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[March 01, 2013]
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 739,000 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 • Continuing to improve 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 and customer satisfaction • Maintaining strong plant performance and reliability 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. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: managing the Company's business and serving our customers well, 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 for recovery of capital invested in transmission and distribution projects without having to file a general rate case and allow for more timely recovery of amounts invested in TNMP's systems. In 2011, PNM made significant progress toward the goal of achieving authorized returns for its retail customers. In 2012, PNM saw additional progress toward achieving authorized returns for its transmission and generation customers regulated by FERC.
PNM and TNMP completed several rate proceedings before their state regulators in 2011 and 2012. PNM has two rate cases pending before FERC and one that was completed in early 2013. Additional information about rate filings is provided in Note 17.
PNM previously announced that it intended to file a request for an increase in the rates charged to New Mexico retail customers in mid-2013, but is currently re-evaluating when this filing will occur, partially due to the lack of clarity around the timing and amount of capital that will be required for BART at SJGS, as discussed below, and improved operating results at PNM.
Fair and timely rate treatment from regulators is crucial to achieving PNMR's 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 rating agencies and would further improve credit ratings, which could lower costs to customers. Also, earning allowed returns should result in increased earnings for PNMR, which should lead to increased total returns to investors.
PNM's interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates.
While PVNGS Unit 3's financial contribution is not calculated in the authorized returns on its regulated business, it impacts PNM's earnings and has demonstrated A- 26-------------------------------------------------------------------------------- Table of Contents 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.
Continuing to Improve 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. On April 13, 2012, S&P raised the corporate credit rating for PNMR as well as the senior debt ratings for PNMR and TNMP and the preferred stock rating for PNM.
S&P changed the outlook to stable for all entities.
Providing Top-Quartile Total Returns to Investors PNMR's strategic goal to provide top quartile total return to investors is based on five-year ongoing EPS growth along with five-year average dividend yield. Top quartile total return currently is equal to an average annual rate of 10 percent to 13 percent. The annual common stock dividend was raised by 16 percent in February 2012 and 14 percent in February 2013.
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. 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 PNMR 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 our 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. We believe there is a direct connection between electric infrastructure to ensure reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and energy reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability. 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 ensure reliability and meet 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 2012, TNMP had completed installation of more than 75,000 smart meters. 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, the smart meter rollout will ultimately give consumers more energy consumption data and help them make more informed decisions. In 2013, TNMP will install a new outage management system that will leverage capabilities of the smart meters to enhance the company's responsiveness to outages.
During the 2010 to 2012 period, PNM and TNMP together invested $803.7 million in substations, power plants, and transmission and distribution systems in New Mexico and Texas. In 2012, PNM announced the site for its planned 40 MW natural gas-fired peaking generating station. Construction 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 purchase power agreement since 2000.
Environmentally Responsible Power PNMR has a long-standing record of environmental stewardship. In 2012, its environmental focus was in three key areas: •Preparing to meet New Mexico's increasing renewable energy requirements as cost-effectively as possible • Developing strategies to meet regional haze rules at the coal-fired SJGS as cost effectively as possible while providing broad environmental benefits •Increasing energy efficiency participation A- 27-------------------------------------------------------------------------------- Table of Contents Renewable Energy In 2012, PNM filed and the NMPRC approved PNM's 2013 renewable procurement strategy. The approved strategy will almost double PNM's solar capacity with the addition of 21.5 MW of utility-owned solar capacity estimated cost of almost $50 million. In addition to the solar expansion, the 2013 proposal includes a 20-year agreement to purchase energy from a geothermal facility to be built near Lordsburg. The 10 MW facility will be the first geothermal project for the PNM system.
In addition to the 22 MW of solar currently available through the five plants constructed in 2011, PNM also owns a sixth facility, 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 with the Electric Power Research Institute, East Penn Manufacturing Co., Northern New Mexico College, Sandia National Laboratories, and the University of New Mexico. When the facility went online in September 2011, it was the nation's first solar storage facility fully integrated into a utility's power grid.
PNM's resource portfolio includes the purchase of 204 MW of wind power. PNM also purchases power from a customer-owned distributed solar generation program having an installed capacity of 19.8 MW at the end of 2012. Distributed generation, wind, and solar power are key means for PNM to meet the RPS established by the REA and related regulations issued by the NMPRC. These rules require a utility to achieve prescribed levels of energy sales from renewable sources within its generation mix, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC, which aims to moderate the cost to consumers when utilities use more renewable resources.
PNM sought and received a waiver from the NMPRC excusing it from meeting the RPS in 2012 because the cost to achieve the full RPS would exceed the RCT. The 2013 plan will enable PNM to comply with the statutory RPS amount in 2013, but required a variance from the NMPRC's diversity requirements in 2013 while the proposed geothermal facilities are being constructed. This plan is expected to enable PNM to achieve full RPS quantity and diversity compliance by 2014 without exceeding the RCT. 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. The FIP for regional haze requires the installation of SCRs on all four units at SJGS by September 2016. PNM is challenging EPA's proposal in court and administratively within EPA.
In order to keep costs to customers as low as possible while also reducing visibility impairment related to regional haze, PNM has supported the installation of SNCRs at SJGS, a technology proposed by the State of New Mexico to meet the regional haze regulations. Additional information about BART at SJGS is contained in Note 16.
On February 15, 2013, PNM, NMED, and EPA agreed 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. PNM would also build a natural gas plant in the Four Corners region to partially replace the capacity from the retired coal units. Implementing this plan would include: • NMED development of a revised SIP • Approval of the revised SIP by EIB • EPA approval of the revised SIP • NMPRC approval of the retirement of Units 2 and 3 and plans to acquire replacement power The term sheet setting forth the non-binding agreement projects EIB approval for October 2013, with EPA final action in 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 and PNM to create a reasonable FIP compliance schedule to reflect the time used to develop the new state plan. PNM is also exploring potential additional areas of relief, including relief from the Tenth Circuit.
In connection with the implementation of the plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners as may be agreed upon by the owners of the affected units. Owners of the affected units also may seek approvals of their utility commissions or governing boards.
A- 28-------------------------------------------------------------------------------- Table of Contents On February 25, 2013, the parties filed their status reports with the Tenth Circuit. To demonstrate that progress has been made toward settling the Tenth Circuit litigation, information, including the non-binding agreement and its accompanying timeline, was submitted to the court. Following the parties' submission of their status reports, on February 28, 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals.
This 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.
Detailed replacement power strategies also would be finalized. PNM believes adequate replacement power alternatives will be available to meet its generation needs and ensure reliability. PNM can provide no assurance that the requirements of this plan will be accomplished at all or within the required timeframes.
In order to be able to install SCRs on all four units of SJGS by the compliance deadline set forth in the FIP, PNM entered into a contract in October 2012 with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. The construction contract, which includes termination provisions in the event that SCRs are determined in the future to be unnecessary, has been suspended through November 1, 2014.
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 $320 million in 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. PNM's share of the costs of these upgrades was $161 million. Since 2006, SJGS has reduced NOx emissions by 43 percent, SO2 by 69 percent, particulate matter by 64 percent, and mercury by 99 percent.
Energy Efficiency Energy efficiency also plays a significant role in helping to keep customers' electricity costs low and meeting their energy needs. PNM's and TNMP's energy efficiency and load management portfolios continue to be robust. In 2012, annual energy saved as a result of PNM's portfolio of energy efficiency programs was approximately 71,000 MWh. This is equivalent to the consumption of approximately 9,600 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 2012 resulted in energy savings totaling an estimated 12,839 MWh.
Creating Value for Customers and Communities 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 2012, PNM hosted 23 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $1.0 million of assistance with utility bills to 10,216 families in 2012.
The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. For 2012, the foundation awarded $0.3 million to support 55 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 $1.1 million of support.
PNM also expanded its environmental stakeholder outreach in 2012, 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 the 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 in Valencia County, 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.
Economic Factors In 2012, PNM experienced a decrease in weather-normalized, retail load of 0.7% and TNMP experienced an increase in weather-normalized, retail load of 3.7% compared to 2011. 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 A- 29-------------------------------------------------------------------------------- Table of Contents workforce. Employment growth is much more telling, as Texas leads the way with growth rates well above the national rate while New Mexico's employment is relatively flat.
Results of Operations A summary of net earnings (loss) attributable to PNMR is as follows: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (In millions, except per share amounts) Net earnings (loss) $ 105.5 $ 176.4 $ (45.2 ) $ (70.9 ) $ 221.6 Average common and common equivalent shares 80.4 89.8 91.6 (9.4 ) (1.8 ) Net earnings (loss) per diluted share $ 1.31 $ 1.96 $ (0.49 ) $ (0.65 ) $ 2.45 The components of the changes in earnings (loss) from continuing operations attributable to PNMR by segment are: Change 2012/2011 2011/2010 (In millions) PNM $ 37.0 $ (2.8 ) TNMP 4.4 6.3 First Choice (24.1 ) 0.1 Corporate and Other (88.2 ) 95.1Optim Energy, including impairment - 122.9 Net change $ (70.9 ) $ 221.6 PNMR's operational results were affected by the following: • Exit from unregulated businesses - As discussed above, PNMR sold First Choice in 2011, resulting in a pre-tax gain of $174.9 million, which was included in the Corporate and Other segment. Additionally, PNMR wrote-off its investment in Optim Energy in 2010, recognizing a pre-tax impairment loss of $188.2 million. In addition to the impacts of these transactions, results of operations only include Optim Energy through December 31, 2010 and First Choice through October 31, 2011.
• Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17 • 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 2017. In addition, TNMP has a $75.0 million revolving credit facility, which expires in December 2015. Total availability for PNMR on a consolidated basis was $603.0 million at February 22, 2013. 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 $2,047.4 million for 2013-2017. The construction expenditures 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 . This estimate does not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze (Note 16) or expenditures that could be required to replace capacity should environmental control at SJGS involve shutdown of one or more SJGS units. 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 2013-2017 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- 30-------------------------------------------------------------------------------- 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.
PNM The table below summarizes operating results for PNM: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (In millions) Total revenues $ 1,092.3 $ 1,057.3 $ 1,017.1 $ 35.0 $ 40.2 Cost of energy 353.6 362.2 352.3 (8.6 ) 9.9 Margin 738.6 695.1 664.9 43.5 30.2 Operating expenses 435.4 438.8 424.5 (3.4 ) 14.3 Depreciation and amortization 97.3 94.8 92.3 2.5 2.5 Operating income 205.9 161.4 148.1 44.5 13.3 Other income (deductions) 26.5 19.9 31.6 6.6 (11.7 ) Net interest charges (76.1 ) (75.3 ) (72.4 ) (0.8 ) (2.9 ) Earnings before income taxes 156.3 106.0 107.3 50.3 (1.3 ) Income (taxes) (50.7 ) (37.4 ) (36.4 ) (13.3 ) (1.0 ) Valencia non-controlling interest (14.1 ) (14.0 ) (13.6 ) (0.1 ) (0.4 ) Preferred stock dividend requirements (0.5 ) (0.5 ) (0.5 ) - - Segment earnings $ 91.0 $ 54.0 $ 56.8 $ 37.0 $ (2.8 ) The table below summarizes the significant changes to total revenues, cost of energy, and margin: 2012/2011 Change 2011/2010 Change Total Cost of Total Cost of Revenues Energy Margin Revenues Energy Margin (In millions) Retail rate increases $ 40.3 $ - $ 40.3 $ 32.1 $ - $ 32.1 Retail load, fuel, and transmission (15.9 ) (10.6 ) (5.4 ) 28.3 10.7 17.5 Wholesale rate increase 4.0 - 4.0 Unregulated margins (5.9 ) 1.1 (7.0 ) (41.0 ) 0.9 (41.9 ) Energy efficiency rider 8.9 - 8.9 13.0 - 13.0 Renewable rider 6.9 2.0 4.9 - - - Net unrealized economic hedges (3.3 ) (1.1 ) (2.2 ) 7.8 (1.7 ) 9.5 Total increase (decrease) $ 35.0 $ (8.6 ) $ 43.5 $ 40.2 $ 9.9 $ 30.2 The following table shows PNM operating revenues by customer class and average number of customers: A- 31-------------------------------------------------------------------------------- Table of Contents Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (In millions, except customers) Residential $ 409.0 $ 390.4 $ 355.9 $ 18.6 $ 34.5 Commercial 413.3 386.4 355.7 26.9 30.7 Industrial 104.0 94.9 85.6 9.1 9.3 Public authority 25.5 24.0 21.3 1.5 2.7 Transmission 39.4 43.6 38.7 (4.2 ) 4.9 Firm-requirements wholesale 39.4 34.1 31.9 5.3 2.2 Other sales for resale 47.4 69.3 121.7 (21.9 ) (52.4 ) Mark-to-market activity 0.9 4.2 (3.6 ) (3.3 ) 7.8 Other 13.4 10.4 9.9 3.0 0.5 $ 1,092.3 $ 1,057.3 $ 1,017.1 $ 35.0 $ 40.2 Average retail customers (thousands) 505.6 503.9 501.7 1.7 2.2 The following table shows PNM GWh sales by customer class: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (Gigawatt hours) Residential 3,323.5 3,402.8 3,361.5 (79.3 ) 41.3 Commercial 4,022.2 4,043.8 4,016.0 (21.6 ) 27.8 Industrial 1,771.3 1,560.9 1,449.9 210.4 111.0 Public authority 279.2 282.1 263.4 (2.9 ) 18.7 Firm-requirements wholesale 652.0 650.4 677.5 1.6 (27.1 ) Other sales for resale 1,652.2 2,076.8 2,203.8 (424.6 ) (127.0 ) 11,700.4 12,016.8 11,972.1 (316.4 ) 44.7 On August 21, 2011, PNM implemented a $72.1 million annual non-fuel rate increase for its retail customers. This rate increase, combined with a base rate increase in April 2010, improved 2012 and 2011 revenues and margins by $40.3 million and $32.1 million. In 2012, lower retail loads, primarily in the residential and commercial customer classes, reflecting lower average usage per customer and milder weather, decreased revenues and margins by $7.8 million. The increase in industrial revenue is primarily due to providing economy energy service to one customer. The only impact in margin for this customer is from minor ancillary services and other changes in revenues and cost of energy are a pass-through with no impact to margin. Higher transmission rates as a result of the June 1, 2011 rate increase, approved by FERC on January 2, 2013, also improved revenues and margins in 2012 and 2011. In 2011, increases in retail loads were primarily driven by cooler temperatures in the first quarter and warmer weather in the third quarter, improving revenue and margins by $12.0 million.
Increases in fuel costs and the reduction in off-system sales volumes resulting from the fire incident at the mine providing coal to SJGS are recovered through PNM's FPPAC and did not negatively impact 2012 or 2011 results. See Note 16 for more discussion on the SJGS mine fire incident.
PNM implemented new rates, approved by FERC, subject to refund, for one of its firm wholesale requirements customers in April 2012, which improved revenues and margins by $4.0 million. See Note 17.
PNM offers several energy efficiency programs and initiatives to its retail customers regulated by the NMPRC. In addition, PNM is allowed to earn adders on these programs based on energy savings. PNM recovers the energy efficiency program costs via a rate rider. Revenues and margins were higher by $8.9 million and $13.0 million in 2012 and 2011, offset with an increase in operating expense for the energy efficiency program costs.
On August 20, 2012, PNM implemented its renewable energy rider, a mechanism approved by NMPRC, which will allow PNM to recover renewable energy investments, including a return on its investments, and procurement costs incurred in meeting the state-mandated RPS. See Note 17. In 2012, PNM revenues increased by $6.9 million and cost of energy, reflecting the purchase A- 32-------------------------------------------------------------------------------- Table of Contents cost of RECs, increased $2.0 million. Included in revenues is the earned return component on its investment of $1.2 million and the remaining revenues are offset by increases in operating and depreciation expenses associated with the PNM-owned PV solar facilities.
In 2012, lower unregulated revenues of $5.9 million and lower margin of $7.0 million associated with sales of power from PVNGS Unit 3 were a result of lower market power prices and increases in nuclear fuel costs. In 2011, lower unregulated revenues and margins were the result of the December 31, 2010 expiration of a long-term tolling arrangement for PVNGS Unit 3, which contained favorable pricing terms compared to 2011 market prices.
Changes in unrealized mark-to-market gains and losses are based on economic hedges for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $1.6 million for 2012 compared to unrealized gains of $3.8 million for 2011 decreased margin by $2.2 million.
Unrealized gains of $3.8 million for 2011 compared to unrealized losses of $5.7 million for 2010 increased margin by $ 9.5 million.
In 2012, operating expenses decreased by $2.1 million due to improved availability 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 and renewable expenses of $11.4 million and $1.0 million, which are offset in revenues as discussed above. As discussed in Note 7, PNM recorded a lease abandonment loss of $6.2 million in operating expenses in 2012.
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.
Operating expenses reflect a regulatory disallowance of $17.5 million recorded in 2011 resulting from PNM's 2010 Electric Rate Case. No regulatory disallowances were recorded in 2012 or in 2010. In 2011, PNM incurred operating expenses of $6.7 million to implement process improvement initiatives related to reducing future costs. In addition, increases in taxes other than income due to additional New Mexico gross receipts tax on prior year billings and other expenses increased operating expenses by $5.0 million in 2011 and reduced operating expenses by $0.4 million in 2012. Lower expense for injuries and damages improved operating expenses in 2011 by $2.9 million.
Depreciation and amortization expense increased in 2012 and 2011 due to additions to utility plant, including PNM-owned solar PV facilities.
Depreciation on the PNM-owned solar PV facilities is recovered through a rate rider as discussed above.
For 2012, other income (deductions) was $6.6 million higher, primarily related to improved performance of the NDT of $5.9 million. PNM incurred less impairments of NDT investments in 2012 compared to 2011. In addition, higher equity AFUDC of $3.3 million improved other income, offset by lower interest income on the PVNGS lessor notes of $2.8 million due to lower outstanding balances. In 2011, lower interest income on the PVNGS lessor notes, lower equity portion of AFUDC were partially offset with increased realized gains on the NDT assets. A pre-tax gain of $8.5 million due to settlement of the Republic Savings Bank litigation increased other income in 2010.
Interest expense increased $8.8 million and $1.8 million in 2012 and 2011 due to the issuance of $160.0 million of long-term debt in October 2011. In 2012, the higher interest expense 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 rider.
A- 33-------------------------------------------------------------------------------- Table of Contents TNMP The table below summarizes the operating results for TNMP: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (In millions) Total revenues $ 250.1 $ 237.9 $ 212.6 $ 12.2 $ 25.3 Cost of energy 46.2 41.2 37.1 5.0 4.1 Margin 203.9 196.7 175.5 7.2 21.2 Operating expenses 87.1 88.2 77.4 (1.1 ) 10.8 Depreciation and amortization 49.3 44.6 41.7 4.7 2.9 Operating income 67.5 63.8 56.4 3.7 7.4 Other income (deductions) 2.7 1.6 0.8 1.1 0.8 Net interest charges (28.2 ) (29.3 ) (31.2 ) 1.1 1.9 Earnings before income taxes 42.1 36.1 26.0 6.0 10.1 Income (taxes) (15.4 ) (13.9 ) (10.0 ) (1.5 ) (3.9 ) Segment earnings $ 26.7 $ 22.3 $ 16.0 $ 4.4 $ 6.3 The table below summarizes the significant changes to total revenues, cost of energy, and margin: 2012/2011 Change 2011/2010 Change Total Cost of Total Cost of Revenues Energy Margin Revenues Energy Margin (In millions) Rate increases $ 1.4 $ - $ 1.4 $ 8.7 $ - $ 8.7 Customer usage/load (2.1 ) - (2.1 ) 5.5 - 5.5 Transmission cost recovery factor 4.9 5.0 (0.1 ) 6.8 4.1 2.7 AMS surcharge 6.9 - 6.9 1.6 1.6 1999 rate settlement 1.6 - 1.6 - - - Other (0.5 ) - (0.5 ) 2.7 - 2.7 Total increase $ 12.2 $ 5.0 $ 7.2 $ 25.3 $ 4.1 $ 21.2 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 2012 2011 2010 2012/2011 2011/2010 (In millions, except customers) Residential $ 103.3 $ 100.3 $ 83.6 $ 3.0 $ 16.7 Commercial 88.3 84.9 77.5 3.4 7.4 Industrial 13.4 13.1 12.3 0.3 0.8 Other 45.1 39.6 39.2 5.5 0.4 $ 250.1 $ 237.9 $ 212.6 $ 12.2 $ 25.3 Average consumers (thousands) (1) 233.0 231.3 229.4 1.7 1.9 (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 and 75,220 consumers of TNMP for 2011 and 2010 that chose First Choice as their REP. These consumers are also included in the First Choice segment.
A- 34-------------------------------------------------------------------------------- Table of Contents The following table shows TNMP GWh sales by retail tariff consumers class: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (Gigawatt hours)(1) Residential 2,714.5 2,862.3 2,699.6 (147.8 ) 162.7 Commercial 2,353.1 2,361.0 2,260.5 (7.9 ) 100.5 Industrial 2,727.1 2,578.9 2,241.5 148.2 337.4 Other 103.9 108.7 103.3 (4.8 ) 5.4 7,898.6 7,910.9 7,304.9 (12.3 ) 606.0 (1) The GWh sales reported above include 836.6 and 1,012.8 GWhs for 2011 and 2010 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 late September 2012 and February 2011 increased revenues and margins by $1.4 million in 2012. See Note 17. Higher usage per customer, after adjusting for weather impacts, and growth in the number of consumers in TNMP's service areas were more than offset with milder weather compared to 2011, reducing revenues and margins by $2.1 million. In 2012, TNMP received a $1.6 million settlement related to ERCOT transmission rates charged from the fourth quarter of 1999. Differences between revenues and costs charged by transmission providers are deferred and recovered through a transmission cost recovery factor, resulting in no impact to margin 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. Revenues increased by $6.9 million in 2012 and $1.6 million in 2011, which offset increases in operating expenses and depreciation. Other changes in revenue include an increase for energy efficiency programs, which was more than offset by lower revenues associated with recovery of CTC, Hurricane Ike, and rate case expenses.
In 2011, a rate increase implemented in May 2010 increased revenues and margins by $8.7 million. In addition, weather impacts on customer usage and load, as well as moderate customer growth improved revenues and margins by $5.5 million.
In 2011, changes to Texas retail electric rules that allow distribution providers to defer and recover differences between revenues and costs charged by transmission providers improved margins by $2.7 million, reflecting the elimination of the regulatory lag. Higher revenues associated with recovery of the CTC, Hurricane Ike, rate case expenses, and energy efficiency programs were offset with increases in operating expenses.
Increases in vegetation management expenses of $1.7 million, higher energy efficiency program expenses of $0.8 million, higher expenses for injuries and damages of $0.9 million, and $2.6 million higher administrative and general and customer related expenses associated with the AMS deployment increased operating expenses in 2012. As discussed in Note 7, TNMP recorded a lease abandonment loss of $1.2 million in operating expenses in 2012. 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.
In 2011, operating expenses increased due to a regulatory disallowance of $3.9 million, regarding retroactive application of the interest rate used to calculate the return on TNMP's CTC regulatory assets. See Note 17. In 2011, TNMP incurred operating expenses of $1.5 million to implement process improvement initiatives related to reducing future costs. Higher allocation of corporate overhead and incentive compensation and higher street rental and property taxes, and energy efficiency and rate case amortizations also increased operating expenses in 2011.
Deployment of AMS on TNMP's system increased depreciation and amortization by $3.1 million in 2012. In addition, increased investment in plant increased depreciation by $ 1.8 million. In 2011, depreciation and amortization expense increased due to higher transmission plant and the AMS deployment.
An increase in contributions in aid of construction of $0.7 million and a gain on the sale of property of $0.3 million, improved other income in 2012. The refinancing of TNMP's revolving credit facility in 2010 resulted in a write-off of unamortized debt issuances costs that did not recur in 2011.
On September 30, 2011, TNMP replaced its 2009 Term Loan Agreement, at lower interest rates, which reduced interest expense in 2012 and 2011. In addition, an increase in allowance for funds used during construction further reduced interest expense in 2012. In 2010, a TNMP credit facility was amended, which resulted in lower fees and more favorable interest rates in 2011.
A- 35-------------------------------------------------------------------------------- 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 compared to a full year of operations for 2010: Ten Months Ended October 31, Year Ended December 31, Change 2011 2010 2011/2010 (In millions) Total revenues $ 439.5 $ 483.2 $ (43.8 ) Cost of energy 323.3 350.5 (27.1 ) Margin 116.1 132.7 (16.6 ) Operating expenses 76.0 92.1 (16.1 ) Depreciation and amortization 1.1 0.9 0.2 Operating income 39.1 39.8 (0.7 ) Other income (deductions) (0.6 ) (0.4 ) (0.2 ) Net interest charges (0.6 ) (1.3 ) 0.7 Earnings before income taxes 37.9 38.1 (0.2 ) Income (taxes) (13.8 ) (14.1 ) 0.3 Segment earnings $ 24.1 $ 24.1 $ 0.1 The changes to total revenues, cost of energy, and margin in 2011 compared to 2010 are primarily due to ten months of operations in 2011 compared to twelve months in 2010.
The following table shows First Choice operating revenues by customer class and the actual number of customers: Ten Months Ended Year Ended October 31, December 31, Change 2011 2010 2011/2010 (In millions, except customers) Residential $ 260.2 $ 305.8 $ (45.6 ) Commercial 166.5 159.8 6.7 Other 12.8 17.6 (4.9 ) $ 439.5 $ 483.2 $ (43.8 ) Actual customers (thousands) (1,2) 221.1 214.2 6.9 (1) See note above in the TNMP segment discussion about the impact of TECA.
(2) Due to the competitive nature of First Choice's business, actual customer count at the end of the period is a more representative business indicator than average customers.
The following table shows First Choice GWh electric sales by customer class: Ten Months Ended October 31, Year Ended December 31, Change 2011 2010 2011/2010 (Gigawatt hours(1)) Residential 2,006.4 2,267.8 (261.4 ) Commercial 1,538.2 1,363.8 174.4 3,544.6 3,631.6 (87.0 ) (1) See note above in the TNMP segment discussion about the impact of TECA.
A- 36 -------------------------------------------------------------------------------- Table of Contents Total revenues decreased in 2011, primarily due to the ten months of operations in 2011 versus twelve months in 2010. Prior to the sale, total 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. Accordingly, First Choice had forward contracts for the purchase of energy to cover the future load requirements for most of its fixed price sales contracts. Changes in the fair value of supply contracts that were not designated or were not eligible for hedge or normal purchase or sales accounting were marked to market through current period earnings as required by GAAP. During 2010, market energy prices decreased significantly, which resulted in GAAP losses on certain of First Choice's forward supply contracts. During 2011, market energy prices increased, which resulted in 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. Gains on unrealized economic hedges increased segment earnings by $4.9 million in 2011 compared with losses of $22.4 million in 2010.
The allowance for uncollectible accounts and related bad debt expense was based on collections and write-off experience. Bad debt expense decreased $16.2 million in 2010 due to lower customer departures, lower default rates, and an increase in commercial customers. In 2011, bad debt expense decreased by $4.6 million, primarily due to the ten months of operations in 2011 versus twelve months in 2010. 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.
Total operating expenses decreased in 2011, primarily due to the ten months of operations in 2011 versus twelve months in 2010. 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 and 2010, interest expense decreased primarily due to lower short-term debt.
Corporate and Other The table below summarizes the operating results for Corporate and Other: Year Ended December 31, Change 2012 2011 2010 2012/2011 2011/2010 (In millions) Total revenues $ - $ (34.0 ) $ (39.4 ) $ 34.0 $ 5.4 Cost of energy - (33.8 ) (39.1 ) 33.8 5.3 Margin - (0.2 ) (0.3 ) 0.2 0.2 Operating expenses (17.9 ) (9.7 ) (12.3 ) (8.2 ) 2.6 Depreciation and amortization 17.5 16.5 16.8 1.0 (0.3 ) Operating income (loss) 0.3 (7.0 ) (4.9 ) 7.3 (2.2 ) Gain on sale of First Choice 1.0 174.9 - (173.9 ) 174.9 Optim Energy loss and impairment - - (203.4 ) - 203.4 Other income (deductions) (8.1 ) (15.8 ) (6.0 ) 7.7 (9.8 ) Net interest charges (16.6 ) (19.6 ) (20.5 ) 3.0 0.9 Earnings (loss) before income taxes (23.4 ) 132.5 (234.8 ) (155.9 ) 367.3 Income (taxes) benefit 11.2 (56.5 ) 92.8 67.7 (149.3 ) Segment earnings (loss) $ (12.2 ) $ 76.0 $ (142.0 ) $ (88.2 ) $ 218.1 The Corporate and Other segment includes consolidation eliminations of revenues and cost of energy between business segments, primarily related to TNMP's sale of transmission services to First Choice prior to November 1, 2011, when PNMR sold First Choice. Accordingly, there was no elimination of intersegment revenue in 2012.
Operating expenses decreased in 2012 and increased in 2011 primarily due to legal and consulting expenses of $4.6 million incurred in 2011 related to assessment of strategic alternatives for PNMR's competitive businesses. Other changes in operating A- 37-------------------------------------------------------------------------------- Table of Contents expenses are offset as a result of allocation of depreciation and amortization and items within other income (deductions) to other business segments.
Depreciation expense increased in 2012 due to accelerated amortization of leasehold improvements for part of its corporate headquarters that was abandoned during 2012. This increase was partially offset by lower depreciation on software applications compared to 2011. Changes in depreciation and amortization are offset in operating expenses as a result of allocation of these costs to other business segments. PNM and TNMP defer their allocations of the accelerated amortization of leasehold improvements as regulatory assets to be recovered through rates.
Corporate and Other results include the gain on the sale of First Choice.
Results of operations of First Choice are discussed above. The sale of First Choice is discussed in Note 3.
Corporate and Other results also include losses associated with Optim Energy.
Further information regarding Optim Energy is shown below. The 2010 loss due to the impairment of PNMR's investment in Optim Energy, which is discussed above and in Note 21, is also reflected in the Corporate and Other segment.
Other income and deductions decreased in 2011 and increased in 2012 primarily due to a $9.2 million loss on the repurchase of $50.0 million of PNMR's 9.25% senior unsecured notes in November 2011 (Note 6). This was offset by lower performance on other investments. Net interest charges decreased in 2012 and 2011, primarily due to the re-acquisition.
In 2010 and 2012, income tax benefit was reduced by $2.6 million and $0.7 million due to the impairment of New Mexico wind energy production tax credit carry forwards. These credits were not expected to be utilized prior to their expiration due to the Company's net operating loss position. On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation, was signed into law. Due to provisions in the act, taxes payable to the state of New Mexico for 2013 will be reduced and PNMR anticipates that it will be required to impair an additional $1.5 million of New Mexico wind energy production tax credits in the first quarter of 2013.
Optim Energy As described above and in Note 21, PNMR reduced its investment in Optim Energy to zero at December 31, 2010 due to the determination that the investment was fully impaired, resulting in a pre-tax impairment loss of $188.2 million ($113.7 million after-tax). In accordance with GAAP, PNMR did not record income or losses associated with its investment in Optim Energy in 2011 as PNMR had no contractual requirement or agreement to provide Optim Energy with additional financial resources. Accordingly, Optim Energy had no impact on PNMR's 2011 balance sheet, statement of earnings, and statement of cash flows. Summarized financial information for Optim Energy is not presented. PNMR entered into agreements on September 23, 2011 that reduced PNMR's ownership in Optim Energy from 50% to 1%. On January 4, 2012, ECJV exercised its option to acquire PNMR's remaining 1% ownership interest in Optim Energy at fair market value, which was determined to be zero. PNMR accounted for its investment in Optim Energy using the equity method of accounting until September 23, 2011 and used the cost method thereafter.
In 2010, Optim Energy's strategy and near-term focus was on utilizing cash flow from operations to reduce debt and optimizing its generation assets as a stand-alone independent power producer. Optim Energy's results of operations were primarily determined by the prices at which its power was sold and its fuel to generate power, principally natural gas, was procured. Power prices in the ERCOT market are directly correlated to natural gas prices. The markets for power and natural gas were depressed in 2010. Optim Energy had net earnings (loss) of $(25.1) million for the year ended December 31, 2010. PNMR recognized net earnings (loss) from Optim Energy of $(15.2) million for the year ended December 31, 2010. Such amounts include amortization of a basis difference between PNMR's recorded investment in Optim Energy and 50 percent of Optim Energy's equity.
A- 38-------------------------------------------------------------------------------- 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 2012 2011 2010 2012/2011 2011/2010 (In millions) Net cash flows from: Operating activities $ 281.3 $ 292.2 $ 287.4 $ (10.9 ) $ 4.8 Investing activities (285.9 ) 19.8 (275.9 ) (305.7 ) 295.7 Financing activities (1.6 ) (312.3 ) (10.7 ) 310.7 (301.6 ) Net change in cash and cash equivalents $ (6.1 ) $ (0.3 ) $ 0.8 $ (5.9 ) $ (1.1 ) The changes in PNMR's cash flows from operating activities relate primarily to improved results of operations at PNM and TNMP, primarily due to rate increases, as well as PNM's receipt of $21.6 million for governmental grants related to renewable energy initiatives in 2012 compared to $2.1 million in 2011. Increases were mostly offset by gains related to the sale of First Choice of $1.0 million in 2012 compared to $174.9 million in 2011. Contributions to the PNM and TNMP pension and other postretirement benefit plans of $89.2 million in 2012 compared to $48.3 million in 2011 and income taxes paid of $5.3 million in 2012 compared to refunds of $5.5 million in 2011 and $99.3 million in 2010 also offset the increases.
The changes in PNMR's cash flows from investing activities relate primarily to proceeds from the sale of First Choice of $4.0 in 2012 compared to $329.3 million offset by related transaction costs of $10.9 million in 2011. Utility plant additions decreased $18.0 million in 2012 and increased $45.4 million in 2011. At PNM, total utility plant additions in 2012 decreased by $54.5 million and increased by $45.4 million in 2011. PNM's 2011 additions included $59.2 million related to solar projects, which were completed by the end of 2011. 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 also 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. In addition, PNMR made equity contributions of $20.3 million to Optim Energy in 2010.
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. 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. In 2012, PNM refinanced $20.0 million of PCRBs. 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. In addition, payments received on PVNGS firm-sales contract arrangements were $2.6 million in 2011 compared to $30.5 million in 2010 as those contract expired at December 31, 2010. In 2010, PNM refinanced the $403.8 million of PCRBs.
Financing Activities See Note 6, for additional information concerning the Company's financing activities. In May 2012, PNM received NMPRC approval to participate in the refunding of $20.0 million of PCRBs. PNM also received NMPRC authority to exercise the two one-year extension options under the PNM Revolving Credit Facility. The PNMR Revolving Credit Facility also provides for two one-year extension options although NMPRC authority to exercise them is not required. In October 2012, the first of the one-year extension options for the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility were exercised extending the expiration of both facilities to October 31, 2017.
In September 2012, PNM participated in the issuance of $20.0 million of new PCRBs by the City of Farmington, New Mexico, which bear interest at 2.54% and mature September 1, 2042 with a mandatory tender on June 1, 2017. The new PCBRs refunded a $20.0 million series of PCRBs, which bore interest at 5.15% and matured in 2037, that were redeemed at par and retired.
A- 39-------------------------------------------------------------------------------- Table of Contents 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 those for renewable energy • Expanding the electric transmission and distribution systems • Purchasing nuclear fuel Projected capital requirements for 2013-2017 are: 2013 2014-2017 Total (In millions) Construction expenditures $ 372.8 $ 1,409.1 $ 1,781.9 Dividends on PNMR common stock 52.6 210.3 262.9 Dividends on PNM preferred stock 0.5 2.1 2.6 Total capital requirements $425.9 $1,621.5 $2,047.4 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 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 of $71.9 million estimated to be expended through 2017. The construction expenditures above do not include any amounts related to environmental upgrades at SJGS that ultimately may be required by EPA to address regional haze or expenditures that could be required to replace capacity should environmental control at SJGS involve shutdown of one or more SJGS units. 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.
During the year ended December 31, 2012, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements.
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 2017 and the TNMP Revolving Credit Facility that expires in December 2015. On October 31, 2011, PNMR entered into the PNMR Revolving Credit Facility, which has a financing capacity of $300.0 million, and PNM entered into the PNM Revolving Credit Facility, which has a financing capacity of $400.0 million. The new credit facilities replaced existing facilities. The terms and conditions of the new facilities are substantially similar to the prior facilities and the Company believes the terms and conditions are consistent with those of other investment grade revolving credit facilities in the utility industry. On December 14, 2012, PNMR entered into the PNMR Term Loan Agreement. On December 27, 2012, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement and used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility. Each of these facilities 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.
The revolving credit facilities provide short-term borrowing capacity and 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. Short-term borrowings at PNMR ranged from $14.0 million to $141.0 million during the year ended December 31, 2012 and from $101.0 million to $129.0 million during the three months ended December 31, 2012. PNM short-term borrowings ranged from zero to $168.0 million during the year ended December 31, 2012 and from zero to $35.0 million during the three months ended December 31, 2012. PNMR short-term borrowings ranged from zero to $106.0 million during the year ended December 31, 2011. PNM short-term borrowings ranged from zero to $298.0 million during the year ended A- 40-------------------------------------------------------------------------------- Table of Contents December 31, 2011. There were no borrowings under the TNMP Revolving Credit Facility during 2012 and 2011. At December 31, 2012, average interest rates were 1.96% for the PNMR Revolving Credit Facility, 1.335% for the PNMR Term Loan Agreement, and 1.71% for the PNM Revolving Credit Facility.
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 2013-2017 period. This could include debt refinancing, new debt issuances, and/or new equity.
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 • Conditions in the financial markets • Credit ratings On April 13, 2012, S&P raised the corporate credit rating for PNMR as well as the senior debt ratings for PNMR and TNMP and the preferred stock rating for PNM. S&P changed the outlook to stable for all entities. As of February 22, 2013, ratings on the Company's debt securities were as follows: PNMR PNM TNMP S&P Senior secured * * BBB+ Senior unsecured BB+ BBB- * Preferred stock * BB * Moody's Senior secured * * A3 Senior unsecured Ba1 Baa3 * 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 summary of liquidity arrangements, which do not include the PNMR Term Loan Agreement, as of February 22, 2013 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 Amounts outstanding as of February 22, 2013: Revolving credit facility 24.2 107.7 25.0 156.9 Letters of credit 11.3 3.5 0.3 15.1 Total short term-debt and letters of credit 35.5 111.2 25.3 172.0 Remaining availability as of February 22, 2013 $ 264.5 $ 288.8 $ 49.7 $ 603.0 Invested cash as of February 22, 2013 $ 2.8 $ - $ - $ 2.8 A- 41-------------------------------------------------------------------------------- Table of Contents 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 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.
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.
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.
The EIP line is a 216 mile, 345 kilovolt line with a capacity of 200 MW. 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 of $7.7 million. See Note 16.
The future lease payments shown below for the PVNGS and EIP leases have been reduced by amounts that will be returned to PNM through its ownership in related lessor notes.
PVNGS Units 1&2 EIP Delta Total (In thousands) 2013 $ 27,427 $ - $ 5,956 $ 33,383 2014 32,236 4,267 5,956 42,459 2015 17,082 - 5,956 23,038 2016 3,270 - 5,956 9,226 2017 - - 5,956 5,956 Thereafter - - 15,385 15,385 Total $ 80,015 $ 4,267 $ 45,165 $ 129,447 The above table includes payments under the PVNGS leases through their existing expiration. As discussed in Note 7, PNM gave notice to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. The renewal payments under the PVNGS Unit 1 leases are $16.5 million, which are not included above. The renewal period is yet to be determined, but will be between two and eight years. See Sources of Power in Part I, Item 1, Investments in Note 1, and Note 7 for additional information.
A- 42-------------------------------------------------------------------------------- Table of Contents Commitments and Contractual Obligations The following table sets forth PNMR's long-term contractual obligations as of December 31, 2012. See Note 7 for further details about the Company's significant leases: Payments Due 2018 and Contractual Obligations 2013 2014-2015 2016-2017 Thereafter Total (In thousands) Long-term debt (a) $ 2,530 $ 231,892 $ 57,000 $ 1,385,070 $ 1,676,492 Interest on long-term debt (b) 116,377 227,180 198,033 606,679 1,148,269 Operating leases (c) 44,040 83,525 28,309 94,883 250,757 Transmission reservation payments 13,443 14,859 11,276 19,667 59,245 Coal contracts (d) 61,809 125,687 101,853 - 289,349 Coal mine decommissioning (e) 3,907 1,327 2,928 72,983 81,145 Nuclear decommissioning funding requirements (f) 2,600 5,200 5,200 60,812 73,812 Outsourcing 5,573 7,771 3,629 - 16,973 Pension and retiree medical (g) 64,542 35,719 8,274 - 108,535 Construction expenditures (h) 372,807 827,969 581,114 - 1,781,890 Total (i) $ 687,628 $ 1,561,129 $ 997,616 $ 2,240,094 $ 5,486,467 (a) Represents total long-term debt excluding unamortized discounts of $4.2 million.
(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 their existing expiration.
As discussed in Note 7, PNM gave notice to the lessors under the PVNGS Unit 1 leases in 2013 that PNM would renew the leases. The renewal payments under the PVNGS Unit 1 leases are $16.5 million, which are not included in the above table. The renewal period is yet to be determined, but will be between two and eight years. 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 Investments in Note 1 and Note 7. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.
(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 at the expiration of the lease. See Capital Requirements above and Note 16.
(i) PNMR is unable to reasonably estimate the timing of liability and interest payments for uncertain income tax positions in individual years due to uncertainties in the timing of the effective settlement of tax positions.
Therefore, PNMR's liability of $19.2 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 Energy PPA since there are no minimum payments required under that agreement.
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.
The PNMR Revolving Credit Facility, PNM Revolving Credit Facility, and TNMP Revolving Credit Facility, contain "ratings triggers," for pricing purposes only. If PNMR, PNM, or TNMP is downgraded or upgraded by the ratings agencies, the A- 43-------------------------------------------------------------------------------- Table of Contents result would be an increase or decrease in interest cost. In addition, the revolving credit facilities, as well as the PNMR Term Loan Agreement and TNMP 2011 Term Loan, each contain a covenant requiring the maintenance of debt-to-capital ratios of less 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 Revolving Credit Facility resulting in an acceleration of the repayment of outstanding loans under the PNM Revolving Credit Facility, 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 PNMR Term Loan Agreement also includes a cross-default provision.
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 2012 2011 PNMR common equity 48.9 % 48.3 % Preferred stock of subsidiary 0.3 % 0.3 % Long-term debt 50.8 % 51.4 % Total capitalization 100.0 % 100.0 % PNM PNM common equity 50.5 % 49.7 % Preferred stock 0.5 % 0.5 % Long-term debt 49.0 % 49.8 % Total capitalization 100.0 % 100.0 % TNMP Common equity 59.8 % 59.8 % Long-term debt 40.2 % 40.2 % Total capitalization 100.0 % 100.0 % OTHER ISSUES FACING THE COMPANY Climate Change Issues Background In 2012, PNM's generating plants emitted approximately 6.7 million metric tons of CO2, which comprises the vast majority of its GHG. By comparison, the total GHG in the United States in 2010, the latest year for which EPA has published this data, were approximately 6.8 billion metric tons, of which approximately 5.7 billion metric tons were CO2. According to EPA data, electricity generation accounted for approximately 2.3 billion metric tons, or 40%, of the CO2 emissions.
A- 44-------------------------------------------------------------------------------- Table of Contents PNM has several programs underway to reduce GHG from its generating plants, 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 will be expanding its renewable energy portfolio by constructing 21.5 MW of utility-scale solar generation that will be on-line by the end of the year and has signed a 20 year PPA for the output of a 10 MW geothermal facility to be in service by January 1, 2014. Additionally, PNM has a customer distributed solar generation program that is expected to grow distributed solar from almost 20 MW installed at the end of 2012 to over 44 MW by the end of 2014. Once fully subscribed, the distributed solar programs will reduce PNM's production from fossil-fueled electricity generation by 116 GWh per year. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2012 budget of over $17 million, that PNM estimates saved approximately 71 GWh of electricity in 2012. Over the next 18 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 12,185 GWh of electricity, which will avoid at least 6.1 million metric tons of CO2 based upon projected emissions from PNM's system-wide portfolio with and without these programs. These estimates are subject to change given that it is difficult to accurately estimate 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 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 regularly 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.
Approximately 81.8% of PNM's owned and leased generating capacity at December 31, 2012 consisted of coal or gas-fired generation that produces GHG, all of which is located within the United States. The Company does not anticipate any direct impact from any near-term international accords. 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, including plant performance. For example, if PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. 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. 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. If implemented, shutdown of those units would reduce PNM's GHG. 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 coal-fired generation would be greater than the increase in GHG from replacement with gas-fired generation.
Because of PNM's dependence on fossil-fueled generation, any legislation that imposes a limit or cost on GHG will impact the cost at which electricity is produced. While PNM expects to be entitled to recover that cost through rates, the timing and outcome of proceedings for cost recovery is uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their demand, 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 possible exception of periodic drought conditions. 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 Tribe to help address any water shortages from primary sources. The contract expires on 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 A- 45-------------------------------------------------------------------------------- Table of Contents 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. EPA had indicated in its original Tailoring Rule that it might extend PSD regulation to smaller emission sources.
However, on July 3, 2012, EPA finalized the third phase of the rule by keeping the permitting thresholds where they are. 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 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 emission 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 March 27, 2012, EPA issued its proposed carbon pollution standards for the emission of GHG from new fossil-fueled electric generating units ("EGUs"). The proposed NSPS sets a limit of 1,000 lb CO2/MWh and covers newly constructed fossil-fueled EGUs that are larger than 25 MW. The proposed limit is based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would likely only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule includes an exemption for simple cycle EGUs. However, during the comment period, EPA solicited comments on whether to drop the exemption and instead exempt any fossil-fueled EGU that limits electric generation to one-third of its annual generating capacity. The proposed rule, as written, does not include limits that apply to existing power plants, or proposed plants that already have a complete preconstruction permit and commence construction within 12 months of the issuance of the proposed rule. The proposal is the first NSPS issued for CO2, and although it is limited to new sources, it has potential far-reaching implications for the utility industry. When finalized, the standard could serve as the floor for BACT analysis for PSD permitting for new GHG sources under the Tailoring Rule. The proposed rule was published in the Federal Register on April 13, 2012. EPA accepted comment on the proposed rule through June 25, 2012.
Completion of the proposed NSPS for new EGUs is a prerequisite for EPA to promulgate GHG standards for existing sources. An EPA proposal to establish a GHG NSPS for existing sources is expected sometime in 2013. In setting the standards, EPA has historically used technology-based performance standards on emission rates, but currently there are no GHG control technologies in existence that can provide a basis for an existing source NSPS.
EPA regulation of GHG from large stationary sources will impact PNM's operations due to its reliance on fossil-fueled electric generation. The impact to PNM is unknown because the regulatory requirements, including BACT implications and NSPS requirements, are still developing. Impacts could involve investments in efficiency improvements and/or control technologies at the fossil-fueled generating plants. Currently, there are no commercially viable GHG control technologies although such technologies may become viable in the future. It is also possible that the costs of such improvements or technologies could impact the economic viability of some plants.
Federal Legislation Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in the new Congress are unlikely in 2013, 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 level of emissions allowances allocated and the level that must be purchased, the development of technologies for renewable energy and to reduce emissions, the cost of emissions allowances, the degree to which offsets may be used for compliance, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as with respect to 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 would likely, among other things, result in significant compliance costs, including significant capital expenditures by PNM, and could jeopardize the economic viability of certain generating facilities. See Note 16. In turn, these consequences would lead to increased costs to customers and could 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 demand for electricity. PNM's assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.
A- 46-------------------------------------------------------------------------------- Table of Contents 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 issued an order in June 2007, requiring 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 (Note 17) 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 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 also adopted regulations to directly limit GHG from larger sources, including electric generation units.
However, these regulations were recently repealed. In November 2010, the EIB adopted a regional GHG cap and trade program proposed by the NMED. The NMED GHG program was intended to implement, in New Mexico, the regional cap and trade program developed by the Western Climate Initiative ("WCI) which is an organization formerly comprised of seven western states, including New Mexico, and three Canadian provinces. The NMED GHG regulation would have capped GHG emissions based on a 2011 emission baseline. Thereafter, NMED would grant GHG allowances to covered sources based on their individual emission baseline. The available allowances would decline by 2% each succeeding year requiring sources to either reduce GHG emissions by the requisite amount or purchase emission allowances from a yet-to-be established regional trading market. The required GHG reductions under the NMED program were not to be triggered until the available trading market for GHG allowances consisted of 100 million metric tons or more. New Mexico, by itself, had insufficient regulated GHG emissions to establish the requisite trading market.
PNM and other public utilities and industry groups challenged the NMED GHG cap and trade program in the New Mexico Court of Appeals. During the pendency of these appeals, the EIB agreed to consider a petition for the repeal of the NMED GHG cap and trade regulation. PNM and the other appellants filed a petition to repeal the New Mexico GHG cap and trade regulation, and in February 2012, the EIB voted unanimously to repeal the GHG cap and trade regulation. The NMED supported the repeal of its GHG cap and trade regulation. The repeal of the GHG cap and trade regulation has now been challenged by two environmental advocacy organizations and is currently pending before the New Mexico Court of Appeals.
In a separate rulemaking proceeding filed in December 2008, New Energy Economy ("NEE") petitioned the EIB for the adoption of a regulation that would cap GHG from larger sources such as electric generation units. The EIB adopted the NEE GHG regulation, in a modified form, in December 2010 as a "backstop" to the NMED GHG cap and trade regulation. The effective date of the NEE GHG regulation was delayed until the later of January 1, 2013 or six months after NMED's cap-and-trade regulation described above is no longer in force. Under the NEE GHG regulation, covered sources would have to reduce GHG emissions by 3% per year, subject to a specified cost cap.
The NEE GHG regulation was challenged in the New Mexico Court of Appeals by PNM and the same groups that challenged the NMED cap and trade regulation. Again, during the pendency of the appeals, the EIB agreed to consider a petition for the repeal of the NEE GHG regulation. In March 2012, the EIB voted unanimously to repeal the NEE GHG regulation. The NMED supported the repeal of the NEE GHG regulation. The repeal of the NEE GHG regulation has been challenged in the Court of Appeals by the same environmental organizations that have challenged the repeal of the NMED cap and trade regulation.
The Court of Appeals conditionally dismissed the challenges to the adoption of the NMED GHG cap and trade and NEE GHG regulations because of the repeal of those regulations. The challenges are subject to reinstatement in the event of a successful challenge to the repeal of the NMED GHG cap and trade or NEE GHG regulation and reinstatement of either of those regulations.
At present it is difficult to assess whether the pending challenges to the repeals of the NMED GHG cap and trade regulation and the NEE GHG regulation will be successful. PNM's analysis of these regulations is that both would increase environmental compliance costs for its fossil fueled generation facilities. It appears that New Mexico is reassessing whether a single-state or regional approach to the regulation of GHG is appropriate public policy. New Mexico is no longer a member-participant in the WCI, but remains involved as an observer.
However, PNM cannot rule out future state legislative or regulatory initiatives to regulate GHGs.
A- 47-------------------------------------------------------------------------------- Table of Contents 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 asks 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. There has been no further action on this matter and it remains pending before the NMPRC.
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 there is no specific time frame in which action must be taken or a docket will be 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. The Company monitors and often submits comments taking a position in such notices and rulemaking dockets or may join in larger group responses. The Company often cannot determine the full impact of a proposed rule and policy change until the final determination is made by FERC and the Company 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 they have delayed the implementation of portions of the MOD-029 methodology for "Flow Limited" paths 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 and are waiting for the request to be processed through NERC's standards development.
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 WestConnect participants. On December 17, 2012, the WestConnect participants filed responses to the issues raised by the intervenors. FERC has not responded to the filing and protests raised by intervenors. A second compliance filing will be made in April 2013 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. Although several of the rules required to implement the legislation have not yet been finalized, 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.
A- 48-------------------------------------------------------------------------------- Table of Contents Other Matters See Notes 16 and 17 for a discussion of commitments and contingencies and rate and regulatory matters. See Note 20 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 historical sales recorded in the billing system, taking into account weather impacts. The method is consistent with the approach to normalization employed for rate case billing determinants and the load forecast. To the extent the estimated amount differs from the amount subsequently billed, revenues will be affected.
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.
The Company 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.
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. Note 22 contains information on the impairment testing performed by the Company on goodwill and intangible assets. No impairments were indicated in the Company's annual goodwill testing, which was performed as of April 1, 2012. 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 impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units and determination of the fair value of each reporting unit. A discounted cash flow methodology is primarily used to estimate the fair value of each 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 each reporting unit, 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, A- 49-------------------------------------------------------------------------------- Table of Contents and the borrowing rate appropriate for each reporting unit. The Company considers available market-based information and may consult with third parties to help determine the WACC. The 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 each 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 WACCs and cash flow projections utilized in the 2012 testing appropriately reflected the fair value of each reporting unit.
Since any cash flow projection contains uncertainty, the Company adjusted the WACCs 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, 2012, the fair value of the PNM reporting unit, which had goodwill of $51.6 million, exceeded its carrying value by approximately 15%. The 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.
PNMR had an investment in Optim Energy, which was accounted for using the equity method of accounting up to September 23, 2011. On September 23, 2011, PNMR's ownership in Optim Energy was reduced from 50% to 1%. Beginning in 2009 and continuing throughout 2010, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. These factors were indicators of impairment that required an impairment analysis to be performed by PNMR of its investment in Optim Energy as of December 31, 2010. PNMR's analysis indicated that its entire investment in Optim Energy was impaired and PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31, 2010, resulting in a pre-tax loss of $188.2 million in 2010. Accordingly and because PNMR had no further financial commitment to Optim Energy, no additional impairment analysis was performed in 2012. See Note 21.
Decommissioning 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. 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. PVNGS Unit 3 is excluded from PNM's retail rates while PVNGS Units 1 and 2 are included. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-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. Asset retirement obligations and nuclear decommissioning costs are discussed in Note 15.
In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation as well as the costs for final reclamation of the coal mines. The reclamation costs are based on site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for 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.
A- 50-------------------------------------------------------------------------------- Table of Contents Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimate technique.
Changes in the assumptions used in the fair value determinations could have significant impacts. See Note 8.
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 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. See Note 12.
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 when determining the proper accrual, however the actual outcomes can vary from any amounts accrued.
See Note 16.
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. 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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