
Corporate and Other
PNMR Services Company is included in the Corporate and Other segment.
B-38
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following tables present summarized financial information for PNMR by segment. Excluding PNM Gas, which is presented as discontinued operations, PNM has only one segment. TNMP operates in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP. Explanations for footnotes follow the tables.
PNMR SEGMENT INFORMATION
B-39
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
B-40
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Footnote explanations for the above tables are as follows:
(1) Excludes gross property additions related to PNM Gas discontinued operations of $3,434 and $36,825 for 2009 and 2008.
(2) Includes PNM’s purchase of an interest in PVNGS Unit 2 from another subsidiary of PNMR of $39,126.
(3) Excludes total assets related to PNM Gas discontinued operations of $669,901 at December 31, 2008.
Major Customers
No individual customers accounted for more than 10% of the operating revenues of PNMR or PNM. First Choice is a customer of TNMP and accounted for 18% of its operating revenues from continuing operations in 2010, 21% in 2009, and 29% in 2008. One unaffiliated customer of TNMP accounted for 19% of its operating revenues from continuing operations in 2010, 20% in 2009, and 22% in 2008. Another unaffiliated customer of TNMP accounted for 13% of its operating revenues from continuing operations in 2010 and 2009 and less than 10% in 2008.
B-41
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(4) Regulatory Assets and Liabilities
Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to its regulated operations. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below. On January 30, 2009, PNM completed the sale of its gas operations. Upon the sale, the regulatory asset of $107.3 million for pension obligations not transferred to NMGC was removed from regulatory assets and charged, net of income taxes, to AOCI.
PNMR
B-42
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM
TNMP
B-43
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The Company’s regulatory assets and regulatory liabilities are reflected in rates charged to customers or have been addressed in a regulatory proceeding. The Company does not receive or pay a rate of return on the following regulatory assets and regulatory liabilities (and their remaining amortization periods): coal mine reclamation costs (through 2020); deferred income taxes (over the remaining life of the taxable item, up to the remaining life of utility plant); financing costs (over the life of the related debt); pension and OPEB costs (through 2033); asset retirement obligations (to be determined in a future regulatory proceeding); and SO2 credits (through April 2011).
The Company is permitted, under rate regulation, to accrue and record a regulatory liability for the estimated cost of removal and salvage associated with certain of its assets through depreciation expense. Under GAAP, actuarial losses and prior service costs for pension plans are required to be recorded in AOCI; however, to the extent authorized for recovery through the regulatory process these amounts are recorded as regulatory assets or liabilities. Based on prior regulatory approvals, the amortization of these amounts will be included in the Company’s rates. See Note 17 for information related to TNMP’s stranded costs and 2009 regulatory decisions, which resulted in additions to regulatory assets and liabilities.
Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that future recovery of its regulatory assets are probable.
(5) Stockholders’ Equity
Common Stock and Equity Contributions
See Note 6 for details related to PNMR’s issuance of common stock. PNM and TNMP did not issue any common stock during the three year period ended December 31, 2010.
PNMR made cash equity contributions to PNM of $86.3 million, including the transaction relating to the transfer of an interest in PVNGS Unit 2 as described in Note 2, in 2009. PNMR made an equity contribution to TNMP by forgiving intercompany borrowings of $25.2 million in 2009.
Dividends on Common Stock
The declaration of common dividends by PNMR is dependent upon a number of factors including the ability of PNMR’s subsidiaries to pay dividends. PNMR’s primary sources of dividends are its operating subsidiaries.
In 2010, PNM paid cash dividends to PNMR of $28.0 million. In addition, PNM declared a dividend of $39.1 million in December 2010 that was paid in January 2011. Following the sale of PNM Gas, PNM paid a dividend to PNMR of $220.0 million on February 5, 2009 and paid additional cash dividends of $79.7 million in 2009. PNM paid cash dividends of $40.0 million to PNMR in 2008. TNMP paid cash dividends to PNMR of $13.1 million in 2010 and $9.3 million in 2009. TNMP did not pay any cash dividends to PNMR in 2008.
Each of the PNMR Facility, the PNM Facility, and the TNMP Revolving Credit Facility contain covenants that require the maintenance of debt-to-capital ratios of less than or equal to 65%. For PNMR and PNM these ratios reflect the present value of payments under the PVNGS and EIP leases as debt. The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including the restriction that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC provisions allow PNM to pay dividends from equity contributions previously made by PNMR and current earnings, determined on a rolling four quarter basis, without prior NMPRC approval. The Federal Power Act also imposes certain restrictions on dividends by public utilities. PNM also has other financial covenants that limit the transfer of assets, through dividends or other means, including a requirement to obtain approval of certain financial counterparties to transfer more than five percent of PNM’s assets. As of December 31, 2010, none of the numerical tests would restrict the payment of dividends from the retained earnings of PNMR, PNM, or TNMP. However, PNM would not be able to distribute amounts in excess of its retained earnings and TNMP would not be able to distribute amounts in excess of approximately $185 million without approval of regulators or financial counterparties. Other PNMR subsidiaries have no restricted net assets.
B-44
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
In addition, the ability of PNMR to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, the financial circumstances and performance, the NMPRC’s and PUCT’s decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of federal regulatory decisions, Congressional and legislative acts, and economic conditions in the United States. Conditions imposed by the NMPRC or PUCT, future growth plans and related capital requirements, and business considerations may also affect PNMR’s ability to pay dividends.
Preferred Stock
PNMR had no preferred stock outstanding prior to November 17, 2008, when it issued 477,800 shares of Series A convertible preferred stock in connection with the purchase obligation of the holder of PNMR’s private equity-linked units. See Note 6. The Series A convertible preferred stock is convertible into PNMR common stock in a ratio of 10 shares of common stock for each share of preferred stock. The Series A convertible preferred stock is entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The Series A convertible preferred stock is entitled to vote on all matters voted upon by common stockholders, except for the election of the Board. In the event of liquidation of PNMR, preferred holders would receive a preference of $0.10 per common share equivalent. After that preference, common holders would receive an equivalent liquidation preference per share and all remaining distributions would be shared ratably between common and preferred holders using the number of shares of common stock into which the Series A convertible preferred stock is convertible. The terms of the Series A convertible preferred stock result in it being substantially equivalent to common stock. Therefore, for earnings per share purposes the number of common shares into which the Series A convertible preferred stock is convertible is included in the weighted average number of common shares outstanding for periods after the Series A convertible preferred stock was issued. Similarly, dividends on the Series A convertible preferred stock are considered to be common dividends in the accompanying Consolidated Financial Statements.
PNM’s cumulative preferred shares outstanding bear dividends at 4.58% per annum. PNM preferred stock does not have a mandatory redemption requirement but may be redeemed, at PNM’s option, at 102% of the stated value plus accrued dividends. The holders of the PNM preferred stock are entitled to payment before the holders of common stock in the event of any liquidation or dissolution or distribution of assets of PNM. In addition, PNM’s preferred stock is not entitled to a sinking fund and cannot be converted into any other class of stock of PNM.
TNMP has no preferred stock outstanding. The number of authorized shares of TNMP cumulative preferred stock is 1 million shares.
(6) Financing
Impacts of Difficulties of Financial Institutions
Disruptions in the credit markets in 2008 and early 2009 had a significant adverse impact on a number of financial institutions, which resulted in certain institutions being restructured or formulating plans to be acquired by other financial institutions. This includes some financial institutions that are lenders under the PNMR Facility, PNM Facility, and Term Loan Agreement (which was terminated effective January 30, 2009) that are described below. Other than as described below, the flux in the banking industry has not impacted these credit agreements to date and the Company does not anticipate it will have a significant impact on TNMP’s 2009 Term Loan Agreement, the TNMP Revolving Credit Facility, the PNMR Facility, or the PNM Facility, in each case prior to their expirations.
LBB was a lender under the PNMR Facility and the PNM Facility. LBH, the parent of LBB, has filed for bankruptcy protection. Subsequent to the bankruptcy filing by LBH, LBB declined to fund a borrowing request under the PNMR Facility. A replacement bank has taken the place of LBB under the PNM Facility. In March 2010, the PNMR Facility was amended to remove LBB as a lender and reduce the total capacity under the PNMR Facility by $32.0 million. PNMR does not believe amending the PNMR Facility to remove LBB or the LBH bankruptcy will have a significant impact on the liquidity provided by the PNMR Facility.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
LBCS, another subsidiary of LBH, has also declared bankruptcy and was a counterparty to various energy transactions with First Choice and Optim Energy. First Choice had no receivables from LBCS, but as a result of the bankruptcy, First Choice terminated its contract effective September 24, 2008 and recognized a $3.9 million loss as settled purchase power contracts. These power supply contracts were replaced with other counterparties, which partially offset the $3.9 million loss. Optim Energy had a receivable from LBCS, which was written off in 2008. PNMR’s equity share of the write off was $0.6 million. The bankruptcy of LBCS is not expected to have a significant impact on future operations of the Company.
Financing Activities
On March 7, 2008, TNMP entered into a $150.0 million short-term bank loan agreement with two lenders. TNMP borrowed $150.0 million under this agreement on April 9, 2008 and used the proceeds to redeem the remaining $148.9 million of its 6.125% senior unsecured notes prior to the maturity date of June 1, 2008. The $150.0 million borrowing under this agreement was repaid in October 2008, through borrowing $150.0 million under the TNMP Facility described under Short-term Debt below.
On May 5, 2008, PNM entered into a $300.0 million unsecured delayed draw term loan facility (the “Term Loan Agreement”), which allowed PNM to borrow up to $300.0 million. This amount was reduced to $150.0 million on May 13, 2008 when PNM completed the offering of $350.0 million aggregate principal amount of senior unsecured notes. Upon the closing of the sale of PNM Gas described in Note 2, the Term Loan Agreement terminated. No borrowings were made under the Term Loan Agreement.
On May 8, 2008, PNM entered into a $100.0 million unsecured letter of credit facility pursuant to a reimbursement agreement (as amended, the “Reimbursement Agreement”), which allowed PNM to obtain standby letters of credit up to the aggregate amount of $100.0 million at any time prior to April 30, 2009. Upon the sale of PNM Gas on January 30, 2009, PNM voluntarily requested the termination of the Reimbursement Agreement. No letters of credit were issued under this arrangement.
On May 13, 2008, PNM issued $350.0 million aggregate principal amount of senior unsecured notes. The notes pay interest semi-annually at a rate of 7.95% per year and mature on May 15, 2018.
On May 15, 2008, TNMP entered into a credit agreement for the TNMP Facility, which had a stated maturity of May 13, 2009. The TNMP Facility provided TNMP with a revolving credit facility for up to $200.0 million. In connection with entering into the TNMP Facility, TNMP withdrew as a borrower under the PNMR Facility and is no longer a party under the PNMR Facility. Upon entering into the TNMP Revolving Credit Facility described below, the TNMP Facility was terminated.
On October 31, 2008, TNMP entered into a $100.0 million term loan credit agreement with two lenders (the “TNMP Bridge Facility”) to provide an additional source of funds to repay TNMP’s $167.7 million of senior unsecured notes that matured January 15, 2009. On January 14, 2009, TNMP borrowed $100.0 million under the TNMP Bridge Facility. On January 15, 2009, TNMP repaid the entire principal and interest due on the $167.7 million principal amount outstanding of 6.25% senior unsecured notes utilizing the proceeds from the TNMP Bridge Facility and inter-company borrowings from PNMR.
PNM had $300.0 million aggregate principal amount of senior unsecured notes that matured in September 2008. PNM repaid these notes by utilizing cash on hand and borrowing $240.0 million under the PNM Facility.
PNMR previously issued 4,945,000 6.75% publicly held equity-linked units. Each of these equity-linked units consisted of a purchase contract and a 5.0% undivided beneficial ownership interest in one of PNMR’s senior notes with a stated amount of $1,000, which corresponded to a $50.00 stated amount of PNMR’s senior notes. The senior notes were scheduled to mature in May 2010 (subject to the remarketing described below) and bore interest at a rate of 4.8% per year. The purchase contracts entitled their holders to contract adjustment payments of 1.95% per year on the stated amount of $50.00. Each purchase contract contained a mandatory obligation for the holder to
B-46
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
purchase, and PNMR to sell, at a purchase price of $50.00 in cash, shares of PNMR’s common stock on or before May 16, 2008. Generally, the number of shares each holder of the equity-linked units was obligated to purchase depended on the average closing price per share of PNMR’s common stock over a 20-day trading period ending on the third trading day immediately preceding May 16, 2008, with an adjusted maximum price of $32.08 per share and minimum price of $26.29 per share. In accordance with the terms of the equity-linked units, the senior note components were remarketed on May 16, 2008. The proceeds from the remarketed senior notes amounted to $247.3 million and were utilized by the holders of the equity-linked units to satisfy their obligations to purchase 9,403,412 shares of PNMR’s common stock for the same aggregate amount on May 16, 2008. In connection with the remarketing, PNMR sold an additional $102.7 million of senior notes with the same terms for a total offering of $350.0 million. The senior notes pay interest semi-annually at a rate of 9.25% per year and mature on May 15, 2015.
PNMR also had outstanding 4,000,000 privately held 6.625% equity-linked units. Each of these equity-linked units consisted of a purchase contract and a 2.5% undivided beneficial ownership interest in one of PNMR’s senior notes with a stated amount of $1,000, which corresponds to a $25.00 stated amount of PNMR’s senior notes. The senior notes aggregating $100.0 million were scheduled to mature in August 2010 (subject to the remarketing described below) and bore interest at the annual rate of 5.1%. The purchase contracts entitled the holder to quarterly contract adjustment payments of 1.525% per year on the stated amount of $25.00. Each purchase contract contained a mandatory obligation for the holder to purchase, and PNMR to sell, at a purchase price of $25.00 in cash, shares of PNMR’s common stock (or PNMR preferred stock in a ratio of one preferred share for each 10 shares of common stock) aggregating $100.0 million on November 17, 2008. Generally, the number of shares the holder was obligated to purchase depended on the average closing price per share of PNMR’s common stock over a 20-day trading period ending on the third trading day immediately preceding November 16, 2008, with a maximum price of $25.12 per share and minimum price of $20.93 per share. In accordance with the terms of the equity-linked units, PNMR attempted to remarket the senior note components in November 2008, but was unable to complete the remarketing. As provided in the agreement under which the equity-linked units were originally issued, the holder tendered the $100 million of senior unsecured notes to PNMR to satisfy its obligations under the purchase contracts. The holder chose to receive 477,800 shares of PNMR Series A convertible preferred stock on November 17, 2008 in lieu of 4,778,000 shares of PNMR common stock. See Note 5.
On January 5, 2009, PNMR commenced a tender offer whereby it offered to repurchase up to $150.0 million of its 9.25% senior unsecured notes due 2015. The tender offer requested the holders of the notes to submit the amount of notes they would be willing to sell to PNMR and at the price they would be willing to sell, within the range of 83% to 93% of face value, including additional compensation of 3% of face value for those holders that tendered their notes and did not withdraw them prior to the stated early participation date. Prior to expiration of the offer, $157.5 million of notes were tendered to PNMR for purchase. Under the applicable rules for this type of arrangement, PNMR was able to purchase $157.0 million of notes at the 93% cap price. On February 5, 2009, PNMR repurchased and retired these notes for $146.0 million plus accrued interest. On February 26, 2009, PNMR purchased an additional $0.4 million of the 9.25% senior unsecured notes at 93% of face value in a private transaction. PNMR recognized a pre-tax gain on these transactions of $7.3 million, net of related transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which is included in other income on the Consolidated Statements of Earnings (Loss).
On March 23, 2009, TNMP issued $265.5 million aggregate principal amount of 9.50% First Mortgage Bonds, due 2019, Series 2009A (the “Series 2009A Bonds”) at a price equal to 97.643% of their face value. The bonds bear interest at the rate of 9.50% per annum of their face value. TNMP may redeem some or all of the bonds at any time at a redemption price that reflects a make-whole provision, plus accrued interest. The Series 2009A Bonds are secured by a first mortgage on substantially all of TNMP’s property.
On March 25, 2009, TNMP entered into a $50.0 million loan agreement with Union Bank, N. A. (the “2009 Term Loan Agreement”). TNMP borrowed $50.0 million under this agreement on March 30, 2009. Borrowings under the 2009 Term Loan Agreement must be repaid by March 25, 2014 and are secured by $50.0 million aggregate principal amount of TNMP first mortgage bonds (the “Series 2009B Bonds”). Through hedging arrangements, TNMP has established fixed interest rates for the 2009 Term Loan Agreement of 6.05% for the first
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
three years and 6.30% thereafter. In January 2010, the hedging relationship was modified to reduce the fixed interest rate to 4.80% through March 25, 2012 and to 5.05% thereafter. The hedging obligations are also secured by the Series 2009B Bonds. The hedge is accounted for as a cash-flow hedge and its December 31, 2010 pre-tax fair value of $1.9 million is included in other current liabilities, except for $0.8 million included in other deferred credits, and in AOCI on the Consolidated Balance Sheets. Amounts reclassified from AOCI are included in interest charges. The fair value determination was made using Level 2 inputs under GAAP.
TNMP used the proceeds received from the Series 2009A Bonds and the 2009 Term Loan Agreement to repay the $100.0 million borrowed under the TNMP Bridge Facility, which then terminated, and the $150.0 million outstanding under the TNMP Facility. The remaining proceeds, after offering expenses, were used to reduce intercompany borrowings from PNMR.
On April 30, 2009, TNMP entered into the TNMP Revolving Credit Facility, a new $75.0 million revolving credit facility, and the existing TNMP Facility was terminated. Borrowings under the TNMP Revolving Credit Facility are secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds (the “Series 2009C Bonds”). The TNMP Revolving Credit Facility was scheduled to expire in April 2011. In December 2010, the TNMP Revolving Credit Facility was amended and restated, which extended its expiration to December 16, 2015.
On May 23, 2003, PNM issued $36.0 million of 4.00% PCRBs, which had a scheduled maturity in 2038, but were subject to mandatory repurchase and remarketing on July 1, 2009. PNM repurchased these PCRBs for $36.0 million on July 1, 2009 utilizing available cash balances and borrowings under the PNM Facility. PNM held these PCRBs (without legally canceling them) until December 1, 2009, on which date they were remarketed. The remarketed PCRBs bear interest at 6.25% and mature on January 1, 2038.
On February 10, 2010, PNM filed an application with the NMPRC requesting approvals and authorizations to refund up to $403.8 million of callable PCRBs issued by the City of Farmington, New Mexico and the Maricopa County, Arizona Pollution Control Corporation (the “prior bonds”) and to replace the prior bonds with new tax-exempt PCRBs. The proceeds from the prior bonds were used to finance a portion of the cost of certain pollution control systems, facilities, and related improvements at SJGS and PVNGS. The NMPRC approved PNM’s request on March 11, 2010. On June 9, 2010, $403.8 million of new PCRBs were sold by the City of Farmington, New Mexico and the Maricopa County, Arizona Pollution Control Corporation. The proceeds from the new PCRBs were utilized to retire the prior bonds, including those secured by PNM first mortgage bonds. The new PCRBs are collateralized by PNM senior unsecured notes, similar to PNM’s other PCRBs.
On October 21, 2010, PNM received an order from the NMPRC authorizing PNM to enter into a revolving credit facility of up to $400 million to replace the current PNM Facility; to increase the amount of PNM’s intercompany loan arrangements to $100 million; and to issue up to $250 million of additional senior unsecured notes. The authorizations remain in effect through March 31, 2012. PNM, after receiving the necessary PNM and PNMR board approvals, increased the amount of the PNM intercompany loan arrangement. PNM has not entered into any agreements with regard to the authorizations relating to the replacement of the PNM Facility or additional senior unsecured notes, nor does it have any arrangements or commitments concerning them. PNM is unable to predict if, or when, such financing arrangements would be consummated.
PNMR offers new shares of PNMR common stock through the PNMR Direct Plan. On July 15, 2009, PNMR began purchasing shares of its common stock on the open market rather than issuing additional shares to satisfy subscriptions under the PNMR Direct Plan. PNMR had offered new shares of its common stock through an equity distribution agreement, which was terminated in July 2009. In 2009 and 2008, PNMR issued 93,328 and 221,517 shares under these plans, as well as 48,202 and 92,224 shares under the ESPP (see Note 13).
In August 2009, PNMR filed an automatically effective shelf registration statement with the SEC for common stock issuable under the PNMR Direct Plan and in April 2008, PNMR filed an automatically effective shelf registration statement for debt securities. These registration statements expire three years from the date of filing and can be amended at any time to include additional securities of PNMR. As a result, these shelf registration statements have unlimited availability, subject to certain restrictions and limitations.
B-48
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
In April 2008, PNM filed a shelf registration statement for the issuance of $750.0 million of senior unsecured notes that was declared effective on April 29, 2008. As of February 18, 2011, PNM had $600.0 million of remaining unissued securities registered under this and a prior shelf registration statement.
Borrowing Arrangements Between PNMR and its Subsidiaries
PNMR has one-year intercompany loan agreements with its subsidiaries. Individual subsidiary loan agreements vary in amount from $20.0 million to $100.0 million and have either reciprocal or non-reciprocal terms. Interest charged to the subsidiaries is equivalent to interest paid on the PNMR Facility. On January 8, 2009, TNMP entered into an agreement for an additional $50.0 million borrowing from PNMR that was subordinated to the TNMP Bridge Facility described above. The agreement for additional borrowing terminated in April 2009. As of December 31, 2010 and 2009, TNMP had outstanding borrowings of $1.2 million and $23.5 million from PNMR. At February 18, 2011, TNMP has borrowings of $0.1 million from PNMR.
Short-term Debt
At December 31, 2009, PNMR and PNM had revolving credit facilities for borrowings up to $600.0 million under the PNMR Facility and $400.0 million under the PNM Facility that primarily expire in August 2012. As discussed above, in March 2010, the PNMR Facility was amended to remove LBB as a lender and reduce the total capacity under the PNMR Facility by $32.0 million to $568.0 million. In addition to the reduction in the PNMR Facility related to LBB, the PNMR Facility and the PNM Facility were reduced by $26.0 million and $14.0 million in August 2010 and will reduce by an additional $25.0 million and $18.0 million in August 2011 according to their terms. In addition, PNMR has a local line of credit amounting to $5.0 million that expires in August 2011 and PNM had a local line of credit for $5.0 million that was allowed to expire in August 2010. TNMP has a revolving credit facility for borrowings up to $75.0 million under the TNMP Revolving Credit Facility that expires in December 2015. PNMR and PNM had commercial paper programs under which they could have issued up to $400.0 million and $300.0 million of commercial paper. No commercial paper has been issued since March 11, 2008 and the programs were terminated on July 2, 2009.
At December 31, 2010, the weighted average interest rate was 1.51% for the PNMR Facility, 0.91% for the PNM Facility. The TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2010. Short-term debt outstanding consists of:
* This line of credit was allowed to expire in August 2010.
In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $49.8 million, $49.7 million, and $0.3 million at December 31, 2010 that reduce the available capacity under their respective revolving credit facilities.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
At February 18, 2011, PNMR, PNM, and TNMP had $468.3 million, $116.8 million, and $74.7 million of availability under their respective revolving credit facilities and local lines of credit, including reductions of availability due to outstanding letters of credit. Total availability at February 18, 2011, on a consolidated basis, was $659.8 million for PNMR. At February 18, 2011, PNMR, PNM, and TNMP had invested cash of $7.9 million, $10.6 million, and none.
Long-Term Debt
Information concerning long-term debt outstanding is as follows:
B-50
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Interest Rate Swaps
PNMR entered into three fixed-to-floating interest rate swaps with an aggregate notional principal amount of $150.0 million, which matured September 15, 2008. Under these swaps, PNMR received a 4.40% fixed interest payment on the notional principal amount on a semi-annual basis and paid a floating rate equal to the six month LIBOR plus 0.5815% on the notional amount. The swaps were accounted for as fair-value hedges.
See Financing Activities above for information concerning a TNMP interest rate swap.
In January 2010, PNM entered into a one-year floating-to-fixed interest rate swap with a notional amount of $100.0 million. The effect of this swap was to convert $100.0 million of borrowings under the PNM Facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.245% through January 14, 2011. This swap was accounted for as a cash-flow hedge. At December 31, 2010, this swap had a value of less than $0.1 million.
New Mexico Energy Investments LLC
In 2002, PNM entered into an agreement with FPL to develop a 200 MW wind generation facility in New Mexico. PNM began receiving commercial power from the project in June 2003. FPL owns and operates the New Mexico Wind Energy Center, which consists of 136 wind-powered turbines on a site in eastern New Mexico. PNM has a PPA to purchase all the power generated by the New Mexico Wind Energy Center for 25 years.
PNMR entered into purchase and sale agreement with ESI Northeast Energy LP, Inc., an affiliate of FPL, and acquired an interest in the New Mexico Wind Energy Center by the purchase of a 1% membership interest in New Mexico Energy Investments, LLC for $21.2 million. At closing, PNMR paid $6.2 million in cash and issued a promissory note for $15.0 million at an annual interest rate of 6%. PNMR makes an annual payment of $2.7 million for principal and interest until the final maturity date of the promissory note on December 31, 2013. PNMR receives state and federal tax benefits from its ownership interest. PNMR’s ownership interest terminates on December 31, 2013.
(7) Lease Commitments
PNMR leases office buildings and other equipment under operating leases. PNM leases interests in Units 1 and 2 of PVNGS, an interest in the EIP transmission line, office buildings, vehicles, and other equipment under operating leases. TNMP leases radio tower antenna space, office buildings, vehicles, and other equipment under operating leases.
PNM has a PPA for the entire output of Delta, a gas-fired generating plant in Albuquerque, New Mexico, which is classified as an operating lease with imputed annual lease payments of $6.0 million. See Note 9 for additional information about the Delta operating lease. PNM also had a PPA for 40 MW of capacity from Pyramid Unit 4, which was classified as an operating lease and was sold in 2008. See Note 8.
A portion of PVNGS Unit 2 had been leased by PNM from another subsidiary of PNMR. In July 2009, the leased assets were transferred to PNM and became subject to rates established by the NMPRC. See Note 17. The table below includes lease expense for PNM of $5.4 million in 2009 and $9.6 million in 2008 paid to that subsidiary of PNMR. After the July 2009 transfer, PNM stopped recognizing lease expense for the transferred assets.
Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has recently completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation, and has no significant rights-of-way that will expire before 2020. On October 20, 2010, PNM and the Navajo Nation entered into an extension/renewal agreement covering all rights-of-way granted by the Navajo Nation to PNM. The existing rights-of-way had varying expiration dates and all were extended to April 7, 2030. PNM is obligated under the agreement to pay the Navajo Nation 20 annual payments of $6.0 million each beginning in 2010. The annual payments are subject to adjustment each year based on the Consumer Price Index. In the event of early termination or
B-51
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
cancellation under the agreement, any remaining payments become due. The rights-of-way agreements are accounted for as operating leases.
Operating lease expense was:
The above amounts reflect the total amount of expense for the lease payments PNM makes under the PVNGS and EIP leases. As discussed under Investments in Note 1, the PVNGS Capital Trust, which is consolidated by PNM, acquired the lessor notes that were issued by the PVNGS lessors and PNM acquired the remaining lessor note issued by the remaining EIP lessor. Of the total annual payments of $69.1 million made by PNM under the PVNGS and EIP leases, $56.3 million in 2010, $55.0 million in 2009, and $50.0 million in 2008 was returned in cash to PNM in the form of principal and interest payments on the lessor notes and through its ownership of the PVNGS Unit 2 leased assets.
Future minimum operating lease payments at December 31, 2010 shown below have been reduced by PNM’s lease payments for amounts that will be returned to PNM on the lessor notes, which amounts vary but are approximately $56 million annually thru 2011 reducing thereafter to approximately $33 million annually in 2015:
The PVNGS leases, which expire in 2015 and 2016, contain options to renew the leases at a fixed price or to purchase the property for fair market value at the end of the lease terms. PNM must give notice to the lessors if it wishes to exercise, or not exercise, these options at dates, varying by lease, through January 15, 2014. PNM is exploring its alternatives. Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the equity participants, and take title to the leased interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2010, PNM could have been required to pay the equity participants up to approximately $177.3 million. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. If PNM exercises its renewal options under the leases, the amount that would be payable to equity participants under the circumstances described above would increase to the fair market value as of the renewal date.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(8) Fair Value of Derivative and Other Financial Instruments
Energy Related Derivative Contracts
Overview
The Company is exposed to certain risks relating to its ongoing business operations. The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy or fuel used to generate electricity, or to manage anticipated generation capacity in excess of forecasted demand from existing customers. Substantially all of the Company’s energy related derivative contracts manage commodity risk and the Company does not currently engage in speculative trading which it ceased in the second quarter of 2008.
Commodity Risk
Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. The Company routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the risk of market fluctuations in wholesale portfolios. The Company monitors the market risk of its commodity contracts using VaR and GEaR calculations to maintain total exposure within management-prescribed limits.
PNM is required to meet the demand and energy needs of its retail and wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the requirements of customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM would be exposed to market risk if its generation capabilities were to be disrupted or if its retail load requirements were to be greater than anticipated. If all or a portion of the net open contract position were required to be covered as a result of the aforementioned unexpected situations, commitments would have to be met through market purchases.
First Choice is responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers are negotiated with each customer. As a result, changes in purchased power costs and retail customer load requirements can affect First Choice’s margins and operating results. First Choice is exposed to market risk to the extent that it has not hedged fixed price load commitments or to the degree that market price movements affect customer retention, customer additions or customer attrition. Additionally, volumetric fluctuations in First Choice retail load requirements due to weather or other conditions may subject First Choice to market risk. First Choice’s strategy is to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins.
Accounting for Derivatives
Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify for the normal sales and purchases exception or for which the normal sales and purchases exception are not elected are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Derivatives that meet the normal sales and purchases exception are not marked to market but rather recorded in results of operations when the underlying transactions settle.
For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the
B-53
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. Based on market prices at December 31, 2010, after-tax gains of $0.1 million for PNMR and zero for PNM would be reclassified from AOCI into earnings during the next twelve months. However, the actual amount reclassified into earnings will vary due to future changes in market prices. As of December 31, 2010, the Company is not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges.
The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as either economic hedges or trading transactions. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. Trading transactions include speculative transactions, which the Company ceased in 2008. Also included in this category are transactions that lock in margin with no forward market risk and are not economic hedges; changes in the fair value of these transactions are reflected on a net basis in operating revenues.
Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of the Company’s own credit standing. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.
The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements. At December 31, 2010 and 2009, amounts recognized for the legal right to reclaim cash collateral were $3.4 million and $4.2 million for PNMR and $3.0 million and $1.4 million for PNM. In addition, at December 31, 2010 and 2009, amounts posted as cash collateral under margin arrangements were $32.0 million and $8.6 million for PNMR and $2.1 million and $1.2 million for PNM. PNMR and PNM had no obligations to return cash collateral at December 31, 2010 and 2009. Cash collateral amounts are included in other current assets on the Consolidated Balance Sheets.
B-54
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following tables do not include activity related to PNM Gas. See Note 23.
Commodity Derivatives
Commodity derivative instruments are summarized as follows:
In 2007, First Choice entered into a series of forward trades that arbitraged basis differentials among certain ERCOT delivery zones. During the three months ended March 31, 2008, these trades were negatively affected by extreme transmission congestion within the ERCOT market. This congestion resulted in historically high basis differences between the various delivery zones. As a result, in the first quarter of 2008, First Choice recorded a total pre-tax loss of $47.1 million in the trading margins from these speculative trades that is reflected in electric revenues. Because of continued market volatility and the concern that the forward basis market would continue to deteriorate, First Choice decided to end any further speculative trading and flattened remaining speculative positions. The PNMR trading transactions column of the above table reflects balances related to the flattened speculative positions of First Choice at December 31, 2009. These positions settled in 2010 without significant additional cost. As discussed in Note 17, on April 20, 2010, PNM received NMPRC approval of a hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. At December 31, 2010, $0.6 million of current assets related to this plan are included as economic hedges above and are recorded as regulatory liabilities.
B-55
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.
Commodity contract volume positions are presented in Decatherms for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:
In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral.
The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not
B-56
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.
Sale of Wholesale Contracts
In January 2008, PNM entered into an agreement to sell certain wholesale power, natural gas, and transmission contracts. These contracts represented a significant portion of the wholesale activity portfolio of PNM Electric, and included several long-term sales and purchase power agreements. Included in the sales agreement were the Pyramid operating lease and certain transmission agreements, which were not considered derivative instruments. In connection with an amendment to GAAP, pre-tax gains on these contracts amounting to $17.2 million were recorded as an adjustment to January 1, 2008 retained earnings. On June 19, 2008 PNM completed the sale for $6.1 million and recognized gains of $5.1 million.
Sale of Power from PVNGS Unit 3
In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW. Under two of the contracts, PNM sold 90 MW of firm capacity and energy. Under the third contract, PNM sold 45 MW of unit contingent capacity and energy. The term of the contracts was May 1, 2008 through December 31, 2010. Under the two firm contracts, the two buyers made prepayments of $40.6 million and $30.0 million. These amounts were recorded as deferred revenue and were amortized over the life of the contracts. At December 31, 2009, $29.5 million was included in other current liabilities related to these contracts. The prepayments received under the firm contracts, as well as required subsequent monthly payments on them, are shown as a financing activity in the Consolidated Statement of Cash Flows as required by GAAP. The firm contracts were considered energy derivatives and a loss of $4.8 million was recognized at inception. The firm contracts were accounted for as cash flow hedges and changes in fair value were included in AOCI. The contingent contract was accounted for as a normal sale. Beginning January 1, 2011, PNM is selling its 135 MW interest in PVNGS Unit 3 daily at market prices. PNM has established fixed rates for the majority of these sales through the end of 2011 through hedging arrangements that are accounted for as economic hedges.
Non-Derivative Financial Instruments
The carrying amounts reflected on the Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value.
Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS. The NDT holds equity and fixed income securities. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. PNMR and PNM do not have any unrealized losses on available-for-sale securities.
B-57
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold.
Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments, including the EIP lessor note.
The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.
At December 31, 2010, the available-for-sale and held-to-maturity debt securities had the following final maturities:
B-58
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The carrying amount and fair value of held-to-maturity debt securities and other non-derivative financial instruments (including current maturities) are:
The fair value of long-term debt shown above was primarily determined using quoted market values, as were certain items included in other investments. To the extent market values were not available, fair value was determined by discounting the cash flows for the instrument using quoted interest rates for comparable instruments.
Other Fair Value Disclosures
The Company determines the fair values of its derivative and other instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.
For NDT investments, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. Fair values of Level 3 commodity derivatives are determined in a manner similar to those in Level 2, but are at a lower level in the hierarchy due to low transaction volume or market illiquidity that significantly limit the availability of observable market data.
Derivatives and Investments
The fair values of derivatives and investments that are recorded at fair value on the Consolidated Balance Sheets are as follows:
B-59
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
B-60
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(1) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of less than $0.1 million for PNMR and zero for PNM at December 31, 2010 and $0.1 million for PNMR and zero for PNM at December 31, 2009. There were no transfers between levels for the twelve months ended December 31, 2010.
A reconciliation of the changes in Level 3 fair value measurements is as follows:
(1) Includes fair value reversal of contracts settled, unearned and prepaid option premiums received and paid during the period for contracts still held at end of period.
Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:
B-61
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Investments Held by Employee Benefit Plans
As discussed in Note 12, PNM and TNMP have trusts that hold investment assets for their pension and other postretirement benefit plans. The fair value of the assets held by the trusts impacts the determination of the funded status of each plan, but the assets are not reflected on the Consolidated Balance Sheets. Both the PNM Pension Plan and the TNMP Pension Plan hold units of participation in the PNM Resources, Inc. Master Trust (the “PNMR Master Trust”), which was established for the investment of assets of the pension plans. Fair value of alternative investments is determined based on net asset value as reported by fund managers.
The fair values of investments held by the employee benefit plans are as follows:
B-62
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
B-63
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The fair values of investments in the PNMR Master Trust are as follows:
B-64
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
A reconciliation of the changes in Level 3 fair value measurements is as follows:
Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:
Level 3 Fair Value Assets and Liabilities
(9) Variable Interest Entities
On January 1, 2010, the Company adopted an amendment to GAAP that changes how an enterprise evaluates and accounts for its involvement with variable interest entities. This amendment modifies the determination of the primary beneficiary of a variable interest entity by focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. The amendment also requires continual reassessment of the primary beneficiary of a variable interest entity and increases disclosure requirements. The adoption of this amendment did not change how the Company accounts for its existing arrangements with variable interest entities and the disclosures presented below reflect the requirements of the amendment.
B-65
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
On April 18, 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. The term of the PPA is for 20 years beginning June 1, 2008, with the full output of the plant estimated to be 145 MW. During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed O&M and capacity charges in addition to variable O&M charges under this PPA. For the year ended December 31, 2010, 2009, and 2008, PNM paid $17.9 million, $17.7 million, and $9.6 million for fixed charges and $1.1 million, $0.5 million, and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.
PNM has evaluated the accounting treatment of this arrangement and concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. The significant factors considered in reaching that conclusion are that PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. As the primary beneficiary, PNM has consolidated the entity in its financial statements beginning on the commercial operations date. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest. PNM did not consolidate Valencia prior to May 30, 2008 since PNM had no financial risk.
Summarized financial information for Valencia since May 30, 2008 is as follows:
B-66
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. PNM has options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes, aggregate $118.5 million over the remaining terms of the leases. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of December 31, 2010, PNM could have been required to pay the beneficial owners up to approximately $177.3 million, which would result in PNM taking ownership of the leased assets and termination of the leases. PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its consolidated balance sheets related to the trusts other than the accrual of lease payments between the scheduled payment dates, which were $26.0 million at December 31, 2010 and 2009 and included in other current liabilities on the Consolidated Balance Sheets. See Note 7.
PNM has evaluated the PVNGS lease arrangements and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since it appears reasonably likely that the operating licenses for the plants will be extended for twenty years through 2045 for Unit 1 and 2046 for Unit 2; PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease term, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so does not significantly influence the day to day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from anticipated carbon legislation or regulation.
PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered into prior to December 31, 2003 and PNM has been unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. PNM makes fixed and variable payments to Delta under the PPA. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. For the years ended December 31, 2010, 2009, and 2008, PNM incurred fixed payments of $6.0 million, $6.4 million, and $9.0 million and variable payments of $0.4 million, $0.4 million, and $0.8 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of December 31, 2010, aggregated $57.1 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be
B-67
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
quantified since the amounts are based on how much the generating plant is in operation. PNM has no other obligations or commitments with respect to Delta.
(10) Earnings Per Share
In accordance with GAAP, dual presentation of basic and diluted earnings (loss) per share has been presented in the Consolidated Statements of Earnings (Loss) of PNMR. Information regarding the computation of earnings (loss) per share is as follows:
(1) Due to losses in the years ended December 31, 2010 and 2008, no potentially dilutive securities are reflected in the average number of common shares used to compute earnings (loss) per share since any impact would be anti-dilutive. At December 31, 2010, PNMR’s potentially dilutive securities consist of all options and restricted stock (see Note 13).
B-68
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(11) Income Taxes
PNMR
PNMR’s income taxes (benefit) from continuing operations consist of the following components:
PNMR’s provision for income taxes from continuing operations differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
B-69
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The components of PNMR’s net accumulated deferred income tax liability were:
The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
B-70
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM
PNM’s income taxes (benefit) from continuing operations consist of the following components:
PNM’s provision for income taxes from continuing operations differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
B-71
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The components of PNM’s net accumulated deferred income tax liability were:
The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
TNMP
TNMP’s income taxes from continuing operations consist of the following components:
B-72
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
TNMP’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the periods shown. The differences are attributable to the following factors:
The components of TNMP’s net accumulated deferred income tax liability at December 31 were:
The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:
B-73
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
GAAP requires that the Company recognize only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the taxing authority. A reconciliation of unrecognized tax benefits (expenses) is as follows:
Included in the balance at December 31, 2010 are $3.5 million and $0.2 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate for PNMR and PNM. None of TNMP’s unrecognized tax benefits at December 31, 2010 would affect the effective tax rate if recognized. The Company believes that it is reasonably possible that approximately $0.1 million of PNMR’s unrecognized tax expenses, $0.1 million of PNM’s unrecognized tax expenses, and $0.5 million of TNMP’s unrecognized tax benefits will be reduced or settled in 2011 as a result of the conclusion of income tax examinations.
Estimated interest income related to refunds the Company expects to receive is included in Other Income and estimated interest expense and penalties related to potential cash settlements are included in Interest Expense in the Consolidated Statements of Earnings (Loss). Interest income (expense) related to income taxes is as follows:
Accumulated accrued interest receivable (payable) related to income taxes is as follows:
The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2003 are closed to examination by either federal or state taxing authorities. Tax year 2003 is open for examination only for certain items. Tax year 2004 is closed to examination by federal taxing authorities, but open for some states. Other tax years are open to examination by federal and state taxing authorities. At December
B-74
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
31, 2010, the Company has $138.8 million of federal net operating loss carryforwards that expire in 2030 and $21.1 million of federal tax credit carryforwards that expire beginning in 2021.
(12) Pension and Other Postretirement Benefits
PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (“PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. As discussed in Note 2, PNM completed the sale of its gas operations to NMGC on January 30, 2009. PNM retained the obligations under the defined benefit pension plans and executive retirement plans relating to employees that transferred to NMGC upon the sale. NMGC assumed the postretirement medical and dental obligations for the transferred employees. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. In addition, PNM receives a regulated return on the amount it has funded for its pension plan in excess of the periodic cost or income.
Participants in the PNM Plans include eligible employees and retirees of PNMR and other subsidiaries of PNMR. Participants in the TNMP Plans include eligible employees and retirees of TNMP, First Choice and other subsidiaries of TNP. The PNM pension plan was frozen at the end of 1997 with regard to new participants, salary levels and benefits. Through December 31, 2007, additional credited service could be accrued under the PNM pension plan up to a limit determined by age and service. The TNMP pension plan was frozen at December 31, 2005 with regard to new participants, salary levels and benefits.
GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur. Such changes are reported in other comprehensive income.
GAAP also requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs will ultimately be included as pension and postretirement benefits expenses in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP records the costs as a regulatory asset or regulatory liability.
The Company has in place, for the PNM Plans and TNMP Plans, a policy that defines the investment objectives, establishes performance goals of the asset managers and provides procedures for the manner in which investments are to be reviewed. The plans implement investment strategies to achieve the following objectives:
•
Maximize the return on assets, commensurate with the risk that the Corporate Investment Committee deems appropriate to: meet the obligations of the pension plans and other postretirement benefits plans; minimize the volatility of expense; and account for contingencies; and
•
Generate a rate of return for the total portfolio that equals or exceeds the actuarial investment rate assumption.
Management is responsible for the determination of the asset target mix and the expected rate of return. The target asset allocations are determined based on consultations with external investment advisors. The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility. For the PNM Plans and TNMP Plans, the market-related value of assets is equal to the prior year’s market related value of assets adjusted for contributions, benefit payments and investment gains and losses that lie within a corridor of plus or minus 4.0% around the expected return on market value. Gains and losses that lie outside the corridor are
B-75
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
amortized over five years. This market-related valuation recognizes the portion of return that is outside the range over a five-year period from the year in which the return occurs. As such, the future value of assets will be impacted as previously deferred returns are recorded.
In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 were signed into law. This legislation expands health care coverage to individuals and will largely be funded through tax increases. One provision that will impact certain companies significantly is the elimination of the tax deductibility of the Medicare Part D subsidy. The Company does not expect any significant impact on its financial statements as a result of the legislation.
In June 2010, the Preservation of Access to Care for Medicare Beneficiaries and Pension Relief Act was enacted. The act contains a provision designed to lower required contributions to pension plans by offering extended amortization methods for shortfalls resulting from recent losses in asset market value. The Company’s pension plans can elect this relief for losses occurring in any two years within the 2009-2011 periods. The Company has elected this relief for year 2009 and 2010 for the PNM Plan and 2010 and 2011 for the TNMP Plan. The impacts of this legislation have been reflected in estimated future contributions to the pension plans.
Pension Plans
For defined benefit pension plans, including the executive retirement plans, the PBO represents the actuarial present value of all benefits attributed by the pension benefit formula to employee service rendered prior to that date using assumptions regarding future compensation levels. The accumulated benefit obligation represents the PBO without considering future compensation levels. Since the plans are frozen, the PBO and accumulated benefit obligation are equal. The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:
B-76
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2010.
The following table presents the components of net periodic benefit cost (income) recognized in the Consolidated Statements of Earnings (Loss):
B-77
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The change in discount rate resulted in an increase in the PNM and TNMP PBOs of $41.5 million and $5.1 million at December 31, 2010. In addition, the PNM and TNMP PBOs increased by $9.0 million and $0.5 million due to changes in demographics and by $0.9 million and $0.1 million due to changes in the mortality assumption. Changes in the interest crediting assumption resulted in a $0.7 million decrease in the TNMP PBO. These changes are reflected as actuarial (gain) loss above. In 2009, the actuarial (gain) loss included changes in demographics of $9.6 million associated with early retirement of PNM Gas employees transferred to NMGC. Although the transferred employees did not result in a significant reduction in the expected years of future service of present employees covered by the pension plan and, therefore, under GAAP, a curtailment does not occur, GAAP required measuring the effects of the reduction in the work force in the same manner as a curtailment for purposes of determining the gain or loss on the sale of gas operations. This $9.6 million, which is not included in net periodic benefit (income) cost above, was recognized as a loss reducing the gain on the sale of PNM Gas.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the PBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates) and current and target asset allocations between asset categories. The expected long-term rate of return assumption for the PNM and TNMP pension plans compares to the actual return of 14.7% and 14.6% for the year ended December 31, 2010. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2011 net periodic cost to increase $4.4 million and $0.6 million (analogous changes would result from a 1% increase).
The Company’s overall pension investment strategy is to invest in a portfolio that is diversified by asset class and style strategies. The targeted asset allocation is 57.5% equities, 22.5% fixed income, and 20% alternative investments. The objective is over the long term to achieve the actuarial rate of return. Equity securities primarily include investments in large, mid, and small cap domestic companies. The pension has a targeted allocation of 10% to equities of companies domiciled primarily in developed countries outside of the United States. This category comprises of actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries and government securities. Fixed income mutual funds are funds that attempt to match the duration of the pension liability. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. These funds are structured as multi-strategy multi-manager fund-of-funds to achieve a diversified position in these asset classes. The plans have invested in funds that have investments in a diversified portfolio of assets including commercial property and multi-family housing. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, venture capital and buy-outs. See Note 8 for fair value information concerning assets held by the pension plans.
B-78
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following pension benefit payments are expected to be paid:
There was a significant decline in the general price levels of marketable equity securities held by the pension plans in late 2008 and in early 2009. Such declines have been partially offset by price increases through 2010. PNM and TNMP began making contributions to the pension plans in 2010. Based on current law and estimates of portfolio performance, PNM anticipates making contributions to its pension plan trust of approximately $40.9 million in 2011 and a total of $190.0 million for 2012-2015 and TNMP anticipates making contributions to its pension plan trust of approximately $1.1 million in 2010 and a total of $6.5 million for 2012-2015. These anticipated contributions were developed using a probabilistically weighted average discount rate of 5.20% for the PNM plan and 5.13% for the TNMP plan to determine the projected benefit obligation under the pension plans. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate.
Other Postretirement Benefit Plans
For postretirement benefit plans, the APBO is the actuarial present value as of a date of all future benefits attributed under the terms of the postretirement benefit plan to employee service rendered to that date.
The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:
B-79
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
As a result of the sale of gas operations on January 30, 2009, $15.7 million of the APBO liability was transferred to the purchaser and PNM recognized unamortized prior service costs resulting in a $2.9 million gain, which is not included in net periodic benefit cost below.
The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2010.
The following table presents the components of net periodic benefit cost recognized in the Consolidated Statements of Earnings (Loss):
B-80
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.
At December 31, 2010, the assumed discount rate for determining the APBO was determined based on a review of long-term high-grade bonds and management’s expectations. The change in discount rate resulted in an increase in the PNM and TNMP APBO of $7.4 million and $0.9 million. In addition, the PNM APBO decreased $20.1 million as a result of updated claims assumptions and recent retiree experience. The PNM and TNMP APBO also decreased by $6.4 million and $1.0 million due to changes in demographic experience.
The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the APBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates) and current and target asset allocations between asset categories. The expected long-term rate of return assumption for the PNM and TNMP postretirement benefit plans compares to the actual return of 17.9% and 16.8% for the year ended December 31, 2010. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2011 postretirement benefit cost to increase $0.6 million and $0.1 million (analogous changes would result from a 1% increase).
TNMP’s exposure to cost increases in the postretirement benefit plan is minimized by a provision that limits TNMP’s share of costs under the plan. Costs of the plan in excess of the limit are wholly borne by the participants. TNMP reached the cost limit at the end of 2001. As a result, a one-percentage-point change in assumed health care cost trend rates would have no effect on either the net periodic expense or the year-end APBO.
The following table shows the assumed health care cost trend rates:
B-81
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:
The Company’s other postretirement benefit plans invest in a portfolio that is diversified by asset class and style strategies. The other postretirement benefit plans use the same pension fixed income and equity investment managers and utilize the same overall investment strategy as described above for the pension plans, except there is no allocation to alternative investments. The other postretirement benefit plans have an asset allocation of 70% equities and 30% fixed income. See Note 8 for fair value information concerning assets held by the other postretirement benefit plans.
The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:
PNM expects to make contributions totaling $2.5 million to the PNM postretirement benefit plan in 2011. TNMP expects to make contributions totaling $0.3 million to the TNMP postretirement benefit plan in 2011.
Executive Retirement Programs
For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:
B-82
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2010.
The following table presents the components of net periodic benefit cost recognized in the Consolidated Statements of Earnings (Loss):
The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.
B-83
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The change in discount rate resulted in an increase in the PNM and TNMP PBO of $1.0 million and less than $0.1 million at December 31, 2010. The PNM PBO also includes a decrease due to demographic experience of $0.5 million.
The following executive retirement plan payments, which reflect expected future service, are expected:
Other Retirement Plans
PNMR sponsors a 401(k) defined contribution plan for eligible employees, including those of its subsidiaries. PNMR’s contributions to the 401(k) plan consist of a discretionary matching contribution equal to 75% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. PNMR also makes a non-matching contribution ranging from 3% to 10% of eligible compensation based on the eligible employee’s age.
PNMR also provides executive deferred compensation benefits through an unfunded, non-qualified plan. The purpose of this plan is to permit certain key employees of PNMR who participate in the 401(k) defined contribution plan to defer compensation and receive credits without reference to the certain limitations on contributions. In December of 2008, an earlier version of this plan, which was frozen in 2004, was merged into this plan. Effective January 1, 2009, PNMR allowed eligible employees to save on an after-tax basis.
A summary of expenses for these other retirement plans is as follows:
(13) Stock-Based Compensation Plans
PNMR has various types of stock-based compensation programs, including stock options, restricted stock and performance shares granted under the Performance Equity Plan (“PEP”). All stock-based compensation is granted through stock-based employee compensation plans maintained by PNMR. Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans.
B-84
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Performance Equity Plan
The PEP provides for the granting of non-qualified stock options, restricted stock rights, performance shares, performance units, and stock appreciation rights to officers, key employees, and non-employee board members. Generally, the awards vest ratably over three years from the grant date of the award. However, plan provisions provide that upon retirement, participants become 100% vested in stock awards. The total number of shares of PNMR common stock subject to all awards under the PEP may not exceed 12.34 million, subject to adjustment under certain circumstances defined in the PEP. The number of shares of PNMR common stock subject to the grant of restricted stock rights, performance shares and units and stock appreciation rights is limited to 1.56 million shares. Re-pricing of stock options is prohibited unless specific shareholder approval is obtained.
Source of Shares
The source of shares for exercised stock options, delivery of vested restricted stock, and performance shares is shares acquired on the open market, rather than newly issued shares.
Accounting for Stock Awards
The unearned stock-based compensation related to stock options and restricted stock awards is being amortized to compensation expense over the requisite vesting period, which is generally equally over three years. However, compensation expense for stock options and restricted stock awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized over the vesting period. The Company records compensation cost for performance stock awards based upon periodic estimates of the levels that the performance targets will be achieved.
Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2010, 2009, and 2008 was $2.2 million, $2.2 million, and $3.3 million. Of the total expense, $1.5 million, $1.4 million, and $2.4 million was charged to PNM and $0.4 million, $0.5 million, and $0.6 million was charged to TNMP.
PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options and a tax deduction for increases in the value of equity instruments issued under stock-based payment arrangements. PNMR’s Consolidated Statements of Cash Flows presentation reports the tax benefits from the exercise of stock options and stock-based payments as financing cash flows.
At December 31, 2010, PNMR had $2.6 million of unrecognized compensation expense related to stock-based payments that is expected to be recognized over a weighted-average period of 1.9 years.
Stock Options
The Company uses the Black-Scholes option pricing model to estimate the fair value of stock-based awards with the following weighted-average assumptions:
The assumptions above are based on multiple factors, including historical exercise patterns of employees in relatively homogeneous groups with respect to exercise and post-vesting employment termination behaviors,
B-85
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
expected future exercising patterns for these same homogeneous groups and both the implied and historical volatility of PNMR’s stock price.
The following table summarizes activity in stock option plans:
(1) At December 31, 2010, the exercise price of 2,573,408 outstanding stock options is greater than the closing price of PNMR common stock on that date so those options have no intrinsic value.
(2) Includes shares available for grants of restricted stock.
The following table provides additional information concerning stock option activity:
Restricted Stock and Performance Shares
The PEP allows for the issuance of restricted stock awards. As noted above, “restricted stock” is the name of these awards provided for in the PEP and refers to awards of stock subject to vesting. It does not refer to restricted shares with contractual post-vesting restrictions as defined in GAAP. Compensation expense for restricted stock and performance stock awards was determined based on the market price of PNMR stock on the date of grant reduced by the present value of future dividends, which will not be received during the vesting period, applied to the total number of shares that were anticipated to fully vest with the following weighted-average assumptions:
B-86
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The following table summarizes nonvested restricted stock activity for the year ended December 31, 2010:
The following table provides additional information concerning restricted stock activity:
During 2009 and 2010, the Company issued performance share agreements to certain executives that are based upon the Company achieving specified performance targets for those respective years. In addition during 2009, the Company issued performance share agreements that are based upon achieving specific performance targets for the period 2009 through 2011. The determination of the number of shares ultimately issued depends on the levels at which the performance criteria are achieved and cannot be determined until after the performance periods end. For the targets based only on 2009 performance, the optimal level was attained resulting in 102,375 shares being awarded in 2010, which will vest through 2013 and are included in the number of shares granted in the above table. Excluded from the above table are maximums of 94,681 shares for the targets based only on 2010 performance and 37,538 shares for the targets based on the period 2009 through 2011 performance that would be issued if all performance criteria are achieved and all executives remain eligible.
ESPP
PNMR terminated the ESPP effective June 30, 2009. Under the ESPP, employees were allowed to purchase shares of PNMR’s common stock at a 5% discount from the market price. The ESPP was not considered to be a compensatory plan. See Note 6.
(14) Construction Program and Jointly-Owned Electric Generating Plants
Joint Projects
PNMR’s construction expenditures for 2010 were $281.5 million. TNMP does not participate in the ownership or operation of any generating plants, but incurred construction expenditures of $41.0 million during 2010.
B-87
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM’s construction expenditures for 2010 were $226.8 million, including expenditures on jointly-owned projects. Under the agreements for the jointly-owned projects, PNM has an undivided interest in each asset and liability of the project and records its pro-rata share of each item in the corresponding asset and liability account on PNM’s Consolidated Balance Sheets. Likewise, PNM records its pro-rata share of each item of operating and maintenance expenses for its jointly-owned plants within the corresponding operating expense account in its Consolidated Statements of Earnings.
At December 31, 2010, PNM’s interests and investments in jointly-owned generating facilities are:
(1) Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.
San Juan Generating Station
PNM operates and jointly owns the SJGS. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri-State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by M-S-R Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS.
Palo Verde Nuclear Generating Station
PNM is a participant in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA and The Department of Water and Power of the City of Los Angeles. PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases.
Operation of each of the three PVNGS units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of 40 years, authorize APS, as operating agent for PVNGS, to operate the three PVNGS units. On December 15, 2008, APS, on behalf of the PVNGS participants applied for renewed operating licenses for the PVNGS Units for a period of 20 years beyond the expirations of the current licenses. The current NRC schedule for the applications estimates that a final NRC decision will be issued in April 2011. APS is making preparations to secure resources necessary to operate the plant for the period of extended operation, including the execution in April 2010 of a Municipal Effluent Purchase and Sale Agreement that provides effluent water rights necessary for cooling purposes at PVNGS through 2050.
Four Corners Power Plant
PNM is a participant in two units of Four Corners with APS (the operating agent), EPE, SRP, SCE, and Tucson. PNM has a 13.0% undivided interest in Units 4 and 5 of Four Corners. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, has negotiated amendments to an existing facility lease with the Navajo Nation which would extend the Four Corners leasehold interest to 2041. The execution of these amendments by the Navajo Nation requires the approval of the Navajo Nation Council, which occurred on February 15, 2011 and is awaiting final signature by the Nation’s President. The effectiveness of the amendments also requires the approval of the DOI, as
B-88
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
does a related federal rights-of-way grant which the Four Corners participants will pursue.
Luna Energy Facility
Luna is a combined-cycle power plant near Deming, New Mexico. Luna is owned 33.3% by PNM, 33.3% by Tucson and 33.3% by Freeport McMoran. Prior to July 2009, Luna was operated as a PNM wholesale facility and PNM’s 190-megawatt share of its power was sold to wholesale electric customers in the Southwest. Beginning in July 2009, Luna is included in rates subject to the jurisdiction of the NMPRC. See Note 17. The operation and maintenance of the facility has been contracted to North American Energy Services.
Construction Program
The Company anticipates making substantial capital expenditures for the construction and acquisition of utility plant and other property and equipment. A summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, renewable energy projects, and nuclear fuel, is as follows:
(15) Asset Retirement Obligations
The ARO is recorded based on the determination of underlying assumptions, such as the Company’s discount rate, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Any changes in these assumptions underlying the required calculations may require revisions to the estimated ARO when identified. A reconciliation of ARO is as follows:
(1) ARO for PNMR and PNM includes $0.2 million and $0.2 million at December 31, 2008 and 2007 for PNM Gas, which is reflected as discontinued operations.
(2) Based on studies to estimate amount and timing of future ARO expenditures.
B-89
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(16) Commitments and Contingencies
Overview
There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal proceedings on its results of operations or financial position. It is the Company’s policy to accrue for expected liabilities in accordance with GAAP when it is probable that a liability has been incurred and the amount to be incurred is reasonably estimable. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. The Company does not expect that any known lawsuits, environmental costs, and commitments will have a material adverse effect on its financial condition, results of operations, or cash flows, although the outcome of litigation, investigations, and other legal proceedings is inherently uncertain.
With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, is not reasonably estimable. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made subject to the known uncertainty of litigation. The Company has established appropriate reserves for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material.
Commitments and Contingencies Related to the Environment
PVNGS Decommissioning Funding
PNM has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts.
PNM funded an additional $3.0 million, $3.0 million, and $3.5 million for the years ended December 31, 2010, 2009, and 2008 into the qualified and non-qualified trust funds. The estimated market value of the trusts at December 31, 2010 and 2009 was $156.9 million and $137.0 million.
Nuclear Spent Fuel and Waste Disposal
Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance under the contract. In November 1997, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. APS pursued a damages claim for costs incurred through December 2006 in a trial that began on January 28, 2009. On June 18, 2010, the court awarded APS and the other PVNGS owners, including PNM, $30.2 million. PNM’s $3.1 million share of this amount has been received and was recorded as a $2.1 million reduction of cost of energy and a $1.0 million reduction of utility plant. PNM currently estimates that it will incur approximately $46.1 million (in 2007 dollars)
B-90
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
over the current life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is burned. At December 31, 2010 and December 31, 2009, PNM had $14.8 million and $15.0 million recorded as a liability on its Consolidated Balance Sheets for interim storage costs.
The Clean Air Act
Regional Haze
The EPA has established rules addressing regional haze and guidelines for BART determinations. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. In particular, the rules define how an SO2 emissions trading program developed by the Western Regional Air Partnership, a voluntary organization of western states, tribes and federal agencies, can be used by western states. New Mexico will be participating in the SO2 program, which is a trading program that will be implemented if SO2 reduction milestones, which have been proposed but not yet finalized, are not met.
SJGS
In November 2006, the NMED requested a BART analysis for NOx and particulates for each of the four units at SJGS. PNM submitted its analysis to the NMED in June 2007, recommending against installing additional pollution control equipment on any of the SJGS units beyond those planned at that time, the installation of which was completed in March 2009. PNM subsequently provided additional data in response to requests from the NMED. On June 21, 2010, the NMED filed its proposed regional haze SIP with the EIB. The NMED filing included a finding by the NMED that BART for NOx at SJGS is a technology known as “selective catalytic reduction” (“SCR”) plus “sorbent injection.” PNM disagreed with this BART determination.
As part of its 2007 submission, PNM analyzed SCR and concluded it was not appropriate as BART. PNM estimates that the cost of installation of the SCR technology at SJGS would be approximately $750 million to $1 billion for the entire station, of which PNM’s share would be approximately 46.3% based on its SJGS ownership percentage. In its filing, the NMED stated that it did not necessarily agree with PNM’s estimate and that it expected the actual costs for SCR technology to be lower than PNM’s estimate. PNM estimates installation of the sorbent injection technology would be an additional cost of approximately $40 million for the entire station. These technologies would also increase operating costs at SJGS. NMED withdrew its petition for adoption of the regional haze SIP on December 17, 2010.
The EPA is subject to a consent decree that required it to issue a proposed FIP for certain states, including New Mexico, for regional haze mitigation by November 11, 2010, later extended to December 22, 2010, if no proposed SIP had been submitted. EPA Region 6 issued a proposed Interstate Transport FIP on December 20, 2010. The proposed FIP included a BART determination for NOx controls at SJGS that requires SCR installation on all four units within three years of the final order, rather than the five-year implementation schedule the regional haze rules generally allow and that EPA proposed for Four Corners. The proposed FIP does not require sorbent injection. The FIP provides for a proposed emission limit for NOx at SJGS of 0.05 pounds per MMBTU, whereas the EPA’s proposed emission limit for NOx at Four Corners is 0.098 pounds per MMBTU. The EPA process includes a sixty day public comment period, which will end on March 21, 2011, unless extended. The consent decree requires a final approved SIP or FIP for New Mexico by May 11, 2011; however, on January 14, 2011, the U.S. District Court granted a joint motion to modify the consent decree to extend the final approval deadline to June 21, 2011.
PNM intends to provide comments to the EPA and vigorously contest the proposed FIP. PNM is unable to predict if the EPA will issue the final FIP, in its current form or in a modified form. If the final FIP requires SCR technology, PNM will likely appeal the FIP in the court system. However, an appeal would not stop the implementation timeframe unless a court issued a stay. As stated above, PNM believes that SCR technology is not appropriate for BART at SJGS and that the recently installed pollution control equipment provides reasonable progress toward visibility improvements required under the EPA rules. In the event a final FIP is issued in the form
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December 31, 2010, 2009 and 2008
of the proposed FIP, PNM believes that it would be extremely difficult to install SCR technology on all four units at SJGS within the three year timeframe. If a three year installation timeframe is ultimately required, PNM and the other owners of SJGS will have to evaluate their options, which could include shutting down part of SJGS during a portion of the installation process. No decisions have been made at this time and decisions can only be made after final rules are adopted and alternatives are analyzed.
PNM would seek recovery from its ratepayers of all costs that may ultimately be incurred as a result of the final FIP. While PNM cannot accurately predict the impact of these requirements on PNM’s ratepayers until requirements, if any, are finalized, it estimates that the installation of SCR controls would cost the average residential PNM customer about $82 for the first year with slowly declining costs for an estimated 20 years and that costs to businesses would be higher.
On January 19, 2011, multiple parties filed with the EPA a notice of intent to sue under the Clean Air Act for the EPA’s failure to promulgate a FIP within two years of a finding that certain states, including New Mexico, had failed to make all or part of a required regional haze SIP submittal. The notice alleges that the deadline for final promulgation of regional haze FIPs or full approval of regional haze SIPs was January 15, 2011. The same parties also filed a separate notice of intent to sue under the Clean Air Act for EPA’s failure to take final action on SIP submissions by multiple states, including New Mexico, within 18 months of receipt of submission.
PNM is unable to predict the ultimate outcome of these matters or what, if any, additional pollution control equipment will ultimately be required for SJGS. If additional equipment is required and/or final requirements result in additional operating costs to be incurred, PNM believes such costs should be recoverable through the ratemaking process and would seek recovery of them. However, PNM can provide no assurance that all such amounts will be recovered from ratepayers. It is possible that requirements to comply with the final BART determinations, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability of individual participants to continue participation in the plant.
Four Corners
EPA Region 9 previously requested that APS, as the operating agent for Four Corners, perform a BART analysis for Four Corners. APS submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA’s rulemaking process, the EPA will determine what it believes constitutes BART for Four Corners.
On October 6, 2010, the EPA issued its proposed BART determination for Four Corners. The rule, as proposed, would require the installation of SCR as post-combustion controls on each of Units 1-5 at Four Corners to reduce nitrogen oxides emissions. As previously disclosed, PNM’s total costs could be up to approximately $69.0 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that may ultimately be incurred. The EPA proposed a 10% stack opacity limitation for all five units and a 20% opacity limitation on certain fugitive dust emissions, although the proposed fugitive dust provision is unrelated to BART.
On November 24, 2010, APS submitted a letter to the EPA proposing an alternative to the EPA’s October BART proposal. Specifically, APS proposed to close Four Corners Units 1, 2, and 3 (PNM has no ownership interest in Four Corners Units 1, 2, and 3) by 2014 and to install post-combustion pollution controls for NOx on Units 4 and 5 by the end of 2018, provided that the EPA agrees to a contemporaneous resolution of Four Corners’ obligations or liability, if any, under the regional haze and reasonably attributable visibility impairment programs, the NSR program, and NSPS programs of the Clean Air Act.
On February 10, 2011, the EPA signed a Supplemental Notice Requesting Comment, related to the BART rulemaking for Four Corners. In the Supplemental Notice, the EPA proposed to find that a different alternative emission control strategy, based upon APS’s November 2010 proposal, would achieve more progress than the EPA’s October 2010 BART proposal. The Supplemental Notice proposes that Units 1, 2, and 3 would close by
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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
2014, post-combustion pollution controls for NOx would be installed on Units 4 and 5 by July 31, 2018, and the NOx emission limitation for Units 4 and 5 would be 0.098 lbs/MMBtu, rather than the 0.11 lbs/MMBtu proposed by the EPA in October 2010. The EPA extended the comment deadline for both the October 2010 proposal and the Supplemental Notice to May 2, 2011. APS is currently evaluating both proposals and will be providing comments to the EPA on both.
In addition, on February 16, 2010, a group of environmental organizations filed a petition with the DOI and DOA requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners and other plants. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners under a different haze program known as “Reasonably Attributable Visibility Impairment.” On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the DOI and DOA, alleging among other things that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. APS is currently evaluating the potential impact of this lawsuit.
The Four Corners participants’ obligations to comply with the EPA’s final BART determinations, coupled with the financial impact of future climate change legislation, other environmental regulations, the result of the lawsuit mentioned above and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.
PNM is currently evaluating the impacts of EPA’s proposed BART determination for Four Corners. As proposed, the participant owners of Four Corners will have five years after the EPA issues its final determination to achieve compliance with the BART requirements. PNM is unable to predict the ultimate outcome of this matter.
Ozone Non-Attainment
In March 2009, the NMED published its draft recommendation of area designations for the 2008 revised ozone national ambient air quality standard. The draft recommended that San Juan County, New Mexico be designated as non-attainment for ozone. SJGS is situated in San Juan County. However, the NMED subsequently determined that the monitor indicating high ozone levels was not reliable and did not recommend to the EPA that San Juan County be designated as non-attainment. On January 6, 2010, the EPA announced it would strengthen the 8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). It is uncertain when the EPA will make its final determination. If EPA sets the standard at 0.070 ppm, San Juan County and Dona Ana County, New Mexico may be designated as non-attainment for ozone. If the standard is set lower than 0.070 ppm, other counties in the state, including Bernalillo County, New Mexico, may be designated as non-attainment. A non-attainment designation for Bernalillo County could result in the requirement to reduce NOx emissions from Reeves Station by 2014, and a non-attainment designation for San Juan County could result in the requirement to reduce NOx emissions from SJGS by 2014. The Company cannot predict the outcome of this matter or if additional NOx controls would be required as a result of ozone non-attainment designation.
Citizen Suit Under the Clean Air Act
The operations of the SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes a provision whereby stipulated penalties are assessed for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance for each quarter. As of December 31, 2008, PNM’s share of the total amount of stipulated penalties was $3.4 million, which had been deposited into the escrow account and was paid in 2009. As required by the Consent Decree, PNM submitted reports addressing mercury emission controls for SJGS. Plaintiffs and NMED rejected PNM’s reports. PNM disputes the validity of the rejection of the reports. On May 17, 2010, PNM filed a petition with the federal district court seeking a judicial determination on the dispute relating to PNM’s mercury controls. NMED and plaintiffs seek to require PNM to implement mercury controls that PNM estimates would increase annual operating costs for the entire station by as much as $42 million. The court held a status conference on November 29, 2010 for purposes of establishing the appropriate process for resolution of the
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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
outstanding disputes related to this matter and to discuss other issues raised in PNM’s petition. An order from the court is pending. PNM cannot predict the outcome of these disputes.
Navajo Nation Environmental Issues
Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government as well as a lease from the Navajo Nation. The Navajo Acts, enacted in 1995 by the Navajo Nation, purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners. The District Court stayed these proceedings pursuant to a request by the parties and the parties are seeking to negotiate a settlement.
In 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the Navajo Nation exceeded its authority when it adopted the operating permit regulations. Each of the Four Corners participants filed a petition with the Navajo Nation Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the outcome of the settlement negotiations mentioned above.
In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement (“VCA”) resolving the dispute regarding the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts.
The Company cannot currently predict the outcome of these matters.
Section 114 Request
On April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits by the EPA. APS has responded to the EPA’s request. The Company is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.
Four Corners Notice of Intent to Sue
On May 7, 2010, APS received a Notice of Intent to Sue from Earthjustice, on behalf of several environmental organizations, related to alleged violations of the Clean Air Act at Four Corners. The notice alleges new source review-related violations and new source performance standard 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, and the EPA did not take any action. At this time, the Company cannot predict whether or when Earthjustice might file a lawsuit.
Endangered Species Act
On January 30, 2011, the Center for Biological Diversity, Dine Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit against the Office of Surface Mining Reclamation and Enforcement (“OSM”) and the DOI, alleging that OSM failed to engage in mandatory Endangered Species Act (“ESA”)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
consultation with the Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats. The lawsuit requests the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA. Neither APS nor PNM is a party to the lawsuit. APS is evaluating the lawsuit to determine its potential impact on Four Corners operations.
Santa Fe Generating Station
PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath the site of the former Santa Fe Generating Station to determine the source of the contamination pursuant to a 1992 settlement agreement between PNM and the NMED.
PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, to avoid a prolonged legal dispute, PNM entered into settlement agreements with the NMED under which PNM agreed to install a remediation system to treat water from a City of Santa Fe municipal supply well and install an additional extraction well and two new monitoring wells to address gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater meets applicable federal and state standards or until such time as the NMED determines that additional remediation is not required, whichever is earlier. The well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project.
The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station In February 2008, a NMED site inspection report was submitted to the EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. The Company is unable to predict the outcome of this matter.
Coal Combustion Waste Disposal
Regulation
SJCC currently disposes of CCBs consisting of fly ash, bottom ash, and gypsum from SJGS in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash at the mine with federal oversight by the U.S. Department of Interior’s Office of Surface Mining (“OSM”). APS currently disposes of CCBs in ash ponds and dry storage areas at Four Corners, and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at the Four Corners plant is regulated by the EPA and the New Mexico State Engineer’s Office.
On May 4, 2010, the EPA issued a proposed rulemaking to regulate CCBs. The proposal asks for public comment on two approaches for regulating CCBs. One option is to regulate CCBs under Subtitle C of the RCRA as a hazardous waste which allows the EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs under RCRA Subtitle D as a non-hazardous waste. This provides the EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. The EPA has indicated that it will work with the OSM to develop federal regulations for placement of CCBs in minefill operations. The proposed rule also states that the EPA and OSM will consider the recommendations of the National Research Council, which, at the direction of Congress, studied the health, safety and environmental risks associated with the placement of CCBs in U.S. coal mines. The 2006 report concluded that the “placement of coal combustion residues in mines as part of coal mine reclamation may be an appropriate option for the disposal of this material.” On June 21, 2010, the EPA published the proposed rule in the Federal Register. The public comment period on the proposed rule ended November 19, 2010.
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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM advocates for the non-hazardous regulation of CCBs under Subtitle D of RCRA. PNM is encouraged by the EPA’s proposed decision to develop separate federal regulations in conjunction with the OSM for mine placement of CCBs and believes the proper place for regulatory oversight should come from the OSM and state mining and mining reclamation agencies. In addition, PNM believes the decision by the EPA to consider the conclusions of the National Research Council study in the development of federal regulations regarding placement of CCBs in minefilling operations is a prudent one. PNM cannot predict the outcome of the EPA’s or OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material adverse impact on its operations, financial position, or cash flows.
Sierra Club Allegations
In December 2009, PNM and PNMR received a Notice of Intent to Sue (“RCRA Notice”) under the RCRA from the Sierra Club. The RCRA Notice was also sent to all SJGS owners, to SJCC, which operates the San Juan Mine that supplies coal to SJGS, and to BHP. Additionally, PNM was informed that SJCC and BHP received a separate notice of intent to sue under the Surface Mine Control and Reclamation Act (“SMCRA”) from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan Mine constitutes “open dumping” in violation of RCRA. The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff’s attorney’s fees and costs. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club’s concerns. If the parties are unable to settle the matter, PNM is prepared to aggressively defend its position in the RCRA litigation. PNM and PNMR cannot predict the outcome of this matter at the present time.
Gila River Indian Reservation Superfund Site
In April 2008, the EPA informed PNM that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. PNM, along with SRP, APS and EPE, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from PNM and other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to PNM, the resolution of this matter is not expected to have a material adverse impact on PNM’s financial position, results of operations, or cash flows.
Other Commitments and Contingencies
Coal Supply
The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP Billiton. SJCC holds certain federal, state, and private coal leases under an underground coal sales agreement pursuant to which it will supply processed coal for operation of the SJGS through 2017. The coal agreement is a cost plus contract. SJCC is reimbursed for all costs for mining and delivering the coal plus an allocated portion of administrative costs. In addition, SJCC receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of approximately 48 million tons of coal during its remaining term, which would supply substantially all the requirements of the SJGS through approximately 2017.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016. APS is currently in discussions with the coal supplier regarding post-2016 coal supply for Four Corners. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government.
In 2009, PNM completed a comprehensive review of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal. Based on this study, PNM revised its estimates of the final reclamation costs. In 2010, this study was updated. In July 2010, the mining contract for Four Corners was restructured with pricing to be determined using an escalating base-price. The estimate for decommissioning the Four Corners mine was also revised in 2010. Based on the most recent estimates, the final costs of mine reclamation, net of contract buyout costs paid to SJCC and reclamation payments made through December 31, 2010, are estimated to be $141.5 million for the surface mines at both SJGS and Four Corners and $21.7 million for the underground mine at SJGS, in future dollars. During the years ended December 31, 2010, 2009, and 2008, PNM made payments of $5.1 million, $7.6 million, and $12.7 million against the surface mine liability. As of December 31, 2010 and 2009, obligations of $25.0 million and $26.6 million for surface mine reclamation and $2.8 million and $2.3 million for underground mining activities were recognized on PNM’s Consolidated Balance Sheets.
In 2003, the NMPRC granted PNM permission to collect as a part of its rates up to $100.0 million of surface mine final reclamation costs. In the 2007 Electric Rate Case, PNM requested recovery of increased surface mine decommissioning costs, as well as underground mine reclamation costs. Recovery of the final underground mine reclamation costs was allowed; however, the NMPRC denied recovery of amounts for surface mine decommissioning in excess of $100.0 million. PNM appealed this decision to the New Mexico Supreme Court, which on September 1, 2009 issued its ruling that the NMPRC had properly denied recovery of these costs. PNM filed a motion with the court seeking rehearing of this issue, which was denied in November 2009 concluding this matter.
PVNGS Liability and Insurance Matters
The PVNGS participants have insurance for public liability exposure for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, the PVNGS participants maintain the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is $117.5 million, subject to an annual limit of $17.5 million per incident, to be periodically adjusted for inflation. Based on PNM’s 10.2% interest in the three PVNGS units, PNM’s maximum potential assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million.
The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. PNM and certain other participants have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). PNM is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of each retrospective assessment PNM could incur under the current NEIL policies totals $5.8 million for each retrospective assessment declared by NEIL’s Board of Directors due to losses. The insurance coverage discussed in this and the previous paragraph is subject to policy conditions and exclusions.
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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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December 31, 2010, 2009 and 2008
Natural Gas Supply
PNM Gas contracted for the purchase of gas primarily to serve its retail customers. The majority of these contracts were short-term in nature, supplying the gas needs for the current heating season and the following off-season months. The price of gas was a pass-through, whereby PNM Gas recovered 100% of its cost of gas. There was also occasion for PNM Gas to purchase gas to source off-system sales. As discussed in Note 2, PNM completed the sale of PNM Gas on January 30, 2009 at which time all commitments for PNM Gas future gas purchases were assumed by the buyer.
PNM Electric procures gas supplies for its power plants from third-party sources and contracts with third party transportation providers, including NMGC (PNM Gas through January 29, 2009).
Water Supply
Because of New Mexico’s arid climate and periodic drought conditions, there is a growing concern in New Mexico about the use of water for power plants. PNM has secured water rights in connection with the existing plants at Afton, Luna, and Lordsburg. Water availability does not appear to be an issue for these plants at this time.
The “four corners” region of New Mexico, in which SJGS and Four Corners are located, experienced drought conditions during 2002 through 2004 that could have affected the water supply for PNM’s generation plants in that region. In future years, if adequate precipitation is not received in the watershed that supplies the four corners region, the plants could be impacted. Consequently, PNM, APS, and BHP Billiton have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines. PNM has reached an agreement for a voluntary shortage sharing agreement with tribes and other water users in the San Juan Basin for a term ending December 31, 2012. Further, PNM and BHP Billiton have reached agreement on a long-term supplemental contract relating to water for SJGS with the Jicarilla Apache Nation that ends in 2016. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of Four Corners. Although the Company does not believe that its operations will be materially affected by the drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how regulations and legislation may impact the Company’s situation in the future, should the shortages occur in the future.
In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for the next forty years.
PVNGS Water Supply Litigation
A summons was served on APS in 1986 that required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons. APS’ rights and the rights of the other PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on both these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material adverse impact on its results of operation, financial position, or cash flows.
San Juan River Adjudication
In 1975, the State of New Mexico filed an action entitled “State of New Mexico v. United States, et al.”, in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. PNM was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. In 2005, the Navajo Nation and various parties announced a settlement of the Navajo
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Nation’s reserved surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation. The Company cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. The Company is unable to predict the ultimate outcome of this matter. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.
Conflicts at San Juan Mine Involving Oil and Gas Leaseholders
SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has other claimants and potential claimants. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders.
Republic Savings Bank Litigation
In 1992, Meadows Resources, Inc. (“MRI”), an inactive subsidiary of PNMR, and its subsidiaries (“Plaintiffs”) filed suit against the Federal government in the United States Court of Claims, alleging breach of contract arising from the seizure of Republic Savings Bank (“RSB”). RSB was seized and liquidated after Federal legislation prohibited certain accounting practices previously authorized by contracts with the Federal government. The Federal government filed a counterclaim alleging breach of obligation to maintain RSB’s net worth and moved to dismiss Plaintiffs’ claims for lack of standing.
Plaintiffs filed a motion for summary judgment in December 1999 on the issue of liability and on the issue of damages. The Federal government filed a cross motion for summary judgment and opposed Plaintiffs’ motion.
On January 25, 2008, the court entered its opinion granting the Federal government’s motion to dismiss MRI, denying the Federal government’s motion for summary judgment and granting the remaining Plaintiffs’ motion for summary judgment on the issues of liability and damages, awarding the Plaintiffs damages in the amount of $14.9 million. MRI had previously received payment from the FDIC in the amount of $0.3 million. This payment reduces the amount of damages owed to $14.6 million.
The federal government appealed this matter to the U.S. Court of Appeals for the Federal Circuit and Plaintiffs cross-appealed. On October 21, 2009, the Federal Circuit issued its opinion, affirming in part and reversing in part the decision of the Court of Claims, resulting in an award to the Plaintiffs of $9.7 million. The appeal period expired in January 2010. A final judgment order was entered for $9.7 million, which amount was received in April 2010. PNM recorded the amount, net of legal expenses of $1.2 million, as other income in 2010.
Western United States Wholesale Power Market
Various circumstances, including electric power supply shortages, weather conditions, gas supply costs, transmission constraints, and alleged market manipulation by certain sellers, resulted in the well-publicized California and Western markets energy crisis of 2000-2001 and the bankruptcy filings of the Cal PX and PG&E. As a result of the conditions in the Western markets during this time period, between late-2000 and mid-2003, FERC, the California Attorney General, and private parties (collectively, the “California Parties”) initiated investigations, litigation, and other proceedings relevant to PNM and other sellers in the Western markets at FERC and in both California State and Federal District Courts, seeking a determination whether sellers of wholesale electric energy during the crisis period, including PNM, should be ordered to pay monetary refunds to buyers of such energy. These proceedings were pending at FERC as well as before the U.S. Court of Appeals for the Ninth Circuit. PNM participated in these proceedings at FERC, the Federal District Courts and the Ninth Circuit, including filing appeals to that court.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
In December 2009, PNM and the California Parties reached an agreement in principle to settle all remaining claims against PNM in these proceedings and on February 11, 2010, PNM entered into a “Settlement and Release of Claims Agreement” (the “Settlement Agreement”), which was filed with FERC on February 12, 2010. The settlement contemplated by this agreement was subject to FERC approval, which was received on April 29, 2010. On May 27, 2010, the Sacramento Municipal Utility District, whose earlier comments opposing the settlement were rejected by FERC, filed with FERC a request for rehearing of the April 29 approval order. That request remains pending before FERC. The terms of the Settlement Agreement provide, among other things, for PNM to pay to the California Parties the amount of $45.0 million, consisting of the assignment of PNM receivables plus interest as of December 31, 2009 from the Cal ISO and the Cal PX in the amount of $13.1 million plus a cash payment of $31.9 million and for the California Parties to release PNM from claims arising from the California energy crisis of 2000 and 2001. PNM recorded the settlement, which was included in other current liabilities, at December 31, 2009. Additionally, the Settlement Agreement provides that certain of the California Parties will assume liability that PNM may have to entities that choose not to opt in to the settlement. PNM expressly denies any wrongdoing or culpability with respect to the claims against it that are released by the Settlement Agreement and, in entering into the settlement, does not admit any fault or liability.
On January 15, 2010, PNM transferred the cash payment, which was included in special deposits, to an escrow account established by the California Parties. Pursuant to the Settlement Agreement, the receivables and the cash payment have been or will be distributed to the California Parties and other entities that purchased electricity through the Cal ISO and Cal PX during the relevant time period as settlement funds in accordance with the terms and conditions of the Settlement Agreement. Upon receiving FERC approval of the Settlement Agreement, the special deposit, assigned receivables, and current liability were removed from the Consolidated Balance Sheets of PNMR and PNM.
Complaint Against Southwestern Public Service Company
In September 2005, PNM filed a complaint under the Federal Power Act against SPS. PNM argued that SPS’ rates for sale of interruptible energy were excessive and that SPS had been overcharging PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a complaint proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices (the “Golden Spread complaint proceeding”). Additionally, in November 2005, SPS filed an electric rate case at FERC proposing to unbundle and raise rates charged to customers effective July 2006. PNM intervened in the case and objected to the proposed rate increase. In September 2006, PNM and SPS filed a settlement agreement providing for resolution of issues relating to rates for sales of interruptible energy, but not resolving the fuel clause issues. In September 2008, FERC issued its order approving the settlement between PNM and SPS.
In April 2008, FERC issued its order in the Golden Spread complaint proceeding. FERC affirmed in part and reversed in part an ALJ’s initial decision, which had, among other things, ordered SPS to pay refunds to PNM with respect to the fuel clause issues. FERC affirmed the decision of the ALJ that SPS violated its fuel cost adjustment clause tariffs. However, FERC shortened the refund period applicable to the violation of the fuel cost adjustment clause issues. PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC.
Begay v. PNM et al
A putative class action was filed against PNM and other utilities on February 11, 2009 in the United States District Court in Albuquerque. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation. Plaintiffs, including an allottee association, make broad, general assertions that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. The plaintiffs, who have sued the defendants for breach of fiduciary duty, seek a constructive trust. They have also included a breach of trust claim against the United States and its Secretary of the Interior. PNM and the other defendants filed motions to dismiss this action. On March 31, 2010, the court ordered that the entirety of the
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court.
On May 10, 2010, Plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs. PNM intends to participate in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. As the administrative appeal process is only in its initial stages, PNM cannot predict the outcome of the proceeding at this time.
Transmission Issues
On November 24, 2009, FERC issued Order 729 approving two Modeling, Data, and Analysis Reliability Standards (“Reliability Standards”) submitted by NERC - MOD-001-1 (Available Transmission System Capability) and MOD-029-1 (Rated System Path Methodology). Both MOD-001-1 and MOD-029-1 require a consistent approach, provided for in the Reliability Standards, to measuring the total transmission capability (“TTC”) of a transmission path. The TTC level established using the two Reliability Standards could result in a reduction in the available transmission capacity currently used by PNM to deliver generation resources necessary for its jurisdictional load and for fulfilling its obligations to third-party users of the PNM transmission system. PNM continues to evaluate its transmission system under the provisions of the two Reliability Standards and consult with other transmission facility owners with whom PNM is interconnected to determine the impact on the capability of its transmission system. PNM is unable to predict the outcome of this matter.
On April 20, 2010, Cargill Power Markets, LLC (“Cargill”) filed a complaint with FERC, asserting that PNM improperly processed its transmission service queue and unfairly invalidated a transmission service request by Cargill. On July 29, 2010, FERC issued an order and established a schedule for hearing and settlement procedures. In its order, FERC determined that PNM had improperly invalidated a single Cargill transmission service request submitted on February 21, 2008 and set the issue for hearing to determine an appropriate remedy. However, the hearing is being held in abeyance by FERC to provide time for settlement negotiations under the oversight of a FERC settlement judge. On September 27, 2010, FERC granted rehearing for further consideration. On January 13, 2011, PNM and Cargill filed a settlement agreement with FERC in which PNM agreed to pay Cargill $0.2 million and put Cargill’s transmission service request back into the queue. The settlement also left Cargill’s and PNM’s rehearing requests in place before FERC. FERC has not yet acted upon the requests for rehearing or settlement and they remain pending further decision. PNM is unable to predict the final outcome of this matter at FERC.
(17) Regulatory and Rate Matters
PNMR
First Choice Request for ERCOT Alternative Dispute Resolution
In June 2008, First Choice filed a request for alternative dispute resolution with ERCOT alleging that ERCOT incorrectly applied its protocols with respect to congestion management during the first quarter of 2008. First Choice requested that ERCOT resolve the dispute by restating certain elements of its first quarter 2008 congestion management data and by refunding to First Choice allegedly overstated congestion management charges. The amount at issue in First Choice’s claim can only be determined by running ERCOT market models with corrected inputs but First Choice believes that the amount is significant. ERCOT protocols provide that ERCOT will notify potentially impacted market participants and subsequently consider the merits of First Choice’s allegations. The Company is unable to predict the outcome of this matter.
B-101
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
PNM
2007 Electric Rate Case
On February 21, 2007, PNM filed a general electric rate case (“2007 Electric Rate Case”) requesting the NMPRC approve an increase in service fees to all of PNM’s retail customers except those formerly served by TNMP. The request was designed to provide PNM’s electric utility an opportunity to earn a 10.75 percent return on equity. The application also requested authorization to implement a FPPAC through which changes in the cost of fuel and purchased power, above or below the costs included in base rates, are passed through to customers on a monthly basis. On April 24, 2008, the NMPRC issued a final order that resulted in a revenue increase of $34.4 million effective May 1, 2008. The rate increase provides for a 10.1 percent return on equity. The NMPRC disallowed recovery of costs associated with the RECs used to meet the New Mexico RPS that were being deferred as regulatory assets and ruled that recovery of surface coal mine decommissioning costs be capped at $100 million. The order resulted in PNM being unable to assert it is probable, as defined under GAAP, that the costs previously deferred on PNM’s balance sheet will be recoverable through future rates charged to its customers. Accordingly, in 2008, PNM recorded regulatory disallowances for pre-tax write offs of $19.6 million for coal mining decommissioning costs and $10.6 million for deferred REC costs. PNM appealed the NMPRC’s treatment of coal mine decommissioning and the RECs to the New Mexico Supreme Court. PNM later dismissed its appeal of the treatment of the REC costs and the New Mexico Supreme Court affirmed the NMPRC order on coal mine decommissioning concluding this matter.
Emergency FPPAC
In March 2008, PNM and the IBEW filed a joint motion in the 2007 Electric Rate Case requesting NMPRC authorization to implement an Emergency FPPAC on an interim basis, which was approved in May 2008, with certain modifications. PNM implemented the Emergency FPPAC from June 2, 2008 through June 30, 2009.
The ABCWUA and the NMIEC filed notices of appeal to the New Mexico Supreme Court seeking to vacate the NMPRC order approving the Emergency FPPAC. On March 19, 2010, the New Mexico Supreme Court affirmed the NMPRC order approving the Emergency FPPAC.
The NMPRC order approving the Emergency FPPAC required PNM to pay for an audit of PNM’s monthly FPPAC reports and a prudence review of PNM’s fuel and purchased power costs, to be conducted by auditors selected by the NMPRC. On February 19, 2010, the audit report of findings and recommendations was submitted to the NMPRC. The report recommended operational changes in several areas but did not identify any imprudent activities or find that PNM’s fuel or purchased power costs were unreasonable. The audit report findings and recommendations are subject to NMPRC review and approval. PNM is unable to predict the outcome of this matter.
The NMPRC order approving the Emergency FPPAC also provided that if PNM’s base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM’s motion and recommended that PNM be required to refund the amount collected. On January 12, 2010, the NMPRC directed the Emergency FPPAC auditor to investigate whether the replacement power costs were prudently incurred. The order also directed PNM to file a response to the auditors’ report, to provide certain additional information, and to show cause why it should not be fined for recovering replacement power costs without prior NMPRC approval. PNM filed its response to the order on February 12, 2010. On February 19, 2010, the auditor’s report on replacement power costs was submitted to the NMPRC. The report concluded that the methodology used to estimate the cost of replacement power was reasonable, that PNM purchased power at the lowest reasonable cost, and that outage planning and scheduling and plant operations were reasonable. These findings are subject to NMPRC review and approval. On April 12, 2010, the NMPRC staff filed a request for a hearing on whether the replacement power costs should be approved and whether any penalty should be imposed, to which PNM responded. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC’s order. If the
B-102
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
stipulation in the 2010 Electric Rate Case discussed below is approved by the NMPRC, the parties to the stipulation, including the NMRPRC staff, will jointly request that the NMPRC take no further action in this matter and close the docket. PNM is unable to predict the outcome of this matter.
2008 Electric Rate Case
On September 22, 2008, PNM filed a general rate case (“2008 Electric Rate Case”) requesting the NMPRC to approve an increase in electric service rates to all PNM retail customers except those formerly served by TNMP. The proposed rates were designed to increase annual operating revenue by $123.3 million, based on a March 31, 2008 test period and calculating base fuel costs using a projection of costs for the 12 months ending March 31, 2009. PNM also proposed a FPPAC in the general form authorized by the NMPRC, but with PNM retaining 25% of off-system sales margins and crediting 75% against fuel and purchased power costs.
On March 6, 2009, PNM, the NMPRC staff, and most of the intervening parties filed a stipulation to resolve all issues in the case, including the approval of the Resource Stipulation described below. No party opposed the stipulation. The stipulation, as amended, was approved by the NMPRC on June 18, 2009 and provided for an increase in annual non-fuel revenues of $77.1 million, of which 65% was implemented on July 1, 2009 and the remaining 35% was implemented on April 1, 2010. As an offset to the non-fuel revenue increase, PNM implemented a credit to customers totaling $26.3 million, representing the amount of revenues from past sales of SO2 allowances. This amount is being credited to ratepayers over 21 months beginning July 1, 2009. The crediting mechanism will also be used to credit customers with revenues received by PNM from future sales of SO2 allowances. In 2009, PNM recorded a regulatory disallowance expense and a regulatory liability for the $26.3 million to be credited to ratepayers. The stipulation also provides that a traditional FPPAC go into effect July 1, 2009 with 100% of off-systems sales margins being credited against costs in the FPPAC. This FPPAC does not include a recovery cap or the capacity factor target of the Emergency FPPAC. The FPPAC factor is set annually.
Resource Stipulation
In anticipation of the 2008 Electric Rate Case, a stipulation (the “Resource Stipulation”) was filed with the NMPRC, which approved it on May 26, 2009. The Resource Stipulation allowed recovery in rates of costs related to 1) the Valencia PPA, 2) PNM’s acquisition of an ownership interest in Unit 2 of PVNGS that was being leased, including carrying costs, and 3) the application to own and operate Lordsburg and PNM’s interest in Luna as jurisdictional assets.
In June 2007, a wholly-owned subsidiary of PNMR purchased 100% of a trust, which owns a 2.26% undivided interest, representing 29.8 MW, in PVNGS Unit 2 and a 0.76% undivided interest in certain PVNGS common facilities, as well as a lease under which such facilities were leased to PNM. The Resource Stipulation allowed the Unit 2 interest to be transferred to PNM and the acquisition costs to be recovered beginning with the 2008 Electric Rate Case. On July 24, 2009, PNM purchased the trust from the other PNMR subsidiary for $39.1 million in cash. The purchase price was equal to the book value of the underlying assets less deferred taxes and miscellaneous accruals. The other PNMR subsidiary paid a dividend of that same amount to PNMR. PNMR then made an equity contribution of that amount to PNM. The trust had $32.0 million of debt owing to the PVNGS Capital Trust, which is consolidated by PNM. The transfer had no impact on the financial statements of PNMR. The impacts on the financial statements of PNM were to increase net plant in service by $73.7 million, increase common stock by $39.1 million, reduce investment in the PVNGS lessor notes by $32.0 million, reflecting the elimination of the debt owed by the trust to the PVNGS Capital Trust, and increase deferred income taxes and other accruals by $2.6 million.
Renewable Portfolio Standard
The Renewable Energy Act of 2004 was enacted to encourage the development of renewable energy in New Mexico. The act, as amended, establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified” beginning in 2011 when no less than 20% of the renewable portfolio requirement must be met by wind energy, no less than 20% by solar
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
energy, no less than 10% by other renewable technologies, and no less than 1.5% by distributed generation. The act provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities recovery of costs incurred consistent with approved procurement plans and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC has established a RCT for 2011 of 2% of all customers’ aggregated overall annual electric charges that increases by 0.25% annually until reaching 3% in 2015.
On July 1, 2009, PNM filed its annual Renewable Energy Portfolio Procurement Plan for 2010 with the NMPRC. Under the plan, PNM proposed to rely on a mixture of solar, wind, and biogas resources and the purchase of RECs to meet its renewable energy requirements for 2010 and 2011 and committed to file for additional projects later in the year. In September 2009, the NMPRC rejected the plan and ordered PNM to file a revised plan. In December 2009, the NMPRC approved the biogas resources project and a procurement of RECs.
PNM and several parties to the proceeding filed a stipulation and PNM filed its revised 2010 procurement plan in January 2010. Under the revised plan, PNM proposed to invest approximately $265 million on solar PV facilities and implement a customer-sited PV distributed generation program to replace its current PV programs. The plan and stipulation were opposed by a number of parties, including the NMAG and the NMPRC staff. On August 31, 2010, the NMPRC issued an order on the revised plan that rejected portions of the plan but approved PNM’s investment in 22 MW of solar PV facilities at various PNM sites and the construction of a solar-storage demonstration project. The NMPRC also modified PNM’s distributed generation REC purchase program. PNM is allowed recovery of costs associated with the purchase of the RECs and for the investments in the solar PV and demonstration projects, up to $107.7 million, PNM’s estimated amounts of these investments. PNM anticipates requesting recovery of these costs from customers through a rate rider. See 2010 Electric Rate Case below.
On July 1, 2010, PNM filed its renewable energy procurement plan for 2011. The 2011 plan proposed the procurement of 250,000 MWh of RECs from another New Mexico public utility for compliance with the renewable portfolio standard in 2011. On October 5, 2010, the NMPRC issued an order rejecting PNM’s plan for 2011 as incomplete because certain planning assumptions used in the plan were found to be outdated, and ordered PNM to file a new plan within 60 days. The NMPRC ordered that the 180-day period for NMPRC action on the 2011 plan would start on the date the new plan was filed. On December 6, 2010, PNM filed a revised 2011 plan that proposes procurement of 423,860 MWh of wind generated renewable energy certificates from various bidders selected through a RFP process at a total cost of up to $5.5 million. The RECs would be retired for RPS compliance for 2011. The plan requests a waiver of the full RPS requirement for 2012 because PNM projects that it will be unable to satisfy the full requirement without exceeding the RCT. The plan also requests a variance from the diversity requirements for solar and certain “other resources” for 2011 and 2012 because of cost and availability constraints. A procedural schedule has been adopted that includes a public hearing on the plan beginning on April 1, 2011. PNM cannot predict the outcome of this matter.
NMPRC Inquiry on Fuel and Purchased Power Adjustment Clauses
In October 2007, the NMPRC issued a NOI regarding possible amendments to the NMPRC’s rule on FPPACs applicable to investor-owned utilities and electric cooperatives in New Mexico. An amended rule became effective as of December 30, 2010. The amended rule authorizes FPPACs based on monthly, rolling average annual, and other fixed period calculations, subject to approval by the NMPRC. PNM is currently authorized to use an annual factor. The amended rule extends the interval between required continuation filings from two years to four years.
NMPRC Rulemaking on Disincentives to Energy Efficiency Programs
In January 2008, the NMPRC issued a NOI to identify disincentives in utility expenditures on energy efficiency and measures to address those disincentives, including specific rate making alternatives, and appointed a Hearing Examiner to conduct workshops to develop proposals for possible rule changes. Based on the workshops, the NMPRC issued proposed amendments to its energy efficiency rule. After a hearing, the NMPRC approved the amended rule on April 8, 2010 to be effective May 3, 2010. The amended rule allows electric utilities to collect rate
B-104
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
adders of $0.01 per KWh for lifetime energy savings and $10 per kilowatt for demand savings related to energy efficiency and demand response programs beginning in 2010. The amended rule also required investor-owned electric utilities to make filings by July 1, 2010 that proposed rate design and ratemaking measures to remove regulatory disincentives or barriers to achieve energy efficiency savings. PNM included its proposals in the 2010 Electric Rate Case described below. Under the amended rule, after such measures become effective, the rate adder for energy saving is reduced to $0.005 per KWh. The NMAG and NMIEC appealed the NMPRC order adopting the amended rule to the New Mexico Supreme Court and subsequently moved the court for a stay of the NMPRC order. The Court denied the stay motion. Oral argument was held before the New Mexico Supreme Court on February 8, 2011. PNM cannot predict the ultimate outcome of these appeals.
On May 5, 2010, PNM filed proposed tariffs under the amended rule to recover a rate adder related to 2010 efficiency programs. PNM proposed to recover $6.2 million over a twelve-month period following NMPRC approval. The staff of the NMPRC filed testimony recommending the recovery of not more than $4.2 million. A public hearing was held on September 14, 2010 and the NMPRC issued an order on November 29, 2010 authorizing recovery of $4.2 million over 12 months. PNM began implementing a rate rider to recover the $4.2 million adder on December 29, 2010.
PNM Electric Energy Efficiency and Load Management Programs
Public utilities are required to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. After proceedings before the NMPRC, PNM began recovering the costs of these programs in August 2009 through a rate rider amounting to 1.881% of customers’ bills, before taxes and franchise fees based on program costs of $14.1 million.
On July 7, 2009, the NMPRC ordered an investigation into whether it is prudent for PNM to continue certain load management programs initiated in 2008 with NMPRC approval. PNM offers these programs through contracts with third-party vendors that contain substantial fees for early termination. On August 12, 2010, the NMPRC issued a final order approving the continuation of the load management programs without modification.
2010 Energy Efficiency Application
On September 15, 2010, PNM filed an energy efficiency program application for programs to be offered beginning June 1, 2011. PNM requested revisions to programs offered, revisions of estimates of participation and expenditure levels, approval of revised program cost recovery tariff riders, and approval of disincentive/incentive adders for 2011 energy efficiency and demand response programs. The total amount that PNM proposed to recover through the tariff riders is $32.9 million, which includes the 2010 programs adder discussed above. On February 11, 2011, the NMPRC staff filed testimony that the amount of the incentive adder authorized by the energy efficiency rule should be prospectively reduced to $0.002 per kWh and $4 per KW and that recovery of certain carrying charges on uncollected program costs should be disallowed for noncompliance with NMPRC rules. On February 21, 2011, PNM filed rebuttal testimony disputing the staff’s contentions. A public hearing was held on February 23, 2011. PNM is unable to predict the outcome of this proceeding.
Investigation on Establishing a Policy Linking Utility Earnings to Quality of Customer Service
On May 28, 2009, the NMPRC ordered an investigation to consider the development of a service quality incentive mechanism for utilities in New Mexico, including PNM. The parties were to look at quality of service mechanisms established in other NMPRC orders, as well as the mechanisms that have been implemented in other states. Following a workshop process, the Hearing examiner filed a report concluding that present circumstances do not warrant the implementation of a performance based ratemaking mechanism to either reward or penalize utilities for quality of service. The workshop participants agreed that enhanced reporting requirements would allow the NMPRC to monitor important customer service metrics to determine if service quality is deteriorating so that the NMPRC can identify and address any adverse trends before they become a problem. The report recommends that utilities be required to file customer service reports no later than April 30th of each year for a three-year period
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
commencing April 30, 2011. A timetable for the NMPRC to act on this recommendation has not been established. PNM is unable to predict the outcome of this proceeding.
Rates for Former TNMP Customers in New Mexico
PNM serves the former New Mexico customers of TNMP (“TNMP-NM” or “PNM South”) under rates approved by the NMPRC in its order approving PNMR’s acquisition of TNMP. Under that order, rates charged to TNMP-NM customers were set through December 31, 2010. In January 2009, the NMPRC directed PNM to estimate the revenue requirement increase that would be reflected in a TNMP-NM rate application for rates effective January 2011. PNM estimated that the rate increase could be between 40% and 56% depending on fuel costs. In April 2009, the NMPRC directed PNM, the NMPRC staff and other parties to attempt to reach consensus on ways to mitigate the impact of this potential rate increase and appointed a mediator. Mediation did not result in an agreement. In March 2010, the NMPRC issued its Order Initiating Investigation and Requiring Informational Filings to which PNM and other parties filed responses. On May 25, 2010, the NMPRC issued an order setting a procedural schedule for the submission of testimony and a hearing. The order further directed PNM and the NMPRC staff to file testimony addressing certain matters related to cost allocation. A hearing was held on December 16, 2010, and post-hearing briefs were filed on December 23, 2010. The TNMP-NM customers have been included in the rate filing and related stipulation discussed under 2010 Electric Rate Case below. PNM cannot predict the outcome of this matter.
Third-Party Arrangements for Renewable Distributed Generation
On June 16, 2009, the NMPRC initiated a proceeding and requested legal briefs on the issue of whether third-party arrangements for the sale of renewable energy from customer-sited distributed generation facilities were permissible under New Mexico law. On December 31, 2009, the NMPRC issued an order that in part declared that a third party that owns renewable generation equipment that is installed on a utility customer’s premises pursuant to a long-term contract with the customer to supply a portion of that customer’s electricity use, payments for which are based on a kilowatt-hour charge, is not a public utility subject to regulation by the NMPRC. PNM and two other parties appealed the order to the New Mexico Supreme Court.
In early 2010, legislation was enacted that nullified the NMPRC order and, effective January 1, 2011, excludes non-utility power suppliers from the definition of public utilities under state law, subject to certain limitations as to size and provided that such suppliers produce renewable energy, locate their generators on the site of the power consumer, and do not utilize retail wheeling of power. A separate provision of the legislation directs the NMPRC to authorize public utilities to establish rates that assure the utilities’ recovery of an appropriate portion of their fixed costs from owners of interconnected generators. After enactment of this legislation, appeals of the NMPRC order were dismissed. On March 9, 2010, the NMPRC issued an order setting workshops for the purpose of obtaining comments and views on implementation of the rate-making aspect of the statute.
Application to Hedge Fuel and Purchased Power Costs
In August 2009, PNM filed an application for approval of a plan to manage fuel and purchased power costs by entering into certain forward market transactions relating to the procurement of fuel and purchased power and the sale of excess electrical energy in the wholesale market. PNM sought NMPRC authorization to conduct these activities, which involve hedging practices, and to pass through the costs and benefits of the transactions to jurisdictional customers using PNM’s FPPAC. The NMPRC approved the program with modifications agreed to by PNM on April 20, 2010 and PNM has begun the hedging program.
2010 Electric Rate Case
PNM filed its 2010 Electric Rate Case application with the NMPRC on June 1, 2010 for rate increases for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for those customers served by PNM (“PNM North”) prior to its acquisition of TNMP and for the customers formerly served by TNMP (“PNM South”). The proposed total increase of $165.2 million represents a 22% increase for PNM North
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
and a 20% increase for PNM South. The filed revenue requirements are based on a future test period ending December 31, 2011. If the NMPRC grants the entire relief requested, PNM proposed to implement the increase in two steps. Phase 1 would become effective April 1, 2011 (PNM North: $111.1 million, 16%; PNM South: $8.7 million, 14%), and Phase 2 would become effective January 1, 2012 (PNM North: $41.7 million, 6%; PNM South: $3.6 million, 6%). PNM also proposed to implement a FPPAC for PNM South. This is the first rate case filing in New Mexico proposing a future test year consistent with the recent amendments to the Public Utility Act. The NMPRC initially suspended the rates until April 1, 2011. On July 27, 2010, in response to motions filed by the NMPRC staff and other parties, the NMPRC determined that PNM’s rate filing was incomplete, ordered PNM to supplement its rate application, directed that the suspension period not begin to run until PNM’s rate application was made complete, and extended the suspension period by one month. PNM believed that the order was erroneous both in its assessment of the completeness of PNM’s filing and in its application of the governing legal standards. On August 5, 2010, PNM supplemented its rate case application in conformance with the NMPRC’s order and also on August 5, 2010 petitioned the New Mexico Supreme Court requesting the Court to vacate the NMPRC’s July 27, 2010 order and for other equitable relief. The Supreme Court denied PNM’s petition on September 13, 2010. In October 2010, PNM began meeting with the NMPRC staff and other parties to discuss settlement. To accommodate these settlement discussions, the Hearing Examiner and the NMPRC issued orders revising the hearing schedule and extending the suspension period.
On February 3, 2011, PNM, NMPRC staff, NMAG, NMIEC, ABCWUA, Buckman Direct Diversion Board, and the City of Alamogordo, New Mexico entered into a stipulation that, if approved by the NMPRC, would resolve all issues in the 2010 Electric Rate Case and provide a rate path for PNM through 2013. Other parties have filed statements opposing the stipulation. This stipulation, which reflects some aspects of a future test year, is subject to approval of the NMPRC. The stipulation would allow PNM to increase rates by $45.0 million beginning May 15, 2011 and by an additional $40.0 million beginning January 1, 2012. The proposed rates are designed so that PNM North customers and PNM South customers would have the same percentage increase. The PNM South customers would also be covered by the same FPPAC that is utilized for the PNM North customers. In addition, subject to further NMPRC approvals, PNM would recover the costs associated with NMPRC approved renewable energy procurement plans through a rate rider beginning July 1, 2012. PNM would also be able to implement a separate rate rider in 2013 to recover up to an additional $20.0 million to cover changes in plant-related rate base between June 30, 2010 and December 31, 2012. PNM’s next general rate adjustment could not go into effect before January 1, 2014, except that PNM can file for recovery of costs to comply with any federal or state environmental law or requirement effective after June 30, 2010. If the stipulation is approved by the NMPRC, PNM would forego collection of $10.0 million of the under-collected amount in the FPPAC balancing account, which would be recorded as a regulatory disallowance. On February 22, 2011, the NMPRC issued an order denying a joint motion of PNM and others that requested the NMPRC, instead of the Hearing Examiner, conduct the hearing on the stipulation. The order also stated that if PNM files a request for interim rate relief, the NMPRC would conduct the hearing on that request. The order also required PNM to agree to extend the suspension period for an additional three months from August 10, 2011 as a condition for going forward with hearings on the stipulation, in order to accommodate the procedural schedule that would be needed if the stipulation is not ultimately approved. PNM gave notice to the NMPRC on February 25, 2011 that it agreed to extend the suspension period until November 10, 2011. The Hearing Examiner has established a procedural schedule that includes a hearing on the stipulation beginning on May 9, 2011. PNM is unable to predict the outcome of this matter.
Transmission Rate Case
In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually and revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms. If approved, the rate increase would apply to all of PNM’s wholesale electric transmission service customers, which include other utilities, electric co-operatives, and entities that use PNM’s transmission system to transmit power at the wholesale level. The proposed rate increase would not impact PNM’s retail customers. On December 29, 2010, FERC issued an order accepting PNM’s filing and suspending the proposed tariff revisions for five months to become effective June 1, 2011, subject to refund, and providing a schedule to establish hearing and settlement judge procedures. PNM is unable to predict the outcome of this proceeding.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
TNMP
TNMP Competitive Transition Charge True-Up Proceeding
The purpose of the true-up proceeding was to quantify and reconcile the amount of stranded costs that TNMP may recover from its transmission and distribution customers. A 2004 PUCT decision established $87.3 million as TNMP’s stranded costs. TNMP and other parties have made a series of appeals on the ruling and it is currently before the Texas Supreme Court. TNMP is unable to predict if the Texas Supreme Court will review the decision or the ultimate outcome of this matter.
Interest Rate Compliance Tariff
Following a revision of the interest rate on TNMP’s carrying charge, TNMP filed a compliance tariff to implement the new 8.31% rate. TNMP’s filing proposed to put the new rates into effect on February 1, 2008. Intervenors asserted objections to the compliance filing. PUCT staff urged that the PUCT make the new rate effective as of December 27, 2007 when the PUCT’s order establishing the correct rate became final. After regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. TNMP filed an appeal of this order in the District Court in Austin, Texas. A hearing was held on June 17, 2010. On June 28, 2010, the District Court reversed the PUCT decision and remanded the matter back to the PUCT for a determination that is not retroactive. The PUCT and other parties have appealed the decision to the Texas 3rd Court of Appeals. While there is inherent uncertainty in this type of proceeding, TNMP believes it will ultimately be successful in overturning any ruling that the effective date should be prior to December 27, 2007.
2008 Rate Case
On August 29, 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues, requesting that new rates go into effect in September 2009. In its request, TNMP also asked for permission to implement a catastrophe reserve fund similar to those approved for other transmission and distribution companies in Texas. Catastrophe funds help pay for a utility system’s recovery from natural disasters and acts of terrorism. The PUCT permitted TNMP to file supplemental testimony on costs caused by Hurricane Ike. In March 2009, TNMP filed its supplemental testimony, requesting an additional revenue increase of $15.7 million annually relating to costs incurred during Hurricane Ike and anticipated increased financing costs. In June 2009, TNMP and the other parties in the rate case announced that a unanimous settlement had been reached. The settlement resolves all issues in the rate case and permitted TNMP to increase revenues by $12.7 million annually. This increase reflected interest and other costs associated with its March 2009 debt refinancing and the settlement adjusted the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The rate increase includes recovery of $17.6 million of Hurricane Ike restoration costs plus carrying costs over five years although $0.7 million of the costs incurred by TNMP were not included and were written off in 2009. The settlement authorizes a catastrophe reserve of $1.0 million funded over an eight year period. The settlement was approved by the PUCT in August 2009 and rates went into effect on September 1, 2009. No party appealed the decision and the matter is concluded.
TNMP now has the ability to update its transmission rates annually to reflect changes in its invested capital. Updated rates would reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.
Energy Efficiency
On October 28, 2009, TNMP filed an application for approval of its 2010 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP’s estimated the costs of its 2010 energy efficiency programs to be $2.6 million and requested to collect this amount based on a per customer charge over 11 months. The PUCT staff and intervenors took no issue with TNMP’s application. TNMP implemented the factor effective February 1, 2010. On April 30, 2010, TNMP filed an application for approval of its 2011 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP estimated the costs of its 2011 energy efficiency programs to be $2.7 million and requested to collect this amount based on a per
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
customer charge over 12 months. The PUCT staff and intervenors did not take issue with TNMP’s application. The 2011 energy cost recovery rider was approved by the PUCT on July 8, 2010 and was implemented on January 1, 2011.
Transmission Rate Filings
On March 2, 2010, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $33.8 million, with a total revenue requirement increase of $5.5 million. The requested updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The PUCT approved the interim adjustment on May 14, 2010. On August 25, 2010, the PUCT amended its rules permitting utilities to file interim adjustments to update transmission rates to reflect changes in invested capital. Beginning October 25, 2010, the revised rule now permits the utility to file twice a year. The prior version of the rule limited utilities to a single annual filing.
Advanced Meter System Deployment and Surcharge Request
On May 26, 2010, TNMP filed a request with PUCT to approve TNMP’s proposed advanced meter deployment. The filing also requested a surcharge to collect $158 million in costs over 12 years, including recovery of capital expenditures of $70.6 million. On June 1, 2010, the PUCT referred the matter to the State Office of Administrative Hearings. On January 6, 2011, the administrative law judge modified the procedural schedule and set this matter for hearing on April 18, 2011. Due to changes in the tax law, TNMP filed supplemental testimony on February 16, 2011 to reflect the effects of the bonus depreciation, new WACC, and other changes. The filing amends the requested surcharge to collect $126 million, including capital expenditures of $70.2 million incurred through 2015.
2010 Rate Case
On August 26, 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues, requesting that new rates go into effect on October 1, 2010. In its request, TNMP also asked for permission to update its catastrophe reserve fund that would be utilized to pay for a utility system’s costs in recovering from natural disasters and acts of terrorism. Additionally, TNMP requested a rate rider to recover costs to storm harden its system. On November 8, 2010, the presiding ALJ severed the rate case expense issues into a separate proceeding. In December 2010, the parties announced to the ALJ that a settlement had been reached in the case and a stipulation supporting the settlement was filed. The settlement provided for a revenue requirement increase of $10.25 million beginning February 1, 2011, a return on equity of 10.125%, and a hypothetical 55%/45% debt-equity capital structure. The PUCT approved the settlement on January 27, 2011.
2010 Rate Case Expense Proceeding
As indicated above, the determination of the amount of reasonable rate case expenses incurred by TNMP and other parties in the 2010 rate case was severed into a separate proceeding. On January 26, 2011, the ALJ set a procedural schedule requiring the parties who participated in the 2010 rate case to file testimony supporting their respective incurred expenses. A hearing must be requested by March 14, 2014. TNMP is unable to predict the outcome of this matter.
Remand of ERCOT Transmission Rates for 1999 and 2000
Following a variety of appeals, the ERCOT Transmission Rates approved in 1999 and 2000 were recently remanded back to the PUCT. The issues relevant to TNMP are addressed in three separate dockets, but those proceedings are expected to be heard jointly. These dockets concern the recalculation of rates for the 4th quarter of 1999 and all of 2000 to correct over-payments made by certain market participants and the recovery of additional, undetermined transmission costs by City Public Service Board of San Antonio. As these proceedings have just started, TNMP cannot predict the ultimate outcome of this matter.
B-109
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(18) Environmental Issues
The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes.
The Company records its environmental liabilities as other deferred credits when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. Unless there is a probable amount, the Company records the lower end of such reasonably likely range of costs (classified as other deferred credits at undiscounted amounts).
The Company’s recorded liability estimated to remediate its identified sites was as follows:
The Company recorded the following expenses for environmental remediation:
The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as the extent and nature of contamination, the scarcity of reliable data for identified sites, and the time periods over which site remediation is expected to occur. The Company expects that the majority of the December 31, 2010 environmental liability will be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
(19) Accumulated Other Comprehensive Income (Loss)
AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. The following table sets forth each component of AOCI, net of income taxes:
(20) Related Party Transactions
PNMR, PNM, TNMP, and Optim Energy are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR, its subsidiaries, and Optim Energy in accordance with shared services agreements. These services are billed on a monthly basis to the business units. Billings are at cost, except for Optim Energy, which includes a profit element. There is also a services agreement for Optim Energy to provide services to PNMR.
PNMR files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PNMR and each of its affiliated companies. These agreements provide that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PNMR. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PNMR to the extent that PNMR is able to utilize those benefits.
B-111
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
See Note 6 for information on intercompany borrowing arrangements and Note 7 for intercompany lease arrangements. See Note 22 for information concerning Optim Energy. The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:
(1) PNM Shared services include billings to PNM Gas of $0.9 million and $16.1 million in 2009 and 2008.
(21) New Accounting Pronouncements
Information concerning recently issued accounting pronouncements that have not been adopted by the Company and could have a material impact, is presented below.
Accounting Standards Update 2010-06 - Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements
The FASB released amended guidance related to disclosures of fair value measurements. The update requires entities to enhance interim and annual disclosures about fair value measurements, specifically:
-Further disaggregate the level presented for debt and equity securities
-Disclose the amount and reason for significant transfers between fair value categories Level 1 and Level 2
-Disclose information about the purchases, sales, issuances, and settlements for items in Level 3 of the fair value measurements on a gross basis rather than net
The enhanced disclosure for the first two items was effective for the interim period ended March 31, 2010 and is included in Note 8 to the extent applicable. The third item regarding Level 3 information is effective for the interim period ending March 31, 2011 and will be included at that time.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Accounting Standards Update 2010-20 - Receivables: Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses
In July 2010, the FASB released guidance requiring enhanced disclosures providing a greater level of disaggregated information about the credit quality of an entity’s financing receivables and the allowance for credit losses, as well as credit quality indicators, past due accounts information, and modifications of financing receivables. The enhanced disclosures are effective and presented for December 31, 2010 and the disclosures about activity that occurs during a reporting period are effective beginning January 1, 2011. Due to the nature of the Company’s receivables, the update will have minimal impact on the Company’s financial statements.
(22) Optim Energy
In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each have a 50 percent ownership interest in Optim Energy, a limited liability company.
Impairment Considerations
Beginning in 2009 and continuing throughout 2010, Optim Energy has been affected by adverse market conditions, primarily low natural gas and power prices. In addition to these adverse market conditions, recently reported sales of electric generating resources within the ERCOT market area have been transacted at prices (per KW of generating capacity) that are substantially below the amounts recorded for electric generating plants underlying PNMR’s investment in Optim Energy. Under GAAP, these factors are indicators of impairment that required an impairment analyses to be performed as of December 31, 2010, both by Optim Energy of its electric generating plants and by PNMR of its investment in Optim Energy.
GAAP requires that Optim Energy perform the impairment analysis of its electric generating plants using forecasts of future cash flows on an undiscounted basis in order to determine its investments are recoverable. Optim Energy’s analysis indicated that it would be able to recover its investments in electric generating assets based on its estimates of undiscounted future cash flows from operating those plants over their expected useful lives. Therefore, Optim Energy did not record any impairment loss related to its electric generating plants at December 31, 2010.
However, GAAP requires that PNMR develop the impairment analysis of its investment in Optim Energy based on a determination of the investment’s fair value. Determination of fair value is subjective and requires reliance on many assumptions and judgments that future events may show to have been inaccurate. Fair value can be based on the market approach, income approach, or cost approach. In making its determination, PNMR considered recent transactions involving electric generating assets within the ERCOT market area, the forecasted cash flows related to the investment, and preliminary information concerning strategic alternatives for its investment in Optim Energy. PNMR’s determination of the fair value of its investment in Optim Energy is considered a Level 3 measurement under the fair value hierarchy established under GAAP. See Note 8. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax impairment loss of $188.2 million ($113.7 million after-tax), which is reflected within Other Income and Deductions on the Consolidated Statements of Earnings (Loss) of PNMR.
As a result of the adverse market conditions described above, PNMR (in collaboration with Optim Energy and ECJV) has been assessing various strategic alternatives relating to PNMR’s ownership interest in Optim Energy. Discussions regarding various alternatives have been held with several potential parties. Although PNMR has no contractual requirement or agreement to provide Optim Energy with additional financial resources as of the date of this report, based on the exploration of these alternatives to date, it is possible that PNMR may decide to contribute equity and/or other operational assets to Optim Energy or a new venture in order to consummate a strategic transaction. Depending on the form and structure of a strategic transaction, if any, as well as market conditions at the time the strategic transaction is consummated, PNMR may recognize additional impairments based
B-113
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
on relative fair values. No assurances can be given that PNMR will consummate any strategic transaction with respect to its investment in Optim Energy.
Operational Information
Optim Energy has a bank financing arrangement that expires on May 31, 2012, which includes a revolving line of credit. This facility also provides for bank letters of credit to be issued as credit support for certain contractual arrangements entered into by Optim Energy. Cascade and ECJV have guaranteed Optim Energy’s obligations on this facility and, to secure Optim Energy’s obligation to reimburse Cascade and ECJV for any payments made under the guaranty, have a first lien on all assets of Optim Energy and its subsidiaries.
In January 2010, Optim Energy entered into one-year floating-to-fixed interest rate swaps with an aggregate notional amount of $650.0 million. The effect of these swaps was to convert $650.0 million of borrowings under Optim Energy’s credit facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.33% through January 7, 2011, exclusive of loan guaranty fees. These swaps were accounted for as cash-flow hedges.
In June 2009, Optim Energy and NRG Cedar Bayou Development Company, LLC completed a jointly developed 550 MW combined-cycle natural gas unit at the existing NRG Cedar Bayou Generating Station near Houston. Optim Energy’s share of this unit is 275 MW and its share of the construction costs was $209.6 million. Optim Energy financed its portion of the Cedar Bayou construction with borrowings under its existing credit facility and operating cash flows.
PNMR has no commitments or guarantees with respect to Optim Energy.
Summarized financial information for Optim Energy is as follows:
(1) Represents the Texas Margin Tax, which is considered an income tax.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Revenue related to power sales and purchases is included net in operating revenues. Costs related to fuel purchases and sales are recorded net in cost of sales.
PNMR has a basis difference between its recorded investment in Optim Energy and 50 percent of Optim Energy’s equity resulting from Optim Energy’s acquisition of the Altura (also known as Twin Oaks) plant from PNMR in 2007. The portion of the basis difference related to contract amortization ended in 2010 and other basis differences, including a difference related to emission allowances that would have continued through the life of the Altura plant, were eliminated with the impairment discussed above. The basis difference adjustment detailed above relates mainly to contract amortization with insignificant offsets related to the other minor basis difference components.
Optim Energy individually valued each asset and liability of the Altura plant acquired from PNMR and the acquisition of Altura Cogen and initially recorded them on its balance sheet at the determined fair value. For both transactions, this accounting resulted in amortization since contracts acquired were out of market and emission allowances, while acquired from government programs without cost to Optim Energy, had market value. During 2010, 2009, and 2008, Optim Energy recorded, as an increase (decrease) to operating revenues, income from amortization of contracts acquired of $(13.6) million, $(6.7) million, and $2.2 million and amortization expense on emission allowances of $5.2 million, $4.7 million, and $11.2 million, which was recorded in cost of sales.
In July 2008, a ruling by the U.S. Court of Appeals for the District of Columbia Circuit Court invalidated CAIR. This ruling appeared to remove the need for emissions allowance credits under the CAIR program. However, in December 2008, CAIR was temporarily reinstated by the courts. Optim Energy has emissions allowances inventory from the acquisitions of the Altura Cogen plant and the Twin Oaks plant, a portion of which are under the CAIR program. During 2008, Optim Energy recorded a pre-tax write off of $31.7 million for all inventory under the CAIR program. As of December 31, 2010 and 2009, Optim Energy had $47.0 million and $54.6 million remaining in inventory for emission allowances intended for its emission usage requirements and not granted under the CAIR program.
Optim Energy values its NOx emissions allowance inventory held for sale at the lower of cost or market. In December 2010 and 2009, Optim Energy reduced the value of its held for sale NOx emission allowances by $2.3 million and $51.6 million because of declining forward prices and significant price declines in the illiquid emission
B-115
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
allowance market. At December 31, 2010 and 2009, Optim Energy had $4.8 million and $4.9 million remaining held for sale allowances in inventory.
The assets of Altura transferred to Optim Energy included the development rights for a possible 600 megawatt expansion of the Twin Oaks plant, which was classified as an intangible asset. Optim Energy made a strategic decision not to pursue the Twin Oaks expansion and, in 2008, wrote off the development rights as an impairment of intangible assets amounting to $21.8 million. In addition $1.2 million of deferred costs related to this project were written off as administrative and general expense.
Optim Energy has a multi-year hedging program. The level of hedging at any given time varies depending on current market conditions and other factors. Economic hedges that do not qualify for or are not designated as cash flow hedges or normal purchases or sales are derivative instruments that are required to be marked to market. Due to the extreme market volatility experienced in the first quarter of 2008 in the ERCOT market, Optim Energy made the decision to exit the speculative trading business and close out the speculative trading positions. Optim Energy incurred $2.4 million of speculative trading losses in 2008 and has since settled all speculative positions.
See Note 6 for a discussion of the impacts of the bankruptcy of LBCS.
On January 6, 2009, LCC filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. LCC is Altura Cogen’s counterparty in several agreements, including the sale of power and steam. LCC also leases Altura Cogen the land for its operating facility and provides other services, including water, to Altura Cogen. The amount outstanding as of December 31, 2008 was fully reserved. In 2010, LCC exited bankruptcy and paid Optim Energy the full receivable from January 6, 2009. Optim Energy reversed the $1.0 million that had been reserved previously. The post-bankruptcy settlement includes, among other things, a reduction in Optim Energy’s posted letter of credit and assumption of the power and steam contract.
(23) Discontinued Operations
PNM Gas
As discussed in Note 2, PNM sold its gas operations, which comprised the PNM Gas segment, on January 30, 2009. Under GAAP, the assets and liabilities of PNM Gas were considered to be held-for-sale as of December 31, 2007 and presented as discontinued operations on the accompanying Consolidated Statements of Earnings (Loss). In accordance with GAAP, no depreciation is recorded on assets held for sale in 2009 and 2008. PNM also retained obligations for certain contingent liabilities that existed at the date of sale. PNM recognized $5.4 million in expense related to these liabilities in the 2009 Results of Operations for PNM Gas. Summarized financial information for PNM Gas is as follows:
B-116
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
Results of Operations
PNM Gas’s cost-of-gas revenues collected from sales-service customers were recovered in accordance with NMPRC regulations through the PGAC and represented a pass-through of the cost of natural gas to the customer. The NMPRC approved an agreement regarding the hedging strategy of PNM Gas and the implementation of a price management fund program which included a continuous monthly balancing account with a carrying charge. PNM Gas used a variety of hedging instruments including fixed price contracts, call options and financial swaps to facilitate the hedge strategy. PNM Gas also entered into physical gas contracts to meet the needs of its retail sales-service customers.
(24) Business Improvement Plan
In 2007, the Company began a business improvement process that included a comprehensive cost structure analysis of its operations and a benchmarking analysis to similar-sized utilities. The Company implemented a series of initiatives designed to manage future operational costs, maintain financial strength and strengthen its regulated utilities. The multi-phase process included a business improvement plan to streamline internal processes and reduce the Company’s work force. The utility-related process enhancements were designed to improve and centralize business functions. Activities contemplated under the business improvement plan have been completed and no significant costs were incurred after 2008.
The Company has existing plans providing severance benefits to employees who are involuntarily terminated due to elimination of their positions. Severance benefits payable under the Company’s existing plans are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. The Company calculated the severance benefits associated with positions that were probable of being eliminated and recorded pre-tax expense of $3.4 million in 2008. In 2008, severance expenses of zero and $0.1 million were recorded by PNM and TNMP. The Company also incurred other costs, primarily consulting fees, related to the business improvement plan of $7.5 million in 2008.
(25) Goodwill and Other Intangible Assets; Impairments
The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its June 6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. Subsequently, TNMP assets that were included in its New Mexico operations, including goodwill of $102.8 million, were transferred to PNM. Of the $79.3 million of other intangible assets acquired in the TNP acquisition, $68.8 million related to the trade name “First Choice.” The trade name is considered to have an indefinite useful life;
B-117
PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
therefore, no amortization is recorded. The other $10.5 million intangible asset related to the First Choice customer list. The useful life of the customer list was estimated to be approximately eight years.
The Company evaluates its goodwill and non-amortizing intangible assets for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill or intangible assets may be impaired. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit. The fair value of each reporting unit is estimated using a discounted cash flow methodology. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment for each reporting unit.
For non-amortizing intangibles other than goodwill, the Company compares the fair value of the intangible asset to its recorded value. For goodwill, the first step of the impairment test requires that the Company compare the fair value of each reporting unit with its carrying value, including goodwill. If as a result of this analysis, the Company concludes there is an indication of impairment in a reporting unit having goodwill, the Company is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the Company to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss is reflected in results of operations.
The market capitalization of PNMR’s common stock was significantly below book value during 2008, which is an indicator that intangible assets may be impaired. In addition, changes in the ERCOT market significantly impacted the results of operations of First Choice. The Company performed its annual testing of intangible assets as of April 1, 2008. As a result of this analysis, the Company concluded there was an indication of impairment in the reporting units having goodwill and of the First Choice trade name and recorded impairments of $135.0 million for goodwill and $9.0 million for the First Choice trade name. The financial challenges facing First Choice continued throughout 2008 and were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in significant increases in the levels of uncollectible accounts. Due to these conditions, additional impairment testing was performed for First Choice as of December 31, 2008. As a result, the Company recorded additional impairment losses of $39.4 million for First Choice goodwill and $33.6 million for the First Choice trade name at December 31, 2008. Although the impairments of goodwill, aggregating $174.4 million, have no income tax effects, the impairment of the First Choice trade name amounting to $42.6 million does have an income tax effect and results in an after-tax impact of $27.7 million. The impairments do not impact the Company’s cash flows. Other than the 2008 impairments, the Company has not recorded any impairments of goodwill.
The 2009 and 2010 annual evaluations did not indicate impairments of any of PNMR’s reporting units. While the market capitalization of PNMR’s common stock remains significantly below book value, PNMR’s stock price has increased since April 1, 2008. In addition, improved regulatory treatment has been experienced by PNM in New Mexico and by TNMP in Texas. Furthermore, the First Choice business stabilized in 2009 and has remained stable throughout 2010, primarily due to more predictable power and fuel price patterns in the ERCOT market. These factors have resulted in more predictable earnings and increased fair values of the reporting units. Since the annual evaluations, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
The changes in the carrying amount of goodwill by reportable segment for the years ended December 31, 2010, 2009, and 2008 were as follows:
The components of PNMR’s other identifiable intangible assets are as follows:
The Company evaluates its amortizing intangible assets for impairment only when circumstances indicate that the intangible assets may be impaired. Due to conditions at First Choice described above, the Company performed an impairment test of the First Choice customer list asset as of December 31, 2008 and as a result, recorded a pre-tax impairment of $4.8 million ($3.1 million after-tax) for this asset.
See Note 22 for a discussion of impairments recorded by Optim Energy and the impairment of PNMR’s investment in Optim Energy.
(26) Quarterly Operating Results (Unaudited)
Unaudited operating results by quarters for 2010 and 2009 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included. On January 30, 2009, PNM completed the sale of PNM Gas, which is considered discontinued operations and excluded from continuing operations in the tables below. See Note 2 and Note 23.
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PNM RESOURCES, INC. AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2010, 2009 and 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
PNM Resources, Inc. and Public Service Company of New Mexico
Albuquerque, New Mexico
We have audited the consolidated financial statements of PNM Resources, Inc. and subsidiaries and Public Service Company of New Mexico and subsidiaries (collectively, the “Companies”) as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the Companies’ internal control over financial reporting as of December 31, 2010, and have issued our reports thereon dated March 1, 2011; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Companies listed in Item 15. These consolidated financial statement schedules are the responsibility of the Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1, 2011
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Texas-New Mexico Power Company
Lewisville, Texas
We have audited the consolidated financial statements of Texas-New Mexico Power Company and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and have issued our report thereon dated March 1, 2011; such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audit also included the consolidated financial statement schedule of the Company listed in Item 15. The consolidated financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audit. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Dallas, Texas
March 1, 2011
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SCHEDULE I
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
BALANCE SHEETS
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SCHEDULE I
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
STATEMENTS OF EARNINGS
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SCHEDULE I
PNM RESOURCES, INC.
CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY
STATEMENTS OF CASH FLOWS
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SCHEDULE II
PNM RESOURCES, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
(a) Totals reflect continuing operations.
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SCHEDULE II
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS
(a) Totals reflect continuing operations.
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SCHEDULE II
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
PNMR
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this annual report, PNMR conducted an evaluation under the supervision and with the participation of PNMR’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.
(b) Management’s report on internal control over financial reporting.
“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-2. This report is incorporated by reference herein.
(c) Changes in internal controls.
There have been no changes in PNMR’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, PNMR’s internal control over financial reporting.
PNM
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this annual report, PNM conducted an evaluation under the supervision and with the participation of PNM’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.
(b) Management’s report on internal control over financial reporting.
“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-3. This report is incorporated by reference herein.
(c) Changes in internal controls.
There have been no changes in PNM’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, PNM’s internal control over financial reporting.
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TNMP
(a) Evaluation of disclosure controls and procedures.
As of the end of the period covered by this annual report, TNMP conducted an evaluation under the supervision and with the participation of TNMP’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.
(b) Management’s report on internal control over financial reporting.
“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-4. This report is incorporated by reference herein.
(c) Changes in internal controls.
There have been no changes in TNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF PNMR AND CORPORATE GOVERNANCE
Reference is hereby made to “Proposal 1: Elect Ten Directors” in PNMR’s Proxy Statement relating to the annual meeting of stockholders to be held on May 17, 2011 (the “2011 Proxy Statement”), to PART I, SUPPLEMENTAL ITEM - “EXECUTIVE OFFICERS OF THE COMPANY” in this Form 10-K, “Other Matters”-“Section 16(a) Beneficial Ownership Reporting Compliance”, “Code of Ethics” and “Board Committees and Their Functions”-“Audit and Ethics Committee” in the 2011 Proxy Statement. The Company intends to satisfy the disclosure requirements of Form 8-K relating to amendments to the Company’s code of ethics applicable to its senior executive and financial officers by posting such information on its Internet website. Information about the Company’s website is included under Part I, Item 1 - “Company Website.”
PNMR’s common stock is listed on the New York Stock Exchange. As a result, PNMR’s Chief Executive Officer is required to make an annual certification to the New York Stock Exchange stating that he was not aware of any violations by PNMR of the New York Stock Exchange corporate governance listing standards. PNMR’s Chief Executive Officer made the most recent certification to the New York Stock Exchange on June 16, 2010.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to “Executive Compensation”, and all subheadings thereunder from “Compensation Discussion and Analysis” to “Potential Payments Upon Termination or Change in Control”, “Director Compensation”, and “Board Committees and Their Functions”-“Compensation and Human Resources Committee”-“Interlocks” in the 2011 Proxy Statement.
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ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Reference is hereby made to “PNM Resources Common Stock Owned by Executive Officers and Directors,” “Ownership of More Than Five Percent of PNM Resources Common Stock” and “Equity Compensation Plan Information” in the 2011 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Reference is hereby made to “Related Person Transactions,” “Other Governance Policies-Related Person Transactions Policy,” and “Director Independence” in the 2011 Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Reference is hereby made to “Audit and Ethics Committee Report” and “Independent Auditor Fees” in the 2011 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2011 Proxy Statement for PNMR. All such fees are fees of PNMR.
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PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Note: Separate financial statements of 50 percent or less owned persons will be filed by amendment to PNMR’s Form 10-K to the extent required by Article 3.09 of SEC Regulation S-X.
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(a) -3- B.
Exhibits Incorporated By Reference:
The documents listed below are being filed (as shown above) or have been previously filed on behalf of PNM Resources, PNM or TNMP and are incorporated by reference to the filings set forth below pursuant to Exchange Act Rule 12b-32 and Regulation S-K section 10, paragraph (d).
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* One or more additional documents, substantially identical in all material respects to this exhibit, have been entered into, relating to one or more additional sale and leaseback transactions. Although such additional documents may differ in other respects (such as dollar amounts and percentages), there are no material details in which such additional documents differ from this exhibit.
** Designates each management contract or compensatory plan or arrangement required to be identified pursuant to paragraph 3 of Item 15(a) of Form 10 -K.
 Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
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