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TEXAS NEW MEXICO POWER CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
[February 28, 2014]

TEXAS NEW MEXICO POWER CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Edgar Glimpses Via Acquire Media NewsEdge) 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 Part II, Item 8, unless otherwise specified. Certain of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR EXECUTIVE SUMMARYOverview and Strategy PNMR is a holding company with two regulated utilities serving approximately 746,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. In the latter part of 2011, PNMR exited both of its competitive businesses, First Choice and Optim Energy, and repositioned itself as a holding company solely operating its electric utilities, PNM and TNMP.

Strategic Goals PNMR is focused on achieving the following strategic goals: • Earning authorized returns on its regulated businesses • Maintaining investment grade credit ratings • Providing a top-quartile total return to investors In conjunction with these goals, PNM and TNMP are dedicated to: • Achieving industry-leading safety performance • Maintaining strong plant performance and system reliability • Delivering a superior customer experience • Demonstrating environmental leadership in its business operations Earning Authorized Returns on Regulated Businesses PNMR's success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities and their strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships.

Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. The NMPRC has approved rate riders for renewable energy and energy efficiency that also allow for more timely recovery of investments and improve the ability to earn authorized returns from PNM's retail customers. In 2012, PNM saw additional progress toward achieving authorized returns for its FERC regulated transmission and generation services. PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. Additional information about rate filings is provided in Note 17.

Fair and timely rate treatment from regulators is crucial to PNMR achieving its strategic goals because it leads to PNM and TNMP earning their allowed returns.

PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by credit rating agencies and would further improve the Company's ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased total returns to investors.

PNM's interest in PVNGS Unit 3 is currently excluded from NMPRC jurisdictional rates. While PVNGS Unit 3's financial results are not included in the authorized returns on its regulated business, it impacts PNM's earnings and has been demonstrated to be a valuable asset. Power generated from PNM's 134 MW interest in PVNGS Unit 3 is currently sold into the wholesale market and any earnings or losses are attributable to shareholders. PNM has requested NMPRC approval to include PVNGS Unit A- 28-------------------------------------------------------------------------------- Table of Contents 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018 as part of compliance with the requirements for BART at SJGS discussed below.

Maintaining Investment Grade Credit Ratings PNM is committed to maintaining investment grade credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. S&P raised the corporate credit ratings and senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM, on April 5, 2013. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody's changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. On January 30, 2014, Moody's raised the credit ratings for PNMR, PNM and TNMP by one notch, while maintaining the positive outlook. All of the Company's credit ratings are now investment grade by both Moody's and S&P.

Providing Top-Quartile Total Returns to Investors PNMR's strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10 percent to 13 percent.

PNMR's long-term target is a dividend payout ratio of 50 percent to 60 percent of its ongoing earnings. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP. The annual common stock dividend was raised by 16 percent in February 2012, 14 percent in February 2013, and 12 percent in December 2013. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target.

The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus In addition to its strategic goals, PNMR's strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers and communities. To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power PNMR and its utilities are keenly aware of the roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. The utilities also work to ensure that rates reflect actual costs of providing service.

Investing in PNM's and TNMP's infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with top-tier electric reliability.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through the end of 2013, TNMP had completed installation of more than 128,000 smart meters, which is approximately 56% of the anticipated total. TNMP's deployment is expected to be completed in 2016.

As part of the State of Texas' long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In 2014, TNMP will install a new outage management system that will leverage capabilities of the smart meters to enhance TNMP's responsiveness to outages.

During the 2011 to 2013 period, PNM and TNMP together invested $937.5 million in utility plant, including substations, power plants, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station, to be located near Belen, New Mexico. PNM filed a request in May 2013 with the NMPRC for approval to construct the La Luz plant, which is expected to begin in 2014, with the facility going into service in 2016. PNM also announced an agreement to purchase Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000. The purchase has been approved by the NMPRC and FERC.

Closing on the Delta purchase will occur once certain environmental issues are resolved.

A- 29-------------------------------------------------------------------------------- Table of Contents Environmentally Responsible Power PNMR has a long-standing record of environmental stewardship. In 2012 and 2013, its environmental focus has been in three key areas: • Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits • Preparing to meet New Mexico's increasing renewable energy requirements as cost-effectively as possible • Increasing energy efficiency participation Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM's power plants. The fresh water used per MWh generated has dropped by 21.0% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. In addition to the above areas of focus, the Company is also working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and has set goals for even further reductions.

Renewable Energy PNM's 2013 renewable procurement strategy almost doubled PNM's existing solar capacity with the addition of 21.5 MW of utility-owned solar capacity. In addition to the solar expansion, the 2013 plan included a 20-year agreement to purchase energy from a geothermal facility built near Lordsburg, New Mexico. The facility began providing power to PNM in January 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. PNM's 2014 renewable procurement strategy calls for the construction of an additional 23 MW of utility-owned solar capacity, a 20 year PPA for the output of an existing 102 MW wind energy center, and the purchase of RECs in 2014 and 2015 to meet the RPS.

In addition to PNM's utility-owned PV solar facilities, PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts. The facility was the nation's first solar storage facility fully integrated into a utility's power grid.

PNM also purchases 204 MW of wind power and power from a customer-owned distributed solar generation program having an installed capacity of 30.5 MW at the end of 2013. These renewable resources are key means for PNM to meet the RPS and related regulations, which require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC.

In 2013, PNM made renewable procurements consistent with the 2013 plan approved by the NMPRC. PNM believes its currently planned resources will enable it to comply with the NMPRC's diversity requirements, as amended in December 2012. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico's escalating RPS requirements.

SJGS PNM continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. Additional information about BART at SJGS is contained in Note 16.

In August 2011, EPA issued a FIP for regional haze that would require the installation of SCRs on all four units at SJGS by September 2016. Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP from the State of New Mexico. The revised SIP has been approved by the EIB and submitted to EPA for its approval. EPA action is projected for late 2014.

Contemporaneously with the signing of the non-binding agreement, EPA indicated in writing that if the above plan does not move forward due to circumstances outside of the control of PNM and NMED, EPA will work with the State of New Mexico and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the new state plan.

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requests authorization to: A- 30-------------------------------------------------------------------------------- Table of Contents • Retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs • Include PNM's ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018 • Allow cost recovery for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 • Exchange ownership of 78 MW of PNM's capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 PNM requested the NMPRC issue its final ruling on the application no later than December 2014. On February 11, 2014, PNM's application was determined to be complete. The Hearing Examiner indicated the NMPRC should proceed with the review of PNM's application and establish a schedule that would allow NMPRC action on the application by the end of 2014. The Hearing Examiner indicated that he will schedule a public hearing to begin on August 19, 2014.

The December 20, 2013 filing also identifies a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM's share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. Specific approvals to acquire these facilities and the treatment of associated costs will be requested in future filings.

In connection with the implementation of the revised plan and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants have expressed a desire to exit their ownership in the plant. As a result, the SJGS participants are attempting to negotiate a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The SJGS participants have engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners. Although discussions are continuing, no agreements have been reached. Owners of the affected units also may seek approvals of their utility commissions or governing boards. PNM is unable to predict the outcome of the negotiations.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and will take reasonable and prudent actions as it deems necessary.

PNM cannot predict the outcome of this matter.

This revised BART plan would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS. It has the added advantage of reducing other emissions beyond NOx, including SO2, particulate matter, CO2, and mercury, as well as reducing water usage. PNM has begun taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract. PNM can provide no assurance that the requirements of this plan will be accomplished at all or within the required timeframes.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO2, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 41 percent, SO2 by 60 percent, particulate matter by 69 percent, and mercury by 99 percent.

Energy Efficiency Energy efficiency also plays a significant role in helping to keep customers' electricity costs low while continuing to meet their energy needs. PNM's and TNMP's energy efficiency and load management portfolios continue to achieve robust results. In 2013, annual energy saved as a result of PNM's portfolio of energy efficiency programs was approximately 75 GWh. This is equivalent to the annual consumption of approximately 10,200 homes in PNM's service territory.

PNM's load management and energy efficiency programs also help lower peak demand requirements. TNMP's energy efficiency programs in 2013 resulted in energy savings totaling an estimated 17.0 GWh. This is equivalent to the annual consumption of approximately 1,650 homes in TNMP's service territory.

A- 31-------------------------------------------------------------------------------- Table of Contents Creating Value for Customers and Communities The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at a regional and community level. In 2013, PNM refocused its efforts to improve the customer experience through an integrated marketing and communications strategy that encompassed brand repositioning and advertising, customer service improvements, and strategic customer and stakeholder engagement.

Integrated communication around known satisfaction drivers, including billing and payment options, bill redesign, energy efficiency, and environmental and community stewardship ensured PNM retained traction from the previous year, as well as gained new ground in critical areas, notably corporate citizenship perceptions. PNM's perceived value to customers has also improved.

Recognizing the importance of environmental stewardship to customers and other stakeholders, PNM expanded engagement with environmental stakeholders to promote ongoing dialogue and input. Similarly, PNM also proactively communicated with communities about its efforts and plans related to environmental stewardship.

Customers took note of PNM's efforts in this area. A nationally recognized customer satisfaction benchmark revealed gains in awareness of PNM's efforts to improve environmental impact, as well as customer perceptions around the commitment to preserving the environment now and for future generations.

Benchmark data also demonstrates positive movement in the communication component of the customer experience.

Through outreach, collaboration, and various community-oriented programs, PNMR has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, legislators, and intervenors.

Building off work that began in 2008, PNM has continued outreach efforts to connect low-income customers with nonprofit community service providers offering support and help with such needs as utility bills, food, clothing, medical programs, services for seniors, and weatherization. In 2013, PNM hosted 22 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.3 million of assistance with utility bills to 3,610 families in 2013. In 2013, PNM committed funding of $0.9 million to the PNM Good Neighbor Fund.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In 2013, PNMR committed funding of $3.5 million to the PNM Resources Foundation. For 2013, the foundation awarded $0.2 million to support 56 projects in New Mexico to provide shade structure installations, window replacements, and efficient appliance purchases. Since the program's inception in 2008, Reduce Your Use grants have provided nonprofit agencies in New Mexico with a total of $1.4 million of support. In 2013, in connection with the PNM Resources Foundation's 30th anniversary, the foundation awarded thirty $10,000 environmental grants to nonprofit agencies.

PNM continues to expand its environmental stakeholder outreach, piloting small environmental stakeholder dialogue groups on key issues such as renewable energy and energy efficiency planning. PNM also employed proactive stakeholder outreach in two key projects - the development of PNM's renewable energy procurement plans that involved distributed solar energy developers early in the conversation and the siting of the planned gas-fired peaking generation facility near Belen, New Mexico, which featured in-depth community involvement and education early in the planning stages of the project. In both cases highly favorable outcomes were achieved, and controversial negative media coverage was virtually eliminated.

In Texas, community outreach has focused on supporting employee volunteerism, as well as customer education to address questions about the ongoing smart meter deployment. TNMP also offers energy efficiency programs specific to government buildings and schools and has successfully used the programs to improve customer relationships.

Economic Factors In 2013 and 2012, PNM experienced annualized decreases in weather-normalized, retail load of 1.8% and 0.7%. TNMP experienced annualized increases in weather-normalized, retail load of 2.6% in 2013 and 3.7% in 2012. In recent years, New Mexico and Texas have fared better than the national average in unemployment. However, New Mexico's figures may be misleading due to people dropping out of the workforce. Employment growth is a stronger predictor of load. Texas' employment growth rates are well above the national rate, while New Mexico's employment remains relatively flat.

A- 32-------------------------------------------------------------------------------- Table of Contents Results of Operations A summary of net earnings attributable to PNMR is as follows: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions, except per share amounts) Net earnings $ 100.5 $ 105.5 $ 176.4 $ (5.0 ) $ (70.9 ) Average common and common equivalent shares 80.4 80.4 89.8 - (9.4 )Net earnings per diluted share $ 1.25 $ 1.31 $ 1.96 $ (0.06 ) $ (0.65 ) The components of the changes in earnings from continuing operations attributable to PNMR by segment are: Change 2013/2012 2012/2011 (In millions) PNM $ (3.4 ) $ 37.0 TNMP 2.4 4.4 First Choice - (24.1 ) Corporate and Other (4.0 ) (88.2 ) Net change $ (5.0 ) $ (70.9 ) PNMR's operational results were affected by the following: • Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17 • Lower retail load at PNM partially offset by higher retail load in at TNMP • Milder weather • Fluctuating prices for sales of power from PVNGS Unit 3 • Increased income tax expense due to impairments of state tax credits and a change in state tax rate (Note 11) • Exit from unregulated businesses - PNMR sold First Choice in 2011, resulting in a pre-tax gain of $174.9 million, which wasincluded in the Corporate and Other segment. The results of operations only include First Choice through October 31, 2011.

• Decrease in the number of common and common equivalent shares, primarily due to PNMR's purchase of its equity as described in Note 6 • Other factors impacting results of operation for each segment are discussed under Results of Operations below Liquidity and Capital Resources The Company has revolving credit facilities that provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which expire in October 2018. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $718.5 million at February 21, 2014. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

The Company projects that its total capital requirements, consisting of construction expenditures and dividends, will total $2,564.5 million for 2014-2018. The construction expenditures include estimated amounts related to environmental upgrades at SJGS to address regional haze and the identified sources of replacement capacity under the revised plan for compliance described in Note 16. The construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources needed to meet needs outlined in PNM's current IRP, and environmental upgrades at Four Corners. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2014-2018 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company's capital requirements.

A- 33-------------------------------------------------------------------------------- Table of Contents RESULTS OF OPERATIONS 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 2 for more information on PNMR's operating segments.

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 Part I, Item 1 and to Part II, Item 7A.

Risk Factors.

PNM The table below summarizes operating results for PNM: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions) Electric operating revenues $ 1,116.3 $ 1,092.3 $ 1,057.3 $ 24.0 $ 35.0 Cost of energy 374.7 353.6 362.2 21.1 (8.6 ) Margin 741.6 738.6 695.1 3.0 43.5 Operating expenses 428.6 435.4 438.8 (6.8 ) (3.4 ) Depreciation and amortization 103.8 97.3 94.8 6.5 2.5 Operating income 209.2 205.9 161.4 3.3 44.5 Other income (deductions) 21.5 26.5 19.9 (5.0 ) 6.6 Net interest charges (79.2 ) (76.1 ) (75.3 ) (3.1 ) (0.8 ) Segment earnings before income taxes 151.5 156.3 106.0 (4.8 ) 50.3 Income (taxes) (48.8 ) (50.7 ) (37.4 ) 1.9 (13.3 ) Valencia non-controlling interest (14.5 ) (14.1 ) (14.0 ) (0.4 ) (0.1 ) Preferred stock dividend requirements (0.5 ) (0.5 ) (0.5 ) - - Segment earnings $ 87.6 $ 91.0 $ 54.0 $ (3.4 ) $ 37.0 The table below summarizes the significant changes to total revenues, cost of energy, and margin: 2013/2012 Change 2012/2011 Change Total Cost of Total Cost of Revenues Energy Margin Revenues Energy Margin (In millions) Retail rate increases $ - $ - $ - $ 40.3 $ - $ 40.3 Customer usage/load (8.6 ) - (8.6 ) (4.8 ) - (4.8 ) Weather (3.3 ) - (3.3 ) (3.0 ) - (3.0 ) Transmission (1.6 ) 1.0 (2.6 ) 1.1 (0.2 ) 1.3 Wholesale rate increase 2.9 - 2.9 4.0 - 4.0 Unregulated margins 2.8 (2.7 ) 5.5 (5.9 ) 1.1 (7.0 ) Energy efficiency rider (2.1 ) - (2.1 ) 8.9 - 8.9 Renewable energy rider 14.7 6.3 8.4 6.9 2.0 4.9 Net unrealized economic hedges (0.6 ) (0.9 ) 0.3 (3.3 ) (1.1 ) (2.2 ) Other 19.8 17.4 2.5 (9.2 ) (10.4 ) 1.1 Net change $ 24.0 $ 21.1 $ 3.0 $ 35.0 $ (8.6 ) $ 43.5 A- 34-------------------------------------------------------------------------------- Table of Contents The following table shows PNM operating revenues by customer class and average number of customers: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions, except customers) Residential $ 411.6 $ 409.0 $ 390.4 $ 2.6 $ 18.6 Commercial 415.6 413.3 386.4 2.3 26.9 Industrial 74.6 78.6 73.8 (4.0 ) 4.8 Public authority 25.7 25.5 24.0 0.2 1.5 Economy service 32.9 25.4 21.1 7.5 4.2 Transmission 38.2 39.4 43.6 (1.2 ) (4.2 ) Firm-requirements wholesale 42.4 39.4 34.1 3.0 5.3 Other sales for resale 67.5 47.4 69.3 20.1 (21.9 ) Mark-to-market activity 0.3 0.9 4.2 (0.6 ) (3.3 ) Other 7.5 13.4 10.4 (5.9 ) 3.0 $ 1,116.3 $ 1,092.3 $ 1,057.3 $ 24.0 $ 35.0 Average retail customers (thousands) 508.2 505.6 503.9 2.6 1.7 The following table shows PNM GWh sales by customer class: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (Gigawatt hours) Residential 3,304.3 3,323.5 3,402.8 (19.2 ) (79.3 ) Commercial 3,954.8 4,022.2 4,043.8 (67.4 ) (21.6 ) Industrial 1,041.2 1,136.0 1,132.1 (94.8 ) 3.9 Public authority 266.4 279.2 282.1 (12.8 ) (2.9 ) Economy Service 719.3 635.3 428.8 84.0 206.5 Firm-requirements wholesale 654.1 652.0 650.4 2.1 1.6 Other sales for resale 2,061.9 1,652.2 2,076.8 409.7 (424.6 ) 12,002.0 11,700.4 12,016.8 301.6 (316.4 ) On August 21, 2011, PNM implemented a $72.1 million annual non-fuel rate increase for its retail customers. This rate increase improved 2012 revenues and margins by $40.3 million. There was no retail rate increase in 2013. For 2013, retail sales were lower compared to 2012 reflecting a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery. PNM's weather normalized and leap-year adjusted retail KWh sales were lower in 2013 by 1.8%, which decreased margin $8.6 million compared to 2012 primarily due to the sluggish economy. In spite of the economic pressures, PNM experienced growth in average retail customers of 0.5% in 2013 compared to 2012. Weather negatively impacted revenues and margin by $3.3 million in 2013 as cooling degree days were 10.7% lower in 2013 than in 2012. In 2012, lower retail KWh sales, primarily in the residential and commercial customer classes, reflecting lower weather normalized and leap-year adjusted average usage per customer, decreased revenues and margins by $4.8 million. In addition, cooling degree days were 2.3% higher in 2012 compared to 2011, but were more than offset by lower heating degree days of 12.4%, resulting in lower revenue and margin of $3.0 million. There is no clear indication regarding the future of New Mexico's economy. Encouraging signs such as growth in the housing industry, increased tax revenue in the Albuquerque metropolitan area, and unemployment rates below the national average are contrasted by indicators such as flat population growth and low job growth.

In 2013, lower transmission revenues as a result of expiration of contracts combined with higher third-party transmission expenses incurred to deliver power to the retail customers reduced margins by $2.6 million. In 2012, higher transmission rates as a result of the June 1, 2011 rate increase improved revenues and margins. PNM implemented new rates for NEC, its largest wholesale firm-requirements customer, in April 2012 and for Gallup, its second largest wholesale customer, in July 2013. These increases improved revenues and margins $2.9 million in 2013 and $4.0 million in 2012. PNM has responded to Gallup's request for proposals for long-term power supply. On January 13, 2014, PNM was notified that its proposal was not the highest ranked and Gallup has stated that a contract is being negotiated with the top-ranked bidder. If a contract is executed with the top-ranked A- 35-------------------------------------------------------------------------------- Table of Contents bidder, PNM's contract with Gallup would expire on June 30, 2014. PNM's 2013 revenues for power sold under the Gallup contract were $11.7 million. See Note 17. If PNM does not continue to supply power to Gallup, costs currently being recovered under the Gallup contract would be reallocated and partially included in PNM's next retail rate case filing, which is expected to be filed by the end of 2014. In addition, PNM would consider opportunities to serve other FERC generation customers. PNM is unable to predict the outcome of this matter.

PNM offers several energy efficiency programs and initiatives to its retail customers regulated by the NMPRC. In addition, PNM is allowed to earn incentives on these programs based on energy savings of the programs. PNM recovers the energy efficiency program costs and incentives via a rate rider. Changes in energy efficiency revenues are offset by changes in operating expenses. In 2013, revenues and margins from the energy efficiency rider were lower by $2.1 million due to lower KWh sales and a decrease in the recovery rate. In 2012, revenues and margins were higher by $8.9 million, primarily related to increases in operating expenses for the energy efficiency programs.

On August 20, 2012, PNM implemented its renewable energy rider, a mechanism approved by the NMPRC, which recovers renewable energy procurement costs, including the investment in and an allowed return on the 22 MW of PNM-owned solar PV facilities constructed to meet the RPS. See Note 17. Revenues under this rider were $6.9 million in 2012 and increased by an additional $14.7 million in 2013. Related cost of energy, reflecting the purchase cost of RECs, was $2.0 million in 2012 and increased by an additional $6.3 million in 2013.

Included in revenues is the earned return component on its investment of $1.2 million in 2012, which increased by $1.8 million in 2013. The remaining revenues from this rider recover renewable energy operating, depreciation, and interest expenses.

Unregulated revenues and margins are primarily associated with PVNGS Unit 3. In 2013, higher market power prices on sales offset by lower available generation increased revenue $2.8 million and margin $2.9 million. In 2012, lower market power prices and increases in nuclear fuel costs resulted in decreases in unregulated revenues of $5.9 million and margin of $5.0 million. In addition, PNM incurred cost of energy for gas imbalance settlements of $2.0 million in 2012 that did not recur in 2013.

Changes in unrealized mark-to-market gains and losses result from economic hedges for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $1.9 million in 2013 compared to unrealized gains of $1.6 million for 2012 increased margin by $0.3 million, primarily due to gains on purchase power contracts of $0.8 million and gains on retail hedges of $0.1 million offset by PVNGS Unit 3 hedge losses of $0.6 million. Unrealized gains of $1.6 million in 2012 compared to unrealized gains of $3.8 million for 2011 decreased margin by $2.2 million due to higher losses on PVNGS Unit 3 hedging activities of $3.5 million, offset by settlement of natural gas hedges of $1.5 million.

Other impacts to revenue and margin include economy energy services to a major customer. In spite of the increase in KWh sales to this customer in 2013 and 2012 there is only a minor impact in margin resulting from providing ancillary services. Other changes in revenues and cost of energy are a pass through with no impact to margin. Other sales for resale revenues and KWh volumes increased in 2013 and decreased in 2012 primarily due to reduced off-system sales at SJGS in 2012 resulting from the fire incident at the mine providing coal to SJGS. See Note 16 for more discussion on the SJGS mine fire incident. Gains from other sales for resale are deferred under the FPPAC with no impact to margin. Lower cost of energy associated with coal mine decommissioning of $1.9 million increased margins in 2013 compared to 2012.

In 2013, operating expenses decreased compared to 2012 due to lower maintenance expenses related to planned outages at SJGS of $8.8 million and unplanned outages at SJGS, PVNGS, and PNM's natural gas plants of $0.9 million, $0.6 million and $2.1 million, partially offset by increased maintenance expense for unplanned outages at Four Corners of $2.3 million. Lower healthcare claims and lower pension and retiree medical expenses (see Note 12) reduced operating expense by $2.3 million in 2013. In addition, capitalized administrative and general expenses increased $3.0 million in 2013 due to increased capital spending, resulting in lower operating expenses compared to 2012. Also, lower energy efficiency expenses of $2.6 million, which are offset in revenues, reduced operating expenses. The allocation of corporate expenses in 2012 included $2.3 million related to business restructuring, which did not recur in 2013. Improved collection experience in 2013 decreased bad debt expense by $0.5 million further decreasing operating expenses. Higher incentive compensation expenses of $2.8 million and the $3.3 million allocation of the Company's contributions to the PNM Resources Foundation and additional financial support to the PNM Good Neighbor Fund increased operating expense in 2013. Property taxes increased $1.8 million due to increased plant in service and higher assessed values and a $0.7 million increase in regulatory, payroll, and gross receipts taxes increased operating expenses in 2013 compared to 2012. In addition, in 2013, PNM concluded that certain costs that were being deferred as regulatory assets were no longer probable of recovery and recorded regulatory disallowances of $12.2 million, including a write-off of $10.5 million of the under-collected balance of the FPPAC pursuant to a settlement in the FPPAC continuation matter discussed in Note 17. As discussed in Note 7, PNM recorded a lease abandonment loss of $6.2 million in operating expenses in 2012.

A- 36-------------------------------------------------------------------------------- Table of Contents In 2012, operating expenses decreased by $2.1 million due to lower maintenance expense at PVNGS and $4.2 million resulting from process improvement initiatives implemented during 2011. In addition, retiree medical and employee health care costs were $1.2 million lower. These reductions in operating expenses were offset by higher expenses associated with planned maintenance outages at SJGS of $7.3 million and union labor negotiation expenses of $1.0 million. Operating expenses also increased in 2012 due to higher energy efficiency expenses of $11.4 million and renewable expenses of $1.0 million, which are offset in revenues, and the lease abandonment loss of $6.2 million, as discussed above. In addition, property taxes were higher by $2.2 million as the result of increased plant additions, higher property tax rates, and a settlement with a Native American pueblo. In 2011, operating expenses reflect a regulatory disallowance of $17.5 million resulting from PNM's 2010 Electric Rate Case. No regulatory disallowances were recorded in 2012. In addition, PNM incurred operating expenses of $6.7 million in 2011 to implement process improvement initiatives associated with reducing future costs.

Depreciation and amortization expense increased in 2013 and 2012 due to additions to utility plant in service, including 22 MW of PNM-owned solar PV facilities. Depreciation on the PNM-owned solar PV facilities is recovered through the renewable energy rate rider as discussed above.

For 2013, other income (deductions) was $5.0 million lower than in 2012, primarily related to lower income from investments held by the NDT of $2.5 million and lower interest income on the PVNGS lessor notes of $2.3 million due to lower outstanding balances. PNM made commitments of $1.0 million to support employment and other economic activities in the "four corners" area, including the Navajo Nation, which further decreased earnings. These decreases were partially offset by higher equity AFUDC of $0.4 million. In 2012, other income (deductions) increased $6.6 million compared to 2011, primarily related to higher income from investments held by the NDT of $5.9 million. In addition, higher equity AFUDC of $3.3 million improved other income in 2012, offset by lower interest income on the PVNGS lessor notes of $2.8 million due to lower outstanding balances.

Interest expense increased $3.1 million in 2013 primarily due to the deferral in 2012 of interest costs associated with the 22 MW of PNM-owned solar PV facilities, which are now being recovered through a renewable energy rate rider.

In 2012, interest expense increased $7.0 million due to the issuance of $160.0 million of long-term debt in October 2011. This was partially offset by $5.6 million for the debt portion of AFUDC and $0.9 million of interest charges on PNM's investment in renewable resources that are deferred for recovery through the renewable energy rate rider.

TNMP The table below summarizes the operating results for TNMP: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions) Electric operating revenues $ 271.6 $ 250.1 $ 237.9 $ 21.5 $ 12.2 Cost of energy 57.6 46.2 41.2 11.4 5.0 Margin 214.0 203.9 196.7 10.1 7.2 Operating expenses 91.6 87.1 88.2 4.5 (1.1 ) Depreciation and amortization 50.2 49.3 44.6 0.9 4.7 Operating income 72.2 67.5 63.8 4.7 3.7 Other income (deductions) 1.9 2.7 1.6 (0.8 ) 1.1 Net interest charges (27.4 ) (28.2 ) (29.3 ) 0.8 1.1Segment earnings before income taxes 46.7 42.1 36.1 4.6 6.0 Income (taxes) (17.6 ) (15.4 ) (13.9 ) (2.2 ) (1.5 ) Segment earnings $ 29.1 $ 26.7 $ 22.3 $ 2.4 $ 4.4 A- 37-------------------------------------------------------------------------------- Table of Contents The table below summarizes the significant changes to total revenues, cost of energy, and margin: 2013/2012 Change 2012/2011 Change Total Cost of Total Cost of Revenues Energy Margin Revenues Energy Margin (In millions) Rate increases $ 4.8 $ - $ 4.8 $ 1.4 $ - $ 1.4 Customer usage/load 2.0 - 2.0 0.8 - 0.8 Customer growth 1.5 - 1.5 1.2 - 1.2 Demand based customers 3.6 - 3.6 - - - Weather (0.7 ) - (0.7 ) (4.1 ) - (4.1 ) Recovery of third-party transmission costs 11.8 11.4 0.4 4.9 5.0 (0.1 ) AMS surcharge 2.7 - 2.7 6.9 - 6.9 CTC surcharge (3.4 ) - (3.4 ) (0.6 ) - (0.6 ) 1999 rate settlement (1.6 ) - (1.6 ) 1.6 - 1.6 Other 0.8 - 0.8 0.1 - 0.1 Net change $ 21.5 $ 11.4 $ 10.1 $ 12.2 $ 5.0 $ 7.2 The following table shows TNMP operating revenues by retail tariff consumer class, including intersegment revenues, and average number of consumers: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions, except customers) Residential $ 111.3 $ 103.3 $ 100.3 $ 8.0 $ 3.0 Commercial 95.1 88.3 84.9 6.8 3.4 Industrial 13.1 13.4 13.1 (0.3 ) 0.3 Other 52.1 45.1 39.6 7.0 5.5 $ 271.6 $ 250.1 $ 237.9 $ 21.5 $ 12.2 Average consumers (thousands) (1) 235.1 233.0 231.3 2.1 1.7 (1) TNMP provides transmission and distribution services to REPs that provide electric service to customers in TNMP's service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy. The average consumers reported above include 67,268 consumers of TNMP for 2011 that chose First Choice as their REP. These consumers are also included in the First Choice segment.

The following table shows TNMP GWh sales by retail tariff consumers class: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (Gigawatt hours)(1) Residential 2,796.7 2,714.5 2,862.3 82.2 (147.8 ) Commercial 2,451.3 2,353.1 2,361.0 98.2 (7.9 ) Industrial 2,598.4 2,727.1 2,578.9 (128.7 ) 148.2 Other 104.5 103.9 108.7 0.6 (4.8 ) 7,950.9 7,898.6 7,910.9 52.3 (12.3 ) (1) The GWh sales reported above include 836.6 GWhs for 2011 used by consumers of TNMP who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

Implementation of rate increases in September 2012, March 2013, and September 2013 increased revenues and margins by $4.8 million in 2013 compared to 2012.

See Note 17. In 2013, TNMP experienced average customer growth of 0.9% further A- 38-------------------------------------------------------------------------------- Table of Contents increasing revenues and margins by $1.5 million. Higher weather normalized and leap-year adjusted usage per customer increased revenues and margin by $2.0 million in 2013 compared to 2012. Milder weather in 2013 compared to 2012, decreased revenues and margins by $0.7 million. TNMP's weather normalized and leap-year adjusted retail KWh sales increased 2.6% for the year ended 2013 compared to 2012. Rate increases implemented in February 2011 and September 2012 increased revenues and margins by $1.4 million in 2012 compared to 2011. Higher weather normalized and leap-year adjusted usage per customer increased margin $0.8 million in 2012. TNMP's weather normalized and leap-year adjusted retail KWh sales increased 3.7%. Customer growth in TNMP's service areas increased revenues and margin $1.2 million in 2012. These increases were more than offset with milder weather in 2012 compared to 2011, which reduced revenues and margins by $4.1 million.

Differences between revenues and costs charged by third-party transmission providers are deferred and recovered through a transmission cost recovery factor. Higher transmission cost of energy resulting from rate increases and higher demand based charges from other transmission service providers within ERCOT increased cost of energy $11.4 million in 2013 and $5.0 million in 2012.

These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue $11.8 million in 2013 and $4.9 million in 2012.

On August 11, 2011, TNMP implemented a surcharge for its AMS deployment. The surcharge will recover TNMP's investment in AMS over a 12 year period. The surcharge has a true-up mechanism, which allows TNMP to match revenues collected against the expenses incurred and allows for a return to be earned on its investments. AMS revenues increased by $2.7 million in 2013 and $6.9 million in 2012, which offset increases in operating expenses and depreciation.

Demand based customers increased revenues and margins by $3.6 million in 2013 compared to 2012. This primarily results from TNMP, under a PUCT approved tariff, lowering the power factor billing threshold from 700 KW to 300 KW. TNMP received a $1.6 million settlement related to ERCOT transmission rates charged from the fourth quarter of 1999, which increased 2012 revenues and margin, but did not recur in 2013. TNMP experienced lower revenues and margins of $3.4 million associated with the recovery of CTC due to a rate rider decrease implemented in January 2013, which was offset by lower amortization expense.

Other revenue increases include recovery of energy efficiency program costs, which are offset with increases in operating expenses.

Higher energy efficiency program expenses of $1.5 million increased operating expense in 2013, which is offset by increases in revenue under TNMP's energy efficiency cost recovery factor. Increased property and sales taxes of $1.1 million, primarily due to increased utility plant in service and higher assessed values, higher expenses for incentive compensation of $0.9 million, higher employee healthcare claims of $0.8 million, and higher pension and retiree medical expense of $0.8 million (see Note 12) increased operating expenses in 2013. Other increases to operating expenses in 2013 include a $0.5 million write-off of costs incurred in exploring the possibility of securitizing the remaining CTC costs and the allocation of the Company's contributions to the PNM Resources Foundation of $0.7 million. These increases were offset by lower vegetation management of $1.1 million in 2013 due to additional vegetation management expenditures in 2012 and the 2012 lease abandonment loss of $1.2 million, which did not recur in 2013.

In 2012, operating expenses associated with the AMS deployment increased $2.6 million and vegetation management expenses increased $1.7 million. These increases were offset by lower maintenance expenses of $1.1 million related to extreme drought conditions experienced in 2011 in the Gulf Coast region, lower administrative and general expenses of $1.9 million based on process improvements initiated in 2011, and higher capitalization of administrative and general expenses related to construction projects of $1.3 million, which improved operating expenses in 2012.

Depreciation expense associated with AMS deployment, which is recovered through the AMS surcharge, increased $1.8 million in 2013. In addition, an increase in utility plant in service increased depreciation by $ 1.4 million in 2013. This was offset by decreased amortization of the CTC regulatory asset of $2.3 million. In 2012, depreciation and amortization expense increased due to higher utility plant in service and AMS deployment.

Other income (deductions) increased in 2012 due to higher AFUDC on equity funds of $0.6 million compared to 2013 and 2011. A gain on the sale of property of $0.3 million further increased other income in 2012.

In April 2013, TNMP exchanged $93.2 million of its 9.5% First Mortgage Bonds for an equal amount of a new series of 6.95% First Mortgage Bonds. This resulted in a decrease in interest expense of $1.8 million in 2013. This was partially offset by increased interest expense due to higher short-term debt balances in 2013. In September 2011, TNMP replaced its 2009 Term Loan Agreement, at a lower interest rate, which resulted in lower interest expense in 2012. In addition, an increase in AFUDC on borrowed funds further reduced interest expense in 2012.

A- 39-------------------------------------------------------------------------------- Table of Contents First Choice As discussed in Note 3, PNMR sold First Choice on November 1, 2011. The table below summarizes the operating results for First Choice from January 1, 2011 through October 31, 2011: Ten Months Ended October 31, 2011 (In millions) Electric operating revenues $ 439.5 Cost of energy 323.3 Margin 116.1 Operating expenses 76.0 Depreciation and amortization 1.1 Operating income 39.1 Other income (deductions) (0.6 ) Net interest charges (0.6 ) Segment earnings before income taxes 37.9 Income (taxes) (13.8 ) Segment earnings $ 24.1 For the ten months of operations in 2011, First Choice operating revenues consisted of $260.2 million from residential customers, $166.5 million from commercial customers, and $12.8 million from other sources. First Choice's sales were 2,006.4 GWh to residential customers and 1,538.2 GWh to commercial customers. At October 31, 2013, First Choice had 0.2 million customers. See note above in the TNMP segment discussion about the impact of TECA.

First Choice revenues increased in 2011 compared to the same period in 2010 due to favorable weather and an increase in both MWh sales and number of customers, which were partially offset by a decrease in the average revenue rates. First Choice incurred significantly higher purchased power costs per MWh due to extreme summer temperatures in 2011. These higher energy costs more than offset the increase in revenues. First Choice managed its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. Changes in the fair value of supply contracts that were not designated or were not eligible for hedge or normal purchase or normal sales accounting were marked to market through current period earnings as required by GAAP. During 2011, market energy prices increased, which increased segment earnings by $4.9 million due to unrealized mark-to-market gains on certain of First Choice's forward supply contracts. First Choice was not required to mark the related fixed price sales contracts to market, which would likely offset the supply contracts.

The allowance for uncollectible accounts and related bad debt expense was based on collections and write-off experience. For the ten months ended October 21, 2011, bad debt expense was $20.3 million. Initiatives to reduce bad debts included efforts to reduce the default rate experienced for customers switching to another REP and increased focus on identifying new customer prospects that are more likely to demonstrate desired payment behavior. First Choice focused its marketing efforts on commercial customers and customers with established payment patterns, increased the required credit score, and expanded advance deposits requirements.

Prior to the sale, operating expenses in 2011 increased compared to the same period in 2010 due to increases in marketing and operational costs, which were partially offset by a decrease in incentive compensation expense. In 2011, interest expense decreased primarily due to lower short-term debt.

A- 40-------------------------------------------------------------------------------- Table of Contents Corporate and Other The table below summarizes the operating results for Corporate and Other: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions) Electric operating revenues $ - - $ (34.0 ) $ - $ 34.0 Cost of energy - - (33.8 ) - 33.8 Margin - - (0.2 ) - 0.2 Operating expenses (18.3 ) (17.9 ) (9.7 ) (0.4 ) (8.2 ) Depreciation and amortization 12.8 17.5 16.5 (4.7 ) 1.0 Operating income (loss) 5.5 0.3 (7.0 ) 5.2 7.3 Gain on sale of First Choice - 1.0 174.9 (1.0 ) (173.9 ) Other income (deductions) (13.7 ) (8.1 ) (15.8 ) (5.6 ) 7.7 Net interest charges (14.9 ) (16.6 ) (19.6 ) 1.7 3.0 Segment earnings (loss) before income taxes (23.1 ) (23.4 ) 132.5 0.3 (155.9 ) Income (taxes) benefit 6.9 11.2 (56.5 ) (4.3 ) 67.7 Segment earnings (loss) $ (16.2 ) $ (12.2 ) $ 76.0 $ (4.0 ) $ (88.2 ) The Corporate and Other segment includes consolidation eliminations of revenues and cost of energy between business segments related to TNMP's sale of transmission services to First Choice prior to November 1, 2011, when PNMR sold First Choice (Note 3). Accordingly, there were no eliminations of intersegment revenues in 2012 or 2013. Corporate and Other results also include the gain on the sale of First Choice.

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP. The amounts allocated include certain expenses shown as depreciation and amortization and other income (deductions) in the table above.

The operating income (loss) of $5.5 million in 2013 reflects the allocation of $4.0 million of the Company's contributions to the PNM Resources Foundation and financial support to the PNM Good Neighbor Fund, recorded in other income (deductions), which were allocated to PNM and TNMP reducing operating expenses.

The operating income (loss) of $(7.0) million in 2011 reflects legal and consulting expenses of $4.6 million related to assessment of strategic alternatives for PNMR's competitive businesses, as well as depreciation and other operating expenses that were retained in the Corporate and Other segment.

Beginning in 2012, substantially all Corporate and Other operating expenses are allocated to the utilities.

Depreciation expense increased in 2012 by $4.5 million due to accelerated amortization of leasehold improvements for part of its corporate headquarters that was abandoned during 2012. PNM and TNMP deferred their allocations of the accelerated amortization of leasehold improvements as regulatory assets to be recovered through rates. This increase was partially offset by lower depreciation on software applications that were fully depreciated by the end of 2011. Beginning in 2012, substantially all depreciation and amortization expense is offset in operating expenses as a result of allocation of these costs to other business segments.

The year-over-year changes in other income and deductions are primarily due to losses of $3.3 million in 2013 and $9.2 million in 2011 recognized on the repurchase of $23.8 million and $50.0 million of PNMR's 9.25% senior unsecured notes (Note 6). As discussed above, in 2013, Corporate and Other made contributions to the PNM Resources Foundation and the PNM Good Neighbor Fund totaling $4.0 million, which were allocated to PNM and TNMP. The impact of these changes is offset by lower performance on other investments in 2012. Net interest charges decreased in 2013 and 2012, primarily due to the repurchase of 9.25% senior unsecured notes.

In 2013 and 2012, income tax benefits were reduced by $3.9 million and $0.7 million due to impairments of New Mexico wind energy production tax credit carry forwards. The impaired credits are not expected to be utilized prior to their expiration due to the Company's net operating loss position and the extension of fifty percent bonus depreciation under the American Taxpayer Relief Act of 2012.

Additional expense of $1.2 million was recognized in 2013 due to reductions in Corporate and Other's deferred tax assets resulting from legislation, which reduced future New Mexico corporate income tax rates. See Note 11.

A- 41-------------------------------------------------------------------------------- Table of Contents LIQUIDITY AND CAPITAL RESOURCES Statements of Cash Flows The information concerning PNMR's cash flows is summarized as follows: Year Ended December 31, Change 2013 2012 2011 2013/2012 2012/2011 (In millions) Net cash flows from: Operating activities $ 386.6 $ 281.3 $ 292.2 $ 105.3 $ (10.9 ) Investing activities (331.4 ) (285.9 ) 19.8 (45.5 ) (305.7 ) Financing activities (61.6 ) (1.6 ) (312.3 ) (60.0 ) 310.7 Net change in cash and cash equivalents $ (6.5 ) $ (6.1 ) $ (0.3 ) $ (0.2 ) $ (5.9 ) The changes in PNMR's cash flows from operating activities primarily relate to income tax refunds received of $95.3 million in 2013 compared to income taxes paid of $5.3 million in 2012 and refunds received of $5.5 million in 2011 and rate increases at TNMP and PNM. Contributions to the PNM and TNMP pension and other postretirement benefit plans of $66.5 million in 2013 compared to $88.5 million in 2012 and $48.3 million in 2011 also contributed to operating cash flow changes. In addition, changes in assets and liabilities resulting from normal operations impact operating cash flows. These increases were offset by refunds of $15.2 million made to customers related to the settlement of PNM's transmission rate case in 2013, as well as governmental grants received by PNM of $21.6 million in 2012 and $2.1 million in 2011 that did not recur in 2013, and lower retail load at PNM in 2013.

Cash flows from investing activities are primarily driven by additions to utility plant. PNMR's utility plant additions increased $39.1 million in 2013 and decreased $18.0 million in 2012. At PNM, total utility plant additions increased by $43.1 million in 2013 and decreased by $54.5 million in 2012. PNM's additions included $59.2 million related to solar projects in 2011 and $35.7 million in 2013. Also, PNM's transmission and distribution additions increased $22.7 million in 2013 offset by $5.8 million lower nuclear fuel purchases than 2012, relating to the timing of purchases. TNMP utility plant additions decreased $3.9 million in 2013 compared to 2012, including an increase in advanced meter additions of $2.5 million, offset by a decrease in other transmission and distribution additions of $6.4 million. TNMP utility plant additions increased $25.6 million in 2012 compared to 2011, including increases of $12.9 million in distribution projects, $13.8 million in transmission projects, and a decrease of $2.8 million related to the deployment of advanced meters. Plant additions at the Corporate and Other segment increased $13.4 million in 2012 primarily related to improvements to the Company's corporate headquarters building. Construction expenditures were funded primarily through cash flows from operating activities and short-term borrowings. Investing cash flows also include the proceeds from the sale of First Choice of $4.0 million in 2012 and $329.3 million in 2011, offset by related transaction costs of $10.9 million in 2011.

The changes in cash flows from financing activities relate primarily to the use of proceeds from the sale of First Choice in 2011 to purchase PNMR common stock for $125.7 million, PNMR's convertible preferred stock, Series A, for $73.5 million, and long-term debt for $58.5 million. Cash flows from financing activities in 2013 also includes long-term borrowings of $75.0 million made at PNM. In addition, $13.0 million was paid in connection with TNMP's debt exchange and $26.9 million was paid by PNMR to repurchase $23.8 million of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in 2013. In 2012, PNMR obtained $100.0 million in new short-term borrowings, and used the proceeds to repay borrowings under the PNMR Revolving Credit Facility. PNM also refinanced $20.0 million of PCRBs in 2012. In 2011, PNM obtained $160.0 million in new long-term borrowings, using the proceeds to reduce short-term borrowings.

Also in 2011, TNMP replaced $50.0 million in long-term debt with a new term loan agreement for $50.0 million.

Financing Activities See Note 6, for additional information concerning the Company's financing activities. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. The Company's ability to access the credit and capital markets at a reasonable cost is largely dependent upon its: • Ability to earn a fair return on equity • Results of operations • Ability to obtain required regulatory approvals A- 42-------------------------------------------------------------------------------- Table of Contents • Conditions in the financial markets • Credit ratings The $100.0 million PNMR Term Loan Agreement matures on December 26, 2014 and the $75.0 million PNM Term Loan Agreement matures on October 21, 2014. Each of the term loans contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%. These ratios reflect the present value of payments under the PVNGS and EIP leases as debt. PNMR and PNM anticipate that funds to repay these term loans will come from entering into a new arrangement similar to the existing agreements, borrowing under their revolving credit facilities, or a combination of these sources. At December 31, 2013, average interest rates were 1.02% for the PNMR Term Loan Agreement and 1.42% for the PNM Term Loan Agreement. PNM anticipates entering into a new $175.0 million term loan agreement with a term of 18 months in March 2014. PNM would use a portion of the funds borrowed under the new agreement to repay all amounts outstanding under the PNM Term Loan Agreement and would use the balance of the funds to repay other short-term borrowings.

Capital Requirements Total capital requirements consist of construction expenditures and cash dividend requirements for PNMR common stock and PNM preferred stock. Key activities in PNMR's current construction program include: • Upgrading generation resources, including expenditures for compliance with environmental requirements and for renewable energy resources • Expanding the electric transmission and distribution systems • Purchasing nuclear fuel Projected capital requirements for 2014-2018 are: 2014 2015-2018 Total (In millions) Construction expenditures $ 509.0 $ 1,758.2 $ 2,267.2 Dividends on PNMR common stock 58.9 235.8 294.7 Dividends on PNM preferred stock 0.5 2.1 2.6 Total capital requirements $568.4 $1,996.1 $2,564.5 The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $80.0 million related to environmental upgrades at SJGS to address regional haze and $276.3 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources to meet needs outlined in PNM's current IRP, environmental upgrades at Four Corners of $80.3 million, the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, and the anticipated purchase of Delta.

See Note 16 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $10.0 million in 2014.

During the year ended December 31, 2013, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and borrowings under term loans.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. Note 6 contains information about the maturities on long-term debt.

The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances or make additional debt repurchases in the future.

Liquidity PNMR's liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both expire in October 2018 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. On January 8, 2014, PNM entered into the $50.0 million PNM New Mexico Credit Facility, which expires on January 8, 2018. The Company believes the terms and conditions of these facilities are consistent with those of other investment grade revolving credit facilities in the utility industry.

A- 43-------------------------------------------------------------------------------- Table of Contents Each of the credit facilities contains one financial covenant that requires 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 revolving credit facilities and the PNM New Mexico Credit Facility provide short-term borrowing capacity. The revolving credit facilities also allow letters of credit to be issued. Letters of credit 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. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Revolving Credit Facility ranged from zero to $84.0 million during the year ended December 31, 2013, $14.0 million to $141.0 million during the year ended December 31, 2012, and zero to $106.0 million during the year ended December 31, 2011. Such borrowings ranged from zero to $28.1 million during the three months ended December 31, 2013.

Borrowings under the PNM Revolving Credit Facility ranged from zero to $130.8 million during the year ended December 31, 2013, zero to $168.0 million during the year ended December 31, 2012, and zero to $298.0 million during the year ended December 31, 2011. Such borrowings ranged from zero to $51.8 million during the three months ended December 31, 2013. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $40.0 million during the year ended December 31, 2013 and from zero to $19.0 million during the three months ended December 31, 2013. There were no such borrowings in 2012 and 2011. At December 31, 2013, the average interest rate was 1.42% for the PNM Revolving Credit Facility. The PNMR Revolving Credit Facility and the TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2013.

The Company currently believes that its capital requirements can be met through internal cash generation, existing credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements.

However, if difficult market conditions experienced during the recent recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM may consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

In addition to its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2014-2018 period. This could include debt refinancing, new debt issuances, and/or new equity.

On April 5, 2013, S&P raised the corporate credit ratings and the senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM.

S&P retained the outlook as stable for all entities. On June 21, 2013, Moody's changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. On January 30, 2014, Moody's raised the senior unsecured rating for PNMR, the senior unsecured and issuer ratings for PNM, and the senior secured and issuer ratings for TNMP. Moody's continued to maintain the ratings outlook for PNMR, PNM, and TNMP as positive. As of February 21, 2014, ratings on the Company's securities were as follows: PNMR PNM TNMP S&P Senior secured * * A- Senior unsecured BBB- BBB * Preferred stock * BB+ * Moody's Senior secured * * A2 Senior unsecured Baa3 Baa2 * Preferred stock * Ba2 * * Not applicable Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A- 44-------------------------------------------------------------------------------- Table of Contents A summary of liquidity arrangements as of February 21, 2014 is as follows: PNMR PNM TNMP PNMR Separate Separate Separate Consolidated (In millions) Financing capacity: Revolving credit facility $ 300.0 $ 400.0 $ 75.0 $ 775.0 PNM New Mexico Credit Facility - 50.0 - 50.0 Total financing capacity $ 300.0 $ 450.0 $ 75.0 $ 825.0 Amounts outstanding as of February 21, 2014: Revolving credit facility $ - $ 69.4 $ - $ 69.4 PNM New Mexico Credit Facility - 25.0 - 25.0 Letters of credit 8.6 3.2 0.3 12.1 Total short term-debt and letters of credit 8.6 97.6 0.3 106.5 Remaining availability as of February 21, 2014 $ 291.4 $ 352.4 $ 74.7 $ 718.5 Invested cash as of February 21, 2014 $ 1.9 $ - $ - $ 1.9 The above table excludes intercompany debt. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

For offerings of securities registered with the SEC, PNMR has a shelf registration statement expiring in March 2014. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations. PNMR can also offer new shares of common stock through the PNM Resources Direct Plan under a separate SEC shelf registration statement that expires in August 2015. PNM has a shelf registration statement for up to $440.0 million of senior unsecured notes that will expire in May 2014.

Off-Balance Sheet Arrangements PNMR's off-balance sheet arrangements include PNM's operating lease obligations for PVNGS Units 1 and 2, the EIP transmission line, and Delta.

In 1985 and 1986, PNM consummated sale and leaseback transactions for its interest in PVNGS Units 1 and 2. The original purpose of the sale-leaseback financing was to lower revenue requirements and to levelize the ratemaking impact of PVNGS being placed in-service. The lease payments reflected lower capital costs as the equity investors were able to capitalize the investment with greater leverage than PNM and because the sale transferred tax benefits that PNM could not fully utilize. Under traditional ratemaking, the capital costs of ownership of a major rate base addition, such as a nuclear plant, are front-end loaded. The revenue requirements are high in the initial years and decline over the life of the plant as depreciation occurs. By contrast, the lease payments are level over the lease term. The leases, which were scheduled to expire in 2015 and 2016, contain options to renew the leases at a fixed price or to purchase the property for fair market value. See discussion below and Note 7 regarding the status of these alternatives.

For reasons similar to the PVNGS sale and leaseback transactions, PNM built the EIP transmission line and sold it in sale and leaseback transactions in 1985.

PNM currently owns 60% and operates the other 40% of the EIP line under the terms of a lease agreement. The lease expires in 2015 with fixed-rate and fair market value renewal options and a fair market value purchase option. PNM has agreed to exercise its option to purchase the leased assets at expiration of the lease at fair market value. See Note 7.

Additionally, in 1996, PNM entered into a PPA for the rights to all the output of the Delta generating plant through June 2020. The PPA is accounted for as an operating lease. The gas turbine generating unit is operated by Delta, which is a variable interest entity. The plant is mainly used to meet peak load requirements. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.

The future lease payments shown below for the PVNGS leases have been reduced by amounts that will be returned to PNM through its ownership in related lessor notes.

A- 45-------------------------------------------------------------------------------- Table of Contents PVNGS Units 1&2 EIP Delta Total (In thousands) 2014 $ 32,207 $ 4,267 $ 5,956 $ 42,430 2015 25,319 - 5,956 31,275 2016 20,589 - 5,956 26,545 2017 18,139 - 5,956 24,095 2018 18,139 - 5,956 24,095 Thereafter 83,263 - 9,430 92,693 Total $ 197,656 $ 4,267 $ 39,210 $ 241,133 As discussed in Note 7, PNM and the lessors under each of the PVNGS Unit 1 leases entered into amendments to those leases that renew the leases from their original expiration on January 15, 2015 through January 15, 2023. In addition, PNM anticipates entering into an amendment with the lessor under one of the PVNGS Unit 2 leases that would extend that lease from its original expiration on January 15, 2016 through January 15, 2024. PNM has given notice to lessors under the other three PVNGS Unit 2 leases that PNM will exercise its option to purchase the assets underlying the leases at fair market value at the expiration of the leases on January 15, 2016. The semiannual renewal payments aggregate $8.3 million under the PVNGS Unit 1 leases and are $0.8 million for the one renewed PVNGS Unit 2 lease, which amounts are included above. See Sources of Power in Part I, Item 1, Investments in Note 1, and Note 7 for additional information.

A- 46-------------------------------------------------------------------------------- Table of Contents Commitments and Contractual Obligations The following table sets forth PNMR's long-term contractual obligations as of December 31, 2013. See Note 7 for further details about the Company's significant leases: Payments Due 2019 and Contractual Obligations 2014 2015-2016 2017-2018 Thereafter Total (In thousands) Long-term debt (a) $ 75,000 $ 158,066 $ 507,025 $ 985,045 $ 1,725,136 Interest on long-term debt (b) 113,064 208,890 188,316 681,933 1,192,203 Operating leases (c) 53,594 74,740 61,890 167,225 357,449 Transmission reservation payments 13,858 20,558 18,621 38,595 91,632 Coal contracts (d) 63,491 133,753 100,173 443,536 740,953 Coal mine decommissioning (e) 2,969 2,640 2,148 141,381 149,138 Nuclear decommissioning funding requirements (f) 2,637 5,274 5,274 10,120 23,305 Outsourcing 5,574 10,169 3,398 - 19,141 Pension and retiree medical (g) 5,470 45,953 37,176 - 88,599 Construction expenditures (h) 509,002 1,013,220 744,935 - 2,267,157 Total (i) $ 844,659 $ 1,673,263 $ 1,668,956 $ 2,467,835 $ 6,654,713 (a) Represents total long-term debt, excluding unamortized discounts of $2.4 million and unamortized premiums of $22.7 million. The TNMP 2011 Term Loan Agreement, which is due on June 30, 2014, is not reflected as maturing in 2014 in the above table since TNMP has entered into the TNMP 2013 Bond Purchase Agreement to re-finance that debt on a long-term basis as discussed in Note 6.

(b) Represents interest payments during the period.

(c) The operating lease amounts include amounts due to Delta. The amounts include payments under the PVNGS leases through the expiration of the leases, including renewal periods for leases for which PNM has provided renewal notices, and the EIP lease. The amounts in the above table are net of amounts to be returned to PNM as payments on its investments in related PVNGS lessor notes. See Off-Balance Sheet Arrangements above, Investments in Note 1, Note 7, and Note 9.

(d) Represents only certain minimum payments that may be required under the coal contracts if no deliveries are made.

(e) Includes funding of the trust established for post-term reclamation related to the mines serving SJGS. See Note 16.

(f) These obligations represent funding based on the current rate of return on investments.

(g) The Company only forecasts funding for its pension and retiree medical plans for the next five years.

(h) Represents forecasted construction expenditures, including nuclear fuel, under which substantial commitments have been made. See Note 14. The Company only forecasts capital expenditures for the next five years. The construction expenditures include the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, as well as the anticipated purchase of Delta.

See Capital Requirements above, Note 7 and Note 9.

(i) PNMR is unable to reasonably estimate the timing of liability and interest payments for uncertain income tax positions (Note 11) in individual years due to uncertainties in the timing of the effective settlement of tax positions. Therefore, PNMR's liability of $19.9 million and interest payable of $1.1 million are not reflected in this table. Amounts PNM is obligated to pay Valencia are not included above since Valencia is consolidated by PNM in accordance with GAAP. See Note 9. No amounts are included above for the New Mexico Wind, Lightning Dock Geothermal, and Red Mesa Wind PPAs since there are no minimum payments required under those agreements.

Contingent Provisions of Certain Obligations PNMR, PNM, and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. In the unlikely event that the contingent requirements were to be triggered, PNMR, PNM, or TNMP could be required to provide security, immediately pay outstanding obligations, or be prevented from drawing on unused capacity under certain credit agreements. The most significant consequences resulting from these contingent requirements are detailed in the discussion below.

A- 47-------------------------------------------------------------------------------- Table of Contents The PNMR Revolving Credit Facility, PNM Revolving Credit Facility, PNM New Mexico Credit Facility, TNMP Revolving Credit Facility, and TNMP 2011 Term Loan contain "ratings triggers," for pricing purposes only. If PNMR, PNM, or TNMP is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost. In addition, these facilities, as well as the PNMR Term Loan Agreement and PNM Term Loan Agreement, each contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%. In the calculation of debt for PNMR and PNM, the present value of payments under the PVNGS and EIP leases are considered debt. If that ratio were to exceed 65%, the entity could be required to repay all borrowings under its facility, be prevented from borrowing on the unused capacity under the facility, and be required to provide collateral for all outstanding letters of credit issued under the facility.

If a contingent requirement were to be triggered under the PNM facilities resulting in an acceleration of the repayment of outstanding loans, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the PVNGS lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments. The Company's revolving credit facilities and term loan agreements also include cross-default provisions.

PNM's standard purchase agreement for the procurement of gas for its fuel needs contains a contingent requirement that could require PNM to provide collateral for its gas purchase obligations if the seller were to reasonably believe that PNM was unable to fulfill its payment obligations under the agreement.

The master agreement for the sale of electricity in the WSPP contains a contingent requirement that could require PNM to provide collateral if the credit ratings on its debt falls below investment grade. The WSPP agreement also contains a contingent requirement, commonly called a material adverse change provision, which could require PNM to provide collateral if a material adverse change in its financial condition or operations were to occur. Additionally, PNM utilizes standard derivative contracts to financially hedge and trade energy.

These agreements contain contingent requirements that require PNM to provide security if the credit rating on its debt falls below investment grade.

No conditions have occurred that would result in any of the above contingent provisions being implemented.

Capital Structure The capitalization tables below include the current maturities of long-term debt, but do not include short-term debt and do not include operating lease obligations as debt.

December 31, PNMR 2013 2012 PNMR common equity 48.8 % 48.9 % Preferred stock of subsidiary 0.3 % 0.3 % Long-term debt 50.9 % 50.8 % Total capitalization 100.0 % 100.0 % PNM PNM common equity 48.2 % 50.5 % Preferred stock 0.4 % 0.5 % Long-term debt 51.4 % 49.0 % Total capitalization 100.0 % 100.0 % TNMP Common equity 59.9 % 59.8 % Long-term debt 40.1 % 40.2 % Total capitalization 100.0 % 100.0 % OTHER ISSUES FACING THE COMPANY Climate Change Issues Background According to EPA, gases that trap heat in the atmosphere are called greenhouse gases. The four primary greenhouse gases are CO2, methane, nitrous oxide, and fluorinated gases, including chlorofluorocarbons such as Freon. In 2013, GHG associated A- 48-------------------------------------------------------------------------------- Table of Contents with PNM's interests in its generating plants were approximately 7.0 million metric tons of CO2, which comprises the vast majority of PNM's GHG. By comparison, the total GHG in the United States in 2011, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.6 billion metric tons were CO2.

PNM has several programs underway to reduce or offset its GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 17. In 2011, PNM completed construction of 22 MW of utility-scale solar generation located at five sites on PNM's system throughout New Mexico. In 2013, PNM expanded its renewable energy portfolio by constructing 21.5 MW of utility-scale solar generation. On December 18, 2013, the NMPRC approved PNM's 2014 renewable energy procurement plan that includes construction of an additional 23 MW of utility-scale solar generation. The proposed generation is anticipated to be online by the end of 2014. Since 2003 PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and will purchase of the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW, beginning in January 2015. PNM has signed a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. Additionally, PNM has a customer distributed solar generation program that represented almost 31 MW at the end of 2013 and is expected to grow to over 36 MW by the end of 2014. Once fully subscribed, the distributed solar programs will reduce PNM's production from fossil-fueled electricity generation by 117 GWh per year. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2013 budget of over $17 million, that PNM estimates saved approximately 76 GWh of electricity in 2013. Over the next 20 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 13,565 GWh of electricity, which will avoid at least 6.8 million metric tons of CO2 based upon projected emissions from PNM's system-wide resources. These estimates are subject to change based upon the difficulty in accurately estimating avoidance because of the high uncertainty of many of the underlying variables and complex interrelationships between those variables, including changes in demand for electricity.

Management periodically updates the Board on implementation of the corporate environmental policy and the Company's environmental management systems, promotion of energy efficiency, and use of renewable resources. The Board is also advised of the Company's practices and procedures to assess the sustainability impacts of operations on the environment. The Board considers associated issues around climate change, the Company's GHG exposures, and potential financial consequences that might result from potential federal and/or state regulation of GHG.

As of December 31, 2013, approximately 74.7% of PNM's generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM's current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 16, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would result in a reduction of GHG of approximately 50 percent at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies have not been finalized, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement with gas-fired generation. On September 5, 2013, the EIB unanimously approved a revised SIP submitted by NMED that encompassed the February 15, 2013 agreement and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA action on the revised SIP is projected for late 2014.

Because of PNM's dependence on fossil-fueled generation, any legislation or regulation that imposes a limit or cost on GHG could impact the cost at which electricity is produced. While PNM expects to recover that cost through rates, the timing and outcome of proceedings for cost recovery are uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their usage, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

Given the geographic location of its facilities and customers, PNM generally has not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the exception of periodic drought conditions. PNM's service areas also experience high winds and severe thunderstorms periodically. Climate changes are generally not expected to have material consequences in the near-term. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal-fired generating plants. Water shortage sharing agreements have been in place since 2004, although no shortage has been declared due to sufficient precipitation in the San Juan River basin. PNM also has a supplemental water contract in place with the Jicarilla Apache Nation to help address any water shortages from primary sources. The contract expires on A- 49-------------------------------------------------------------------------------- Table of Contents December 31, 2016. TNMP has operations in the Gulf Coast area of Texas, which experiences periodic hurricanes and drought conditions. In addition to potentially causing physical damage to TNMP-owned facilities, which disrupt the ability to transmit and/or distribute energy, hurricanes can temporarily reduce customers' usage and demand for energy.

EPA Regulation In April 2007, the United States Supreme Court held that EPA has the authority to regulate GHG under the CAA. This decision heightened the importance of this issue for the energy industry. In December 2009, EPA released its endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO2, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the "Tailoring Rule") to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule is to "tailor" the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focuses on the largest sources of GHG, including fossil-fueled electric generating units. This program currently covers new construction projects that emit GHG of at least 100,000 tons per year (even if PSD is not triggered for other pollutants). In addition, modifications at existing facilities that increase GHG by at least 75,000 tons per year will be subject to PSD permitting requirements, even if they do not significantly increase emissions of any other pollutant. All of PNM's fossil-fueled generating plants are potentially subject to the Tailoring Rule because of the magnitude of non-GHG, but the existing plants do not have any currently planned projects that would trigger PSD permitting for GHG. Any newly constructed fossil-fired power plant would likely be subject to the Tailoring Rule.

On June 26, 2012, the D.C. Circuit rejected challenges to EPA's 2009 GHG endangerment finding, GHG standards for light-duty vehicles, PSD Interpretive Memorandum (EPA's so-called GHG "Timing Rule"), and Tailoring Rule. The Court found that EPA's endangerment finding and its light-duty vehicle rule "are neither arbitrary nor capricious," that "EPA's interpretation of the governing CAA provisions is unambiguously correct," and that "no petitioner has standing to challenge the Timing and Tailoring Rules." On October 15, 2013, the United States Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The Supreme Court limited the question that it will be reviewing to: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases." Specifically, the case deals with whether EPA's determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA's determination that it was required to regulate GHG under the PSD and Title V Programs was unlawful as it violates Congressional intent.

On March 27, 2012, EPA issued its proposed carbon pollution standards for GHG from new fossil-fueled EGU. The proposed NSPS set a limit of 1,000 lb CO2/MWh and would cover newly constructed fossil-fueled EGUs larger than 25 MW. The proposed limit was based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule included an exemption for new simple cycle EGUs. EPA accepted comment on the proposed rule through June 25, 2012, during which EPA received over 2.5 million comments on the proposed rule.

On June 25, 2013, President Obama announced the President's Climate Action Plan which outlines how his administration plans to cut GHG in the United States, prepare the country for the impacts of climate change, and lead international efforts to combat and prepare for global warming. The plan proposes actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum establishes a timeline for the reproposal and issuance of a GHG NSPS for new sources and a timeline for the proposal and final rule for developing carbon pollution standards, regulations, or guidelines for GHG reductions from existing sources. EPA met the President's timeline for the reproposal of the GHG NSPS for new sources by releasing the draft rule on September 20, 2013. In accordance with the Presidential Memorandum, EPA will issue a final rule in "a timely fashion thereafter." EPA is also directed to issue the proposed GHG NSPS for modified and existing EGUs by June 1, 2014 and issue the final rule by June 1, 2015. Each state then must submit a SIP that addresses how the state will comply with the new regulation no later than June 30, 2016.

The Presidential Memorandum further directs EPA to allow the use of "market-based instruments" and "other regulatory flexibilities" to ensure standards will allow for continued reliance on a range of energy sources and technologies and that they are developed and implemented in a manner that provides for reliable and affordable energy and to undertake the rulemaking through direct engagement with states, "as they will play a central role in establishing and implementing standards for existing power plants," and with utility leaders, labor leaders, non-governmental organizations, tribal officials and other stakeholders.

EPA's reproposed GHG NSPS for new sources published on September 20, 2013 apply only to new EGUs. The reproposed standard would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and A- 50-------------------------------------------------------------------------------- Table of Contents simple cycle turbines, and new sources meeting certain other criteria. New fossil fuel-fired utility boilers including coal-fired and integrated gasification combined cycle units would be required to meet an emissions limit of 1,100 pounds of CO2 per MWh on a 12-operating month rolling average basis or an alternative limit of 1,000 to 1,050 pounds of CO2 per MWh based on an 84-operating month average. New coal-fired facilities would only be able to meet the standard by using carbon capture and sequestration technology. New combined or simple cycle gas turbines would be subject to an emission limit of either 1,000 or 1,100 pounds of CO2 per MWh based on whether the rated capacity of the unit is above or below 850 million BTUs per hour. The reproposed GHG NSPS removed the blanket exemption for simple-cycle turbines and instead provided an exemption for units that sell to the transmission grid less than one-third of their potential electric output over a three-year rolling average.

EPA regulation of GHG from large stationary sources will impact PNM's fossil-fueled EGUs. Impacts could involve investments in efficiency improvements and/or control technologies at the fossil-fueled EGUs. In setting existing source standards, EPA has historically used technology-based performance standards on emission rates. The only end-of-pipe emission control technology for coal and gas fired power plants available for GHG reduction is carbon capture and sequestration, which is not yet a commercially demonstrated technology. There are limited efficiency enhancement measures that may be available to a subset of the existing EGUs; however, such measures would provide only marginal GHG improvements. It is also possible EPA may consider a broader range of emission reduction measures, such as fuel switching, end use energy efficiency, or renewable energy deployment. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of such improvements or technologies could impact the economic viability of some plants.

The ultimate impact of EPA's regulation of GHG to PNM is unknown because the regulatory requirements, including BACT implications and NSPS requirements, are in draft form or are still developing. PNM estimates that implementation of the revised SIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by January 2016 or 15 months after EPA approval of a revised SIP and the retirement of SJGS Units 2 and 3 by the end of 2017, will allow PNM on a system-wide basis to meet or exceed the President's GHG reduction goal of 17% below 2005 levels by 2020. The reduction in CO2 emissions that will result from implementation of the revised SIP may allow PNM to meet future GHG regulations; however, until such regulations are finalized, PNM is uncertain of the requirements for compliance.

Federal Legislation Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2014, although there is growing interest among some policymakers in addressing climate change and there may be legislation in the future. Instead, EPA is the primary venue for GHG regulation in the near future, especially for coal-fired units. PNM has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business. This assessment is preliminary and future changes arising out of the legislative or regulatory process could impact the assessment significantly. PNM's assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the possibility of a cap and trade program including the associated costs and the availability of offsets, the development of technologies for renewable energy and to reduce emissions, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as the price of coal and gas and regional plant economics. These assumptions, at best, are preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation could, among other things, result in significant compliance costs, including large capital expenditures by PNM, and could jeopardize the economic viability of certain generating facilities. See Note 16. In turn, these consequences could lead to increased costs to customers and affect results of operations, cash flows, and financial condition if the incurred costs are not fully recovered through regulated rates. Higher rates could also contribute to reduced usage of electricity. PNM's assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

State and Regional Activity Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis. The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility's customers. The NMPRC requires that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO2 emitted and escalating these costs by 2.5% per year. Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs. Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances. However, PNM is required to use these prices for purposes of its IRP, and the prices may not reflect the costs that it ultimately will incur. PNM's IRP filed with the NMPRC on July 18, 2011 showed that while consideration of the NMPRC required carbon emissions costs did not significantly change the resource decisions regarding future facilities over the next 20 years, it did slightly impact the projected in-service dates of some of the identified resources. Much higher GHG costs than assumed A- 51-------------------------------------------------------------------------------- Table of Contents in the NMPRC analysis are necessary to impact future resource decisions. The primary consequence of the standardized cost of carbon emissions was an increase to generation portfolio costs.

In recent years, New Mexico adopted regulations, which have since been repealed, that would directly limit GHG from larger sources, including EGUs, through a regional GHG cap and trade program and that would cap GHG from larger sources such as EGUs. Although these rules have been repealed, PNM cannot rule out future state legislative or regulatory initiatives to regulate GHG.

On August 2, 2012, thirty-three New Mexico organizations representing public health, business, environmental, consumers, Native American, and other interested parties filed a petition for rulemaking with the NMPRC. The petition asked the NMPRC to issue a NOPR regarding the implementation of an Optional Clean Energy Standard for electric utilities located in New Mexico. The proposed standard would have utilities that elect to participate reduce their CO2 emissions by 3% per year. Utilities that opt into the program would be assured recovery of their reasonable compliance costs. On October 4, 2012, the NMPRC held a workshop to discuss the proposed standard and whether it has authority to proceed with the NOPR. On August 23, 2013, the petitioners amended the August 2, 2012 petition and requested that the NMPRC issue a NOPR to implement a "Carbon Risk Reduction Rule" for electric utilities in New Mexico. The proposed rule would require affected utilities to demonstrate a 3% per year CO2 emission reduction from a three-year average baseline period between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than one metric ton of CO2 per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords The Company monitors international treaties and accords such as the Kyoto Protocol and the EU Emissions Trading System to determine potential impacts to their business activities. The Company does not anticipate any direct impact near-term from international accords.

Transmission Issues At any given time, FERC has various notices of inquiry and rulemaking dockets related to transmission issues pending. Such actions may lead to changes in FERC administrative rules or ratemaking policy, but have no time frame in which action must be taken or a docket closed with no further action. Further, such notices and rulemaking dockets do not apply strictly to PNM, but will have industry-wide effects in that they will apply to all FERC-regulated entities.

PNM monitors and often submits comments taking a position in such notices and rulemaking dockets or may join in larger group responses. PNM often cannot determine the full impact of a proposed rule and policy change until the final determination is made by FERC and PNM is unable to predict the outcome of these matters.

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.

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers that the implementation of portions of the MOD-029 methodology for "Flow Limited" paths has been delayed until such time as a modification to the standard can be developed that will mitigate the technical concerns identified by the transmission owners and transmission service providers. PNM and other western utilities filed a Standards Action Request with NERC in the second quarter of 2012.

NERC initiated an informal development process to address directives in Order No. 729 to modify certain aspects of the MOD standards, including MOD-001 and MOD-029. The modifications to this standard would retire MOD-029 and require each transmission operator to determine and develop methodology for TTC values for MOD-001.

A final ballot for MOD-001-2 concluded on December 20, 2013 and received sufficient affirmative votes for approval. On February 10, 2014, NERC filed with FERC a petition for approval of MOD-001-2 and retirement of reliability standards A- 52-------------------------------------------------------------------------------- Table of Contents MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. The MOD-001-2 standard will become effective on the first day of the calendar quarter that is 18 months after the date the standard is approved by FERC. The retirement and changes to these MOD standards will remove the risk of reduced TTC for PNM and other southwestern utilities.

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development. Order 1000 calls for significant changes to the transmission process of WestConnect, an organization of utility companies providing transmission of electricity in the western region that includes PNM. On October 11, 2012, PNM and other WestConnect participants filed modified versions of Attachment K to their transmission tariffs to meet Order 1000 regional compliance requirements. Thirteen intervention motions were filed, with several objecting to and/or protesting various provisions of the filings submitted by the WestConnect participants. On December 17, 2012, the WestConnect participants filed responses to the issues raised by the intervenors. On March 22, 2013, FERC issued its order regarding PNM's and six other WestConnect FERC jurisdictional utilities compliance filings. FERC partially accepted many aspects of the filings including the governance structure that gives the transmission owners a veto authority over the regional plan and cost allocations. A major change directed by FERC is the requirement that the cost allocations be binding on identified beneficiaries and that a process be created that will result in a qualified developer being selected. PNM and the other WestConnect FERC jurisdictional entities submitted compliance filings on September 20, 2013 to address and comply with the March 22, 2013 FERC order. On July 11, 2013, the WestConnect participants submitted an additional compliance filing to address the planning and cost allocation between WestConnect and other regions.

Financial Reform Legislation The Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank Reform Act"), enacted in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading facility. It also includes provisions related to swap transaction reporting and recordkeeping and may impose margin requirements on swaps that are not centrally cleared. The United States Commodity Futures Trading Commission ("CFTC") has published final rules defining several key terms related to the act and has set compliance dates for various types of market participants. The Dodd-Frank Reform Act provides exemptions from certain requirements, including an exception to the mandatory clearing and swap facility execution requirements for commercial end-users that use swaps to hedge or mitigate commercial risk. PNM expects to qualify for this exception. PNM also expects to be able to comply with its requirements under the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of the Dodd-Frank Reform Act and related rules, PNM's swap activities could be subject to increased costs, including from higher margin requirements. In addition, implementation of, and compliance with, the swaps provisions of the Dodd-Frank Reform Act and related rules by PNM's swap counterparties could result in increased costs. At this time, PNM cannot predict the ultimate impact the Dodd-Frank Reform Act may have on PNM's financial condition, results of operations, cash flows, or liquidity.

Other Matters See Notes 16 and 17 for a discussion of commitments and contingencies and rate and regulatory matters. See Note 1 for a discussion of accounting pronouncements that have been issued, but are not yet effective and have not been adopted by the Company.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements in accordance with GAAP requires management to apply accounting policies and to make estimates and judgments that best provide the framework to report the results of operations and financial position for PNMR, PNM, and TNMP. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions. Management has identified the following accounting policies that it deems critical to the portrayal of the financial condition and results of operations and that involve significant subjectivity. The following discussion provides information on the processes utilized by management in making judgments and assumptions as they apply to its critical accounting policies.

Unbilled Revenues The Company records unbilled revenues representing management's assessment of the estimated amount of revenue earned from customers for services rendered between the meter-reading dates in a particular month and the end of that month.

Management estimates unbilled revenues based on daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience. The estimate requires the use of various judgments and assumptions; significant changes to these judgments and assumptions could have a material impact to the Company's results of operations.

A- 53-------------------------------------------------------------------------------- Table of Contents Regulatory Accounting The Company is subject to the provisions of GAAP for rate-regulated enterprises and records assets and liabilities resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities.

Additional information concerning regulatory assets and liabilities is contained in Note 4.

The Company continually evaluates the probability that regulatory assets and liabilities will impact future rates and makes various assumptions in those analyses. The expectations of future rate impacts are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If future recovery or refund ceases to be probable, the Company would be required to write-off the portion that is not recoverable or refundable in current period earnings.

The Company has made adjustments to regulatory assets and liabilities which have materially affected its results of operations in the past due to changes in various factors and conditions impacting future cost recovery. Based on its current evaluation, the Company believes that future recovery of its regulatory assets are probable.

Impairments Tangible long-lived assets and amortizable intangible assets are evaluated for impairment when events and circumstances indicate that the assets might be impaired in accordance with GAAP. These potential impairment indicators include management's assessment of fluctuating market conditions as a result of planned and scheduled customer purchase commitments; future market penetration; changing environmental requirements; fluctuating market prices resulting from factors including changing fuel costs and other economic conditions; weather patterns; and other market trends. The amount of impairment recognized, if any, is the difference between the fair value of the asset and the carrying value of the asset and would reduce both the asset and current period earnings. Variations in the assessment of potential impairment or in the assumptions used to calculate an impairment could result in different outcomes, which could lead to significant effects on the Consolidated Financial Statements.

Goodwill and non-amortizable other intangible assets are evaluated for impairment at least annually, or more frequently if events and circumstances indicate that the goodwill and intangible assets might be impaired. GAAP allows impairment testing to be performed based on either a qualitative analysis or quantitative analysis. Note 21 contains information on the impairment testing performed by the Company on goodwill and intangible assets. For 2013, the Company utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. No impairments were indicated in the Company's annual goodwill testing, which was performed as of April 1, 2013. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. The annual testing was based on certain critical estimates and assumptions. Changes in the estimates or the use of different assumptions could affect the determination of fair value and the conclusion of impairment for each reporting unit.

Application of the qualitative goodwill impairment test requires evaluating various events and circumstances to determine whether it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. As a part of the Company's goodwill qualitative testing process for a reporting unit, various factors that are specific to the reporting unit as well as industry and macroeconomic factors are evaluated in order to determine whether these factors are reasonably likely to have a material impact on the fair value of the reporting unit. Examples of the factors that were considered in the qualitative testing of the goodwill include the results of the most recent quantitative impairment test, current and long-term forecasted financial results, regulatory environment, credit rating, changes in the interest rate environment, and operating strategy for the reporting unit. Based on the qualitative analysis performed in 2013 for the TNMP reporting unit, the Company concluded that there were no changes that were reasonably likely to cause the fair value of the reporting unit to be less than the carrying value and determined that there was no impairment of goodwill. Although the Company believes all relevant factors were considered in the qualitative impairment analysis to reach the conclusion that goodwill is not impaired, significant changes in any one of the assumptions could produce a significantly different result potentially leading to the recording of an impairment that could have significant impacts on the results of operations and financial position of the Company.

Application of the quantitative impairment test requires judgment, including assignment of assets and liabilities to reporting units and the determination of the fair value of a reporting unit. A discounted cash flow methodology is primarily used by the Company to estimate the fair value of a reporting unit.

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 WACC for each reporting unit.

In determining the fair value of a reporting unit under the quantitative approach, the WACC is a significant factor. The Company considers many factors in selecting a WACC, including the market view of risk for each individual reporting unit, the appropriate capital structure based on that used in the ratemaking process, and the borrowing rate appropriate for a reporting unit. The Company considers available market-based information and may consult with third parties to help determine the WACC. The A- 54-------------------------------------------------------------------------------- Table of Contents selection of a WACC is subjective and modifications to this rate could significantly increase or decrease the fair value of a reporting unit.

The other primary factor impacting the determination of the fair value of a reporting unit is the estimation of future cash flows. The Company considers budgets, long-term forecasts, historical trends, and expected growth rates in order to estimate future cash flows. Any forecast contains a degree of uncertainty and modifications to these cash flows could significantly increase or decrease the fair value of a reporting unit. For the PNM and TNMP reporting units, which are subject to rate-regulation, a fair recovery of and return on costs prudently incurred to serve customers is assumed. Should the regulators not allow recovery of certain costs or not allow these reporting units to earn a fair rate of return on invested capital, the fair value of the reporting units could decrease. For the First Choice unregulated reporting unit, which PNMR sold on November 1, 2011 (Note 3), assumptions regarding customer usage, pricing, retention, and payment behavior, in addition to fluctuations in the cost of energy, significantly impacted estimates of future cash flows.

The Company believes that the WACC and cash flow projections utilized in the 2013 qualitative testing appropriately reflected the fair value of the PNM reporting unit. Since any cash flow projection contains uncertainty, the Company adjusted the WACC used to reflect that uncertainty. The Company does not believe that there are indications of goodwill impairment in any of its reporting units, but this analysis is highly subjective. As of the impairment testing for April 1, 2013, the fair value of the PNM reporting unit, which had goodwill of $51.6 million, exceeded its carrying value by approximately 27%. An increase of 0.5% in the expected return on equity capital utilized in calculating the WACC used to discount the forecasted cash flows, would have reduced the excess of PNM's fair value over carrying value to approximately 20% at April 1, 2013. The April 1, 2012 quantitative evaluation of fair value of the TNMP reporting unit, which had goodwill of $226.7 million, exceeded its carrying value by approximately 26%. Due to the subjectivity and sensitivities of the assumptions and estimates underlying the impairment analysis, there can be no assurance that future analyses, which will be based on the appropriate assumptions and estimates at that time, will not result in impairments.

Decommissioning and Reclamation Costs Accounting for decommissioning costs for nuclear and fossil-fuel generation involves significant estimates related to costs to be incurred many years in the future after plant closure. Decommissioning costs are based on site-specific estimates which are updated periodically and involve numerous judgments and assumptions. Changes in these estimates could significantly impact PNMR's and PNM's financial position, results of operations and cash flows. PNM owns and leases nuclear and fossil-fuel generation 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 are based on site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions including estimates of future decommissioning costs at current price levels, inflation rates, and discount rates. AROs, including nuclear decommissioning costs, are discussed in Note 15. Nuclear decommissioning costs represent approximately 84% of PNM's ARO liability. A 10% increase in the estimates of future decommissioning costs at current price levels would have increased the ARO liability by $8.8 million at December 31, 2013. PVNGS Units 1 and 2 are included in PNM's retail rates while PVNGS Unit 3 is excluded although PNM has requested Unit 3 be included. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fuel generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. PNM believes that it will continue to be able to collect in rates for its legal asset retirement obligations for nuclear generation activities included in the ratemaking process.

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, including estimates of future reclamation costs at current price levels, inflation rates, and discount rates. A 10% increase in the estimates of future reclamation costs at current price levels would have increased the mine reclamation liability by $2.9 million at December 31, 2013.

PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for discussion of the final reclamation costs.

Derivatives The Company follows the provisions set forth in GAAP to account for derivatives.

These provisions establish accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. GAAP also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. 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.

Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in A- 55-------------------------------------------------------------------------------- Table of Contents any estimate technique. Changes in the assumptions used in the fair value determinations could have significant impacts on the results of operations and financial position of the Company. Note 8 contains additional information on commodity derivatives, including the volumes covered by derivative contracts.

Pension and Other Postretirement Benefits The Company maintains qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The net periodic benefit cost or income and the calculation of the projected benefit obligations are recognized in the Company's financial statements and depend on expected investment performance, the level of contributions made to the plans, and employee demographics. They both require the use of a number of actuarial assumptions and estimates. The most critical of the actuarial assumptions are the expected long-term rate of return, the discount rate, and projected health care cost trend rates. The Company reviews and evaluates its actuarial assumptions annually and adjusts them as necessary.

Changes in the pension and OPEB assets and liabilities associated with these factors are not immediately recognized as net periodic benefit cost or income in results of operations, but are recognized in future years, generally, over the remaining life of the plan. However, these factors could have a significant impact on the financial position of the company. Note 12 contains additional information about pension and OPEB obligations, including assumptions utilized in the calculations and impacts of changes in certain of those assumptions.

Accounting for Contingencies The financial results of the Company may be affected by judgments and estimates related to loss contingencies. Losses associated with uncollectible trade accounts receivable was a significant contingency for First Choice, which PNMR sold on November 1, 2011. The determination of bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, general economic conditions, and customer behavior.

Contingencies related to litigation and claims, as well as environmental and regulatory matters, also require the use of significant judgment and estimation.

The Company attempts to take into account all known factors regarding the future outcome of contingent events and records an accrual for any contingent events that are both probable and reasonably estimated based upon current available information. However the actual outcomes can vary from any amounts accrued which could have a material effect on the results of operations and financial position of the Company. See Note 16 and Note 17.

Income Taxes The Company's income tax expense and related balance sheet amounts involve significant judgment and use of estimates. Amounts of deferred income tax assets and liabilities, current and noncurrent accruals, and determination of uncertain tax positions involve judgment and estimates related to timing and probability of the recognition of income and deductions by taxing authorities. In addition, some temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, the Company's forecasted financial condition and results of operations in future periods, and the final review from taxing authorities. See Note 11.

Market Risk See Part II, Item 7A. Quantitative and Qualitative Disclosure About Market Risk for discussion regarding the Company's accounting policies and sensitivity analysis for the Company's financial instruments and derivative energy and other derivative contracts.

MD&A FOR PNM RESULTS OF OPERATIONSPNM operates in only one reportable segment, as presented above in Results of Operations for PNMR.

MD&A FOR TNMP RESULTS OF OPERATIONSTNMP operates in only one reportable segment, as presented above in Results of Operations for PNMR.

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