Edgar Filing: PNM RESOURCES INC

PNM 12.31.2013 10-K

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_________________________________________________

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2013



Commission File Number	Names of Registrants, State of Incorporation, Address and Telephone Number	I.R.S. Employer Identification No.
001-32462	PNM Resources, Inc. (A New Mexico Corporation) 414 Silver Ave. SW Albuquerque, New Mexico 87102-3289 (505) 241-2700	85-0468296
001-06986	Public Service Company of New Mexico (A New Mexico Corporation) 414 Silver Ave. SW Albuquerque, New Mexico 87102-3289 (505) 241-2700	85-0019030
002-97230	Texas-New Mexico Power Company (A Texas Corporation) 577 N. Garden Ridge Blvd. Lewisville, Texas 75067 (972) 420-4189	75-0204070

Securities Registered Pursuant To Section 12(b) Of The Act:



Registrant	Title of Each Class	Name of Each Exchange on Which Registered
PNM Resources, Inc.	Common Stock, no par value	New York Stock Exchange

Securities Registered Pursuant To Section 12(g) Of The Act:



Registrant		Title of Each Class
Public Service Company of New Mexico		1965 Series, 4.58% Cumulative Preferred Stock
		($100 stated value without sinking fund)

Indicate by check mark whether each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.



PNM Resources, Inc. (“PNMR”)	YES ü	NO
Public Service Company of New Mexico (“PNM”)	YES	NO ü
Texas-New Mexico Power Company (“TNMP”)	YES	NO ü

Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



PNMR	YES	NO ü
PNM	YES	NO ü
TNMP	YES ü	NO

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Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.



PNMR	YES ü	NO
PNM	YES ü	NO
TNMP	YES	NO ü

(NOTE: As a voluntary filer, not subject to the filing requirements, TNMP filed all reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



PNMR	YES ü	NO
PNM	YES ü	NO
TNMP	YES ü	NO

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10–K or any amendment to this Form 10–K.

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act).



	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller Reporting Company
PNMR	ü		__
PNM	__		ü
TNMP	__		ü

Indicate by check mark whether the registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act). YES NO ü

As of February 21, 2014, shares of common stock outstanding were:



PNMR	79,653,624
PNM	39,117,799
TNMP	6,358

On June 28, 2013, the aggregate market value of the voting common stock held by non-affiliates of PNMR as computed by reference to the New York Stock Exchange composite transaction closing price of $22.19 per share reported by The Wall Street Journal, was $1,767,513,917. PNM and TNMP have no common stock held by non-affiliates.

PNM AND TNMP MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (I) (1) (a) AND (b) OF FORM 10-K AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION (I) (2).

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following document are incorporated by reference into Part III of this report:

Proxy Statement to be filed by PNMR with the SEC pursuant to Regulation 14A relating to the annual meeting of stockholders of PNMR to be held on May 15, 2014.

This combined Form 10-K is separately filed by PNMR, PNM, and TNMP. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. When this Form 10-K is incorporated by reference into any filing with the SEC made by PNMR, PNM, or TNMP, as a registrant, the portions of this Form 10-K that relate to each other registrant are not incorporated by reference therein.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX



			Page
GLOSSARY			iv
PART I
ITEM 1. BUSINESS			A- 1
THE COMPANY			A- 1
WEBSITES			A- 1
OPERATIONS AND REGULATION			A- 2
REGULATED OPERATIONS
PNM			A- 2
TNMP			A- 4
EXIT FROM COMPETITIVE BUSINESSES
First Choice			A- 5
Optim Energy			A- 6
CORPORATE AND OTHER			A- 6
SOURCES OF POWER			A- 6
FUEL AND WATER SUPPLY			A- 9
ENVIRONMENTAL MATTERS			A- 11
COMPETITION			A- 11
EMPLOYEES			A- 11
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS			A- 12
SECURITIES ACT DISCLAIMER			A- 13
ITEM 1A. RISK FACTORS			A- 13
ITEM 1B. UNRESOLVED STAFF COMMENTS			A- 20
ITEM 2. PROPERTIES			A- 20
ITEM 3. LEGAL PROCEEDINGS			A- 21
ITEM 4. MINE SAFETY DISCLOSURES			A- 21
SUPPLEMENTAL ITEM – EXECUTIVE OFFICERS OF PNM RESOURCES, INC.			A- 22
PART II
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER			A- 23
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA			A- 24
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			A- 28
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			A- 57
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			B- 1
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING			C- 1
AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES			C- 1
ITEM 9B. OTHER INFORMATION			C- 2
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERANCE			C- 2
ITEM 11. EXECUTIVE COMPENSATION			C- 2
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			C- 2
AND RELATED STOCKHOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR			C- 2
INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			C- 2
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			D-0
SIGNATURES			E-1

iii

Table of Contents

GLOSSARY



Definitions:
ABO		Accumulated Benefit Obligation
Afton		Afton Generating Station
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMS		Advanced Meter System
AOCI		Accumulated Other Comprehensive Income
APBO		Accumulated Postretirement Benefit Obligation
APS		Arizona Public Service Company, which is the operator and a co-owner of PVNGS and Four Corners
ARO		Asset Retirement Obligation
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
BHP		BHP Billiton, Ltd, the parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
CAA		Clean Air Act
Cascade		Cascade Investment, L.L.C.
CCB		Coal Combustion Byproducts
CCN		Certificate of Convenience and Necessity
CO₂		Carbon Dioxide
CTC		Competition Transition Charge
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
Delta		Delta-Person Generating Station
DOE		United States Department of Energy
DOI		United States Department of Interior
ECJV		ECJV Holdings, LLC
EGU		Electric Generating Unit
EIB		New Mexico Environmental Improvement Board
EIP		Eastern Interconnection Project
EPA		United States Environmental Protection Agency
EPE		El Paso Electric
ERCOT		Electric Reliability Council of Texas
ESA		Endangered Species Act
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
First Choice		FCP Enterprises, Inc. and Subsidiaries
Four Corners		Four Corners Power Plant
FPL		FPL Energy New Mexico Wind, LLC
FPPAC		Fuel and Purchased Power Adjustment Clause
GAAP		Generally Accepted Accounting Principles in the United States of America
Gallup		City of Gallup, New Mexico
GHG		Greenhouse Gas Emissions
GWh		Gigawatt hours
IBEW		International Brotherhood of Electrical Workers
IRP		Integrated Resource Plan
IRS		Internal Revenue Service

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KW		Kilowatt
KWh		Kilowatt Hour
LIBOR		London Interbank Offered Rate
Lightning Dock Geothermal		Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant
Lordsburg		Lordsburg Generating Station
Luna		Luna Energy Facility
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU		Million BTUs
Moody’s		Moody’s Investor Services, Inc.
MW		Megawatt
MWh		Megawatt Hour
NAAQS		National Ambient Air Quality Standards
Navajo Acts		Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT		Nuclear Decommissioning Trusts for PVNGS
NEC		Navopache Electric Cooperative, Inc.
NERC		North American Electric Reliability Council
New Mexico Wind		New Mexico Wind Energy Center
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMPRC		New Mexico Public Regulation Commission
NOx		Nitrogen Oxides
NOI		Notice of Inquiry
NOPR		Notice of Proposed Rulemaking
NRC		United States Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NSR		New Source Review
OCI		Other Comprehensive Income
OPEB		Other Post Employment Benefits
Optim Energy		Optim Energy, LLC, a limited liability company, formerly known as EnergyCo, LLC
OSM		United States Office of Surface Mining Reclamation and Enforcement
PBO		Projected Benefit Obligation
PCRBs		Pollution Control Revenue Bonds
PG&E		Pacific Gas and Electric Co.
PNM		Public Service Company of New Mexico and Subsidiaries
PNM New Mexico Credit Facility		PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility		PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNM Term Loan Agreement		PNM’s $75.0 Million Unsecured Term Loan Facility
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR Revolving Credit Facility		PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement		PNMR’s $100.0 Million Unsecured Term Loan Facility
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas

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PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REA		New Mexico’s Renewable Energy Act of 2004
REC		Renewable Energy Certificates
Red Mesa Wind		Red Mesa Wind Energy Center
REP		Retail Electricity Provider
RMC		Risk Management Committee
RPS		Renewable Energy Portfolio Standard
SCE		Southern California Edison Company
SCPPA		Southern California Public Power Authority
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SJCC		San Juan Coal Company
SJGS		San Juan Generating Station
SJPPA		San Juan Project Participation Agreement
SNCR		Selective Non-Catalytic Reduction
SO₂		Sulfur Dioxide
SPS		Southwestern Public Service Company
SRP		Salt River Project
S&P		Standard and Poor’s Ratings Services
TCEQ		Texas Commission on Environmental Quality
TECA		Texas Electric Choice Act
Tenth Circuit		United States Court of Appeals for the Tenth Circuit
TNMP		Texas-New Mexico Power Company and Subsidiaries
TNMP 2011 Term Loan Agreement		TNMP’s $50.0 Million Secured Term Loan
TNMP Revolving Credit Facility		TNMP’s $75.0 Million Secured Revolving Credit Facility
TNP		TNP Enterprises, Inc. and Subsidiaries
Tri-State		Tri-State Generation and Transmission Association, Inc.
Tucson		Tucson Electric Power Company
UAMPS		Utah Associated Municipal Power System
Valencia		Valencia Energy Facility
VaR		Value at Risk
WACC		Weighted Average Cost of Capital
WEG		WildEarth Guardians
WSPP		Western Systems Power Pool

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PART I


ITEM 1.	BUSINESS

THE COMPANY

Overview

PNMR is an investor-owned holding company of utilities providing electricity and electric services in New Mexico and Texas. With PNMR’s exit from its unregulated businesses in 2011, PNMR is now positioned as a holding company of regulated electric utilities 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

PNMR’s success in accomplishing these strategic goals is highly dependent on continued favorable regulatory treatment for its regulated utilities. Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. In Texas, 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. In 2011, PNM and TNMP completed general rate proceedings before their state regulators. In August 2012, PNM implemented a rate rider to collect renewable energy procurement costs that are not otherwise being collected in rates. On January 2, 2013, FERC approved a settlement for an increase in rates PNM charges its transmission customers and, in December 2012, PNM filed for an additional increase in rates charged to those customers based on a formula rate methodology, which is pending before FERC. In April 2013, PNM received FERC approval of a settlement for an increase in rates charged to NEC, its largest firm-requirements wholesale customer. PNM also reached agreement with Gallup, its second largest firm-requirements wholesale customer, to increase rates and extend the contract through June 30, 2014. TNMP received PUCT approvals to increase rates to reflect increases in its transmission cost of service in September 2012, March 2013, and September 2013. Additional information about rate filings is provided in Operations and Regulation below and in Note 17.

PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM. PNMR was incorporated in the State of New Mexico in 2000.

Other Information

These filings for PNMR, PNM, and TNMP include disclosures for each entity. For discussion purposes, this report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such. A reference to “MD&A” in this report refers to Part II, Item 7. - Management’s Discussion and Analysis of Financial Condition and Results of Operations. A reference to a “Note” refers to the accompanying Notes to Consolidated Financial Statements.

Financial information relating to amounts of revenue, net income, and total assets of reportable segments is contained in MD&A and Note 2.

WEBSITES

The PNMR website, www.pnmresources.com, is an important source of Company information. New or updated information for public access is routinely posted. PNMR encourages analysts, investors, and other interested parties to register on the website to automatically receive Company information by e-mail. This information includes news releases, notices of webcasts, and filings with the SEC. Participants can unsubscribe at any time and will not receive information that was not requested.

Our Internet addresses are:


•	PNMR: www.pnmresources.com


•	PNM: www.pnm.com


•	TNMP: www.tnmp.com

The contents of these websites are not a part of this Form 10-K. The SEC filings of PNMR, PNM, and TNMP, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are accessible free of charge on the PNMR website as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports are also available in print upon request from PNMR free of charge.

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Also available on the Company’s website at www.pnmresources.com/investors/governance.cfm and in print upon request from any shareholder are our:


•	Corporate Governance Principles


•	Code of Ethics (Do the Right Thing-Principles of Business Conduct)


•	Charters of the Audit and Ethics Committee, Nominating and Governance Committee, Compensation and Human Resources Committee, and Finance Committee

The Company will post amendments to or waivers from its code of ethics (to the extent applicable to the Company’s executive officers and directors) on its website.

OPERATIONS AND REGULATION

Regulated Operations

PNM

PNM is an electric utility that provides electric generation, transmission, and distribution service to its rate-regulated customers. In New Mexico, the utility’s retail electric service territory covers a large area of north central New Mexico, including the cities of Albuquerque, Rio Rancho, and Santa Fe, and certain areas of southern New Mexico. PNM also provides electricity to firm-requirements wholesale customers in New Mexico and Arizona. Service to retail electric customers is subject to the jurisdiction of the NMPRC. Service to wholesale customers is regulated by FERC. Regulation encompasses the utility’s electric rates, service, accounting, issuances of securities, construction of major new generation, types of generation resources, transmission and distribution facilities, and other matters.

Other services provided by PNM include transmission services to third parties as well as the generation and sale of electricity into the wholesale market, which services are regulated by FERC. The utility owns or leases transmission lines, interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. The largest retail electric customer served by PNM accounted for 3.8% of the utility’s revenues for the year ended December 31, 2013. PNM was incorporated in the State of New Mexico in 1917.

Rate Proceedings

Customer rates for retail electric service are set by the NMPRC. PNM made a general rate case filing in June 2010. On August 8, 2011, the NMPRC issued a final order modifying a stipulation reached by PNM and other parties in this case. The modified stipulation provides:


•	$72.1 million increase in annual non-fuel revenues for all New Mexico retail customers, implemented August 21, 2011


•	Customers formerly served by TNMP prior to its acquisition by PNMR (“PNM South”) being covered by the same FPPAC utilized for other retail customers of PNM (“PNM North”)


•	Subject to further NMPRC approvals, recovery of costs associated with NMPRC approved renewable energy procurement plans through a rate rider


•	Limit on annual recovery of costs for fuel, renewable energy, and energy efficiency, with recovery of additional amounts deferred for collection to future periods

As permitted by the above NMPRC order, PNM filed an application in January 2012 for a rate rider to collect costs for renewable energy procurements incurred after December 31, 2010 that are not otherwise being collected in rates. These costs include the procurement of solar RECs from customers, wind resource procurements, and the revenue requirements for PNM-owned solar PV facilities and a solar battery storage demonstration project. On August 14, 2012, the NMPRC approved the rider, which PNM implemented on August 20, 2012. The rider will terminate upon a final order in PNM’s next general rate case unless that order authorizes a continuation of the rider. Amounts that can be collected under the rider were capped at $18.0 million in 2012 and $24.6 million in 2013. Any amounts above the caps were to be deferred for future recovery without carrying costs. Collections under the rider during 2012 and 2013 were below the cap. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operation, exceeded 10.5%, it would refund to customers during May through December 2014 the amount over 10.5%. PNM’s earned return on jurisdictional equity in 2013 did not exceed 10.5%.

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PNM has entered into firm-requirements wholesale contracts to provide electricity to various customers. These contracts contain both capacity charges and energy charges. Capacity charges are monthly payments for a commitment of resources to service the contract requirements. Energy charges are payments based on the amount of electricity delivered to the customer and are intended to compensate for the variable costs incurred to provide the energy. PNM’s firm-requirements demand was 114 MW in 2013, and is expected, based solely on existing contracts and reflecting that the current contract with Gallup expires in 2014, to be 104 MW in 2014, 69 MW in 2015, and 69 MW in 2016. No firm-requirements customer of PNM accounted for more than 2.5% of PNM’s revenues for the year ended December 31, 2013.

In September 2011, PNM filed with FERC to increase rates for electric service and ancillary services provided to NEC, PNM’s largest firm-requirements wholesale customer. PNM also requested a traditional FPPAC and full recovery of certain third-party transmission charges. FERC issued an order allowing the increased rates to be collected beginning April 14, 2012, subject to refund. The parties agreed to a settlement providing for an increase in rates of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. FERC approved the settlement in April 2013. PNM provides both energy and power services to Gallup, its second largest firm-requirements wholesale customer, under an electric service agreement that was to expire June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase rates by $3.1 million during the term of the amended agreement. In June 2013, FERC approved the amended agreement. In response to Gallup’s request for proposals, PNM submitted a proposal for long term power supply in November 2013. On January 13, 2014, PNM was notified that it was not the highest ranked proposal. Gallup has stated they are negotiating a contract with the top-ranked bidder. See Results of Operations in MD&A and Note 17. PNM is unable to predict the outcome of this matter.

In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission rates for all of PNM’s wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM’s transmission system to transmit power at the wholesale level. The proposed rates were implemented on June 1, 2011, subject to refund. On January 2, 2013, FERC approved a settlement among the parties providing for an increase in transmission service revenues of $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC’s approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. The rate increase does not impact PNM’s retail customers.

In December 2012, PNM filed a notice with FERC to increase its wholesale electric transmission rates for all of its transmission customers. The filing represents a formula based rate as contemplated by the approved settlement in the case described above. The proposed increase of $1.3 million, as updated, went into effect, subject to refund, on August 2, 2013. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

Operational Information

Weather-normalized retail electric KWh sales decreased by 1.8% in 2013 and 0.7% in 2012. The system peak demands for retail and firm-requirements customers increased year over year. The system peak demands were as follows:

System Peak Demands



	2013	2012	2011
	(Megawatts)
Summer	2,008	1,948	1,938
Winter	1,576	1,523	1,709

PNM holds long-term, non-exclusive franchise agreements for its electric retail operations, with varying expiration dates. These franchise agreements allow the utility to access public rights-of-way for placement of its electric facilities. Franchise agreements have expired in some areas PNM serves, including Albuquerque, Rio Rancho, and Santa Fe. Because PNM remains obligated under New Mexico state law to provide service to customers in these areas, the expirations should not have a material adverse impact. The Albuquerque, Rio Rancho, and Santa Fe metropolitan areas accounted for 48.6%, 11.0%, and 9.7% of PNM’s 2013 revenues and no other franchise area represents more than 5%. Although PNM is not required to collect or pay franchise fees in some areas it serves, the utility continues to collect and pay such fees in certain parts of its service territory, including Albuquerque, Rio Rancho, and Santa Fe. As discussed in Note 16, the County Commission of Bernalillo County, New Mexico passed an ordinance on January 28, 2014 that would require PNM to enter into a use agreement and pay a yet to be determined fee as a condition for installing, maintaining, and operating facilities on county rights-of-way. PNM and other utilities have filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. If the challenge to the ordinance is unsuccessful, PNM believes any fees paid pursuant to the ordinance

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would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter.

PNM owns or leases 3,189 circuit miles of electric transmission lines that interconnect with other utilities in New Mexico, Arizona, Colorado, Texas, and Utah. There has been little development of new transmission facilities in recent years. Therefore, most of the capacity on PNM’s transmission system is fully committed during peak hours, with very little to no additional access available on a firm commitment basis. These factors result in physical constraints on the system and limit the ability to wheel power into PNM’s service area from outside of New Mexico.

PNM also generates and sells electricity into the wholesale market. Because PNM’s 134 MW share of Unit 3 at PVNGS currently is excluded from retail rates, that unit’s power is being sold in the wholesale market. PNM has contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. PNM has established fixed rates for all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015. As discussed in Note 16, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource to serve New Mexico retail customers as part of the revised plan to comply with the regional haze requirements of the CAA. Beyond the PVNGS contracts, PNM also engages in activities to optimize its existing jurisdictional assets and long-term purchase power agreements through spot market, hour ahead, day ahead, week ahead, and other sales of any excess generation not required to fulfill retail load and contractual commitments. Gains from these sales, other than those from PVNGS Unit 3, are credited to retail customers through the FPPAC.

Use of Future Test Year

Under New Mexico law, the NMPRC must set rates using the test period, including a future test year, that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. In addition, the NMPRC must include certain construction work in progress (“CWIP”) for environmental improvement, generation, and transmission projects in rate base. These provisions are designed to promote more timely recovery of reasonable costs of providing utility service.

The use of a future test year should help PNM mitigate the adverse effects of regulatory lag, which is inherent when using a historical test year. Accordingly, the utility’s earnings should more closely reflect the rate of return allowed by the NMPRC. PNMR believes that achieving earnings that approximate its allowed rate of return is an important factor in attracting equity investors, as well as being considered favorably by credit rating agencies and financial analysts.

PNM anticipates filing a request for a general rate increase with the NMPRC by the end of 2014 that would likely be based on a 2016 future test year. As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that exist in the forecasting process. These include forecasts of both operating and capital expenditures that necessitate reliance on many assumptions concerning future conditions and operating results. In the rate making process, PNM’s assumptions are subject to challenge by regulators and intervenors who may assert different interpretations or assumptions.

Renewable Portfolio Standard

The REA was enacted to encourage the development of renewable energy in New Mexico. The act establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% by 2011, 15% by 2015, and 20% by 2020. The act provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities recovery of costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. PNM files required renewable energy plans with the NMPRC annually and makes procurements consistent with the plans approved by the NMPRC. See Note 17.

TNMP

TNMP is a regulated utility operating in Texas. TNMP’s predecessor was organized in 1925. TNMP is incorporated in the State of Texas.

TNMP provides transmission and distribution services in Texas under the provisions of TECA and the Texas Public Utility Regulatory Act. TNMP is subject to traditional cost-of-service regulation with respect to rates and service under the jurisdiction of the PUCT and certain municipalities. Because its transmission and distribution activities are solely within ERCOT, TNMP is not subject to traditional rate regulation by FERC. TNMP serves a market of small to medium sized communities, most of which have populations of less than 50,000. TNMP is the exclusive provider of transmission and distribution services in most areas it serves.

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TNMP’s service territory consists of three non-contiguous areas. One portion of this territory extends from Lewisville, which is approximately 10 miles north of the Dallas-Fort Worth International Airport, eastward to municipalities near the Red River, and to communities north, west, and south of Fort Worth. The second portion of its service territory includes the area along the Texas Gulf Coast between Houston and Galveston, and the third portion includes areas of far west Texas between Midland and El Paso. ERCOT is the independent system operator that is responsible for maintaining reliable operations for the bulk electric power supply system in its region.

TNMP provides transmission and distribution services at regulated rates to various REPs that, in turn, provide retail electric service to consumers within TNMP’s service area. TNMP experienced annualized increases in weather-normalized retail KWh sales of 2.6% in 2013 and 3.7% in 2012. As of December 31, 2013, 97 active REPs receive transmission and distribution services from TNMP. The acquirer of First Choice, including the former First Choice operations, accounted for 17% of TNMP’s revenues in 2013. Two other unaffiliated customers of TNMP accounted for operating revenues of 16% and 10% in 2013. No other customer accounted for more than 10% of revenues.

Regulatory Activities

In August 2010, TNMP filed with the PUCT for a general rate increase. On January 27, 2011, the PUCT approved a stipulation that settles the case. Key components of the settlement were:


•	A revenue increase of $10.25 million, effective February 1, 2011


•	A return on equity of 10.125%


•	A target debt-equity capital structure of 55%/45%

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of smart meters began in September 2011 and is scheduled to be completed over a 5-year period.

The PUCT approved interim adjustments to TNMP’s transmission rates of $2.5 million on September 27, 2012, $2.9 million on March 20, 2013, and $2.8 million on September 17, 2013.

Franchise Agreements

TNMP holds long-term, non-exclusive franchise agreements for its electric transmission and distribution services. These agreements have varying expiration dates and some have expired. TNMP intends to negotiate and execute new or amended franchise agreements with municipalities where the agreements have expired or will be expiring. Since TNMP is the exclusive provider of transmission and distribution services in most areas that it serves, the need to renew or renegotiate franchise agreements should not have a material adverse impact. TNMP also earns revenues from service provided to facilities in its service area that lie outside the territorial jurisdiction of the municipalities with which TNMP has franchise agreements.

Exit from Competitive Businesses

First Choice

As discussed in Note 3, PNMR completed the sale of First Choice on November 1, 2011 receiving $270.0 million, plus $59.3 million for estimated working capital. The latter amount was subject to adjustment based on the actual amounts of certain components of working capital at October 31, 2011. PNMR recognized a pre-tax gain of $174.9 million on the sale in 2011. The parties could not agree on the working capital amount and, in accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012 resulting in an additional pre-tax gain of $1.0 million in 2012. PNMR used the net proceeds from the sale of First Choice to repurchase some of PNMR’s outstanding debt and equity and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility.

First Choice, operating as a certified REP in ERCOT, provided electricity to residential, small commercial and governmental customers. First Choice focused its competitive customer acquisition efforts in major Texas metropolitan areas open to electric choice within ERCOT, including Dallas-Fort Worth, Houston, Corpus Christi, and McAllen-Harlingen. Although First Choice was regulated in certain respects by the PUCT, its business was not subject to traditional rate of return regulation. Rates were negotiated by First Choice with each customer. No specific provisions existed for the recovery of First Choice’s purchased power costs and changes in those costs affected operating results.

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During the period it was a subsidiary of PNMR, First Choice’s operating results were pressured by several factors. Due to the competitive nature of the Texas market, First Choice, similar to other REPs, experienced significant turnover in its customer base, which along with depressed economic conditions resulted in significant increases in the levels of uncollectible accounts and bad debt expense. First Choice’s load fluctuated due to customer additions and losses, changes in customer usage, and seasonality of weather. First Choice experienced increased sales and operating revenues during the summer months as a result of increased air conditioner usage. First Choice monitored and revised its load forecast to account for changing customer loads and entered into hedging arrangements to cover forecasted sales.

Optim Energy

In January 2007, PNMR and ECJV, a wholly owned subsidiary of Cascade, which until late in 2011 was a large PNMR shareholder, created Optim Energy to serve expanding energy markets, principally the areas of Texas covered by ERCOT. Optim Energy’s business consisted of development, operation, and ownership of diverse generation assets, complemented by wholesale marketing to optimize those assets. PNMR and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company. Optim Energy had interests in three electric generating resources located within the ERCOT area.

Beginning in 2009, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices. In response to those adverse conditions, Optim Energy changed its strategy to focus on utilizing cash flow from operations to reduce debt. Optim Energy also concentrated on optimizing generation assets as a stand-alone independent power producer.

As discussed in Note 20, PNMR determined its investment in Optim Energy was fully impaired at December 31, 2010 and reduced the carrying value of the investment to zero. PNMR, ECJV, and Cascade entered into agreements on September 23, 2011, whereby Optim Energy was restructured and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR’s ownership in Optim Energy being reduced 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 through September 23, 2011 and used the cost method thereafter. In accordance with GAAP, PNMR did not record income or losses associated with its investment in Optim Energy in 2011.

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. PNMR Services Company provides corporate services through shared services agreements to PNMR and all of PNMR’s business units, including PNM and TNMP. These services are charged and billed at cost on a monthly basis to the business units. PNMR Services Company also provided corporate services under shared services agreements with First Choice and Optim Energy through their disposition and for limited periods thereafter under transition services agreements.

SOURCES OF POWER

PNM

Generation Capacity

As of December 31, 2013, the total net generation capacity of facilities owned or leased by PNM was 2,368 MW. PNM also obtains 204 MW of power under a long-term PPA for the power produced by New Mexico Wind.

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PNM’s capacity in electric generating facilities, which are owned, leased, or under PPAs, in commercial service as of December 31, 2013 is:



			Generation
			Capacity
Type	Name	Location	(MW)
Coal	SJGS	Waterflow, New Mexico	783
Coal	Four Corners	Fruitland, New Mexico	200
Gas	Reeves Station	Albuquerque, New Mexico	154
Gas	Afton (combined cycle)	La Mesa, New Mexico	230
Gas	Lordsburg	Lordsburg, New Mexico	80
Gas	Luna (combined cycle)	Deming, New Mexico	185
Gas/Oil	Delta	Albuquerque, New Mexico	132
Gas	Valencia	Belen, New Mexico	158
Nuclear	PVNGS	Wintersburg, Arizona	402
Solar	PNM-owned solar	Eight sites in New Mexico	44
Wind	New Mexico Wind	House, New Mexico	204
			2,572

Fossil‑Fueled Plants

SJGS consists of four units operated by PNM. Units 1, 2, 3, and 4 at SJGS have net rated capacities of 340 MW, 340 MW, 497 MW and 507 MW. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri‑State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by MSR Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the potential shutdown of Units 2 and 3 on December 31, 2017 and the restructuring of the ownership interests in SJGS.

Four Corners Units 4 and 5 are 13% owned by PNM. Units 4 and 5 at Four Corners are jointly owned with APS, SRP, Tucson, and EPE and are operated by APS. PNM has no ownership interest in Four Corners Units 1, 2, or 3, which were shutdown by APS on December 30, 2013. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a PSD permit from EPA to install SCR technology at Four Corners. PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to PNM and the other Four Corners owners. See Note 16 for additional information about Four Corners.

PNM owns 100% of Reeves, Afton, and Lordsburg and one-third of Luna. The remaining interests in Luna are owned equally by Tucson and Freeport McMoRan. PNM is entitled to the energy and capacity of Delta under a PPA that is deemed to be an operating lease. PNM has a PPA that entitles it to the entire output of Valencia. Valencia is a variable interest entity and is consolidated by PNM as required by GAAP. Therefore, Valencia is reflected in the above table as if it were owned. Reeves, Lordsburg, Delta, and Valencia are used primarily for peaking power and transmission support. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta, and Valencia, including the potential purchase of 50% of Valencia.

Nuclear Plant

PNM is participating in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA, and the Department of Water and Power of the City of Los Angeles. PNM is entitled to 10.2% of the power and energy generated by PVNGS. PNM has ownership interests of 2.3% in Unit 1, 4.6% in Unit 2, and 10.2% in Unit 3 and has leasehold interests of 7.9% in Unit 1 and 5.6% in Unit 2. The lease payments for the leased portions of PVNGS are recovered through retail rates approved by the NMPRC. See Note 7 for additional information concerning the PVNGS leases, including notices given in 2013 to the lessors under the PVNGS Unit 1 leases and one of the PVNGS Unit 2 leases that PNM would renew those leases and notices given in 2014 that PNM would exercise its fair market purchase option for the other

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three Unit 2 leases. On February 25, 2014, PNM and one of the Unit 2 lessors agreed on the price to be paid upon PNM’s exercise of the fair market value purchase option. See Note 16 for information on other PVNGS matters, including PNM’s proposal to include PVNGS Unit 3 as a jurisdictional resource to serve New Mexico retail customers.

On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced tsunamis that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Following these events, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. In March 2012, the NRC issued the first regulatory requirements based on the recommendations of the task force. With respect to PVNGS, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation. The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, PNM cannot predict the financial or operational impacts on PVNGS; however, the NRC has directed nuclear power plants to implement the first tier of its recommendations. In response to these recommendations, PVNGS expects to spend approximately $100 million for capital enhancements to the plant over the next several years. PNM’s share of these enhancements would be 10.2%, substantially all of which are included in PNM’s current projection of capital expenditures.

Solar

In 2011, PNM completed its first major utility-owned renewable energy project aggregating 22 MW when five utility-scale solar facilities in New Mexico went online. In addition to these facilities, PNM completed its solar-storage demonstration project in Albuquerque, which has a generation capacity of 0.5 MW and is included in the above table. In 2013, PNM completed the installation of an additional 21.5 MW of utility-owned solar capacity at four sites, including expansion of capacity at two of the existing sites. In July 2013, PNM filed its 2014 renewable energy procurement that includes the construction by December 31, 2014 of an additional 23 MW of PNM-owned solar PV facilities at three additional sites.

Plant Operating Statistics

Equivalent availability of PNM’s major base-load generating stations were:



Plant	Operator	2013	2012	2011
SJGS	PNM	77.6%	81.7%	86.9%
Four Corners	APS	72.9%	83.5%	81.5%
PVNGS	APS	89.4%	90.6%	89.1%

Joint Projects

SJGS, PVNGS, Four Corners, and Luna are joint projects each owned or leased by several different entities. Some participants in the joint projects are investor-owned entities, while others are municipally or co-operatively owned. Furthermore, participants in SJGS and Four Corners may have varying percentage interests in different generating units within the project. The primary operating or participation agreements for the joint projects expire in 2016 for Four Corners, 2022 for SJGS, and 2027 for PVNGS. In addition, SJGS and Four Corners are coal-fired generating plants that obtain their coal requirements from mines near the plants. The agreement for coal supply expires 2017 for SJGS. In late December 2013, the coal supply arrangement for Four Corners was extended through 2031. As described above, Four Corners is situated on land under a lease from the Navajo Nation. Portions of PNM’s interests in PVNGS Units 1 and 2 are through leases that expire in 2015 and 2016, but contain certain fixed-rate renewal and fair market value purchase options. See Nuclear Plant above and Note 7 regarding PNM’s actions related to these options. Several of the participants in the joint projects are located in California. There are legislative and regulatory mandates in California that may prohibit utilities from entering into new, or extending existing, arrangements for coal-fired generation. It is also possible that the participants in the joint projects have changed circumstances and objectives from those existing at the time of becoming participants. The status of these joint projects is further complicated by the uncertainty surrounding the form of potential legislation and/or regulation of CCBs,GHG, and other air emissions, as well as the impacts of the costs of compliance and operational viability of all or certain units within the joint projects. It is unclear how these factors will enter into discussion and negotiations concerning the status of the joint projects as the expiration of basic operational agreements approaches. PNM can provide no assurance that its participation in the joint projects will continue in the manner that currently exists. See Note 16 for a discussion of potential restructuring of SJGS ownership and developments with respect to Four Corners.

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PPAs

In addition to generating its own power, PNM purchases power under long-term PPAs. PNM also purchases power in the forward, day-ahead, and real-time markets.

In 2002, PNM entered into an agreement with FPL to develop New Mexico Wind. PNM began receiving power from the project in June 2003. FPL owns and operates New Mexico Wind, which consists of 136 wind-powered turbines having an aggregate capacity of 204 MW on a site in eastern New Mexico. PNM has a contract to purchase all the power and RECs generated by New Mexico Wind for 25 years. The NMPRC has approved a voluntary tariff that allows PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from New Mexico Wind is used to service load under the voluntary tariff and as part of PNM’s electric supply mix for meeting retail load.

PNM’s 2013 renewable energy procurement plan includes a 20-year agreement to purchase energy and RECs from the Lightning Dock Geothermal facility built near Lordsburg. The facility, which is the first geothermal project for the PNM system, began providing limited power to PNM on January 1, 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity.

In June 2013, PNM entered into a 20 year PPA with Red Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC, to purchase all of the power and RECs produced by Red Mesa Wind beginning on January 1, 2015. Red Mesa Wind, LLC owns and operates the facility, which consists of 64 wind-powered turbines having an aggregate capacity of 102 MW on a site west of Albuquerque.

A summary of purchased power, excluding Delta and Valencia, but including power purchased under long-term contracts that have expired by their terms, is as follows:



	Year Ended December 31,
	2013		2012		2011
Purchased under long-term PPAs
MWh	490,539		546,321		794,867
Cost per MWh	$	27.25	$	27.25	$	29.93
Other purchased power
Total MWh	1,061,514		948,911		988,564
Cost per MWh	$	35.64	$	27.30	$	31.47

TNMP

TNMP provides only transmission and distribution services and does not sell power.

First Choice

First Choice bought electricity and entered into hedging arrangements to purchase quantities of power to match the supply obligations to customers that were under fixed price contracts. Power was purchased long-term in the over-the-counter market or using futures. In the short term, hedges were adjusted to load changes by buying and selling power in the over-the-counter market or ERCOT day-ahead market.

FUEL AND WATER SUPPLY

PNM

The percentages of PNM’s generation of electricity (on the basis of KWh), including Valencia and Delta, fueled by coal, nuclear fuel, and gas and oil, and the average costs to PNM of those fuels per MMBTU were as follows:



	Coal				Nuclear				Gas and Oil
	Percent of Generation		Average Cost		Percent of Generation		Average Cost		Percent of Generation		Average Cost
2013	56.8	%	$	2.62	30.4	%	$	0.88	12.2	%	$	4.12
2012	59.2	%	$	2.99	31.3	%	$	0.88	9.0	%	$	3.25
2011	61.8	%	$	2.79	29.7	%	$	0.80	8.4	%	$	4.47

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In 2013, 2012, and 2011, 0.6%, 0.5%, and 0.1% of PNM’s generation was from utility owned solar, which has no fuel cost. The generation mix for 2014 is expected to be 61.4% coal, 28.9% nuclear, 8.8% gas and oil, and 0.9% utility owned solar. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits, and the generally adequate supply of nuclear fuel, PNM believes that adequate sources of fuel are available for its generating stations into the foreseeable future. See Sources of Power - PNM - PPAs for information concerning the cost of purchased power.

Coal

The coal supply contract that provides fuel for SJGS expires in 2017. Coal supply has not been arranged for periods after the existing contract expires. PNM believes there is adequate availability of coal resources to continue to operate SJGS although an extended or new contract could result in higher prices. In late December 2013, the expiration date of the coal supply contract for Four Corners was extended from 2016 to 2031. PNM estimates fuel costs for Four Corners will increase approximately 26% during the extension period. See Note 16 for additional information about PNM’s coal supply.

Natural Gas

The natural gas used as fuel for the electric generating plants is procured on the open market and delivered by third party transportation providers. The supply of natural gas can be subject to disruptions due to extreme weather events and/or pipeline or facility outages. PNM’s natural gas plants are generally used as peaking resources that are highly relied upon during periods of extreme weather, which also may be the times natural gas has the highest demand from other users.

Nuclear Fuel and Waste

PNM is one of several participants in PVNGS. The PVNGS participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The PVNGS participants have contracted for all of PVNGS’s requirements for uranium concentrates through 2017, 90% of its requirements for 2018, and 45% of its requirements through 2020. The participants have contracted for all of PVNGS’s conversion services through 2016, 95% of its requirements in 2017 and 2018, and 45% of its requirements through 2020. The participants have contracted for all of PVNGS’s enrichment services through 2014 and 95%-100% of its requirements through 2020. All of PVNGS’s fuel assembly fabrication services are contracted through 2016.

The Nuclear Waste Policy Act of 1982 required the DOE to begin to accept, transport, and dispose of spent nuclear fuel and high level waste generated by the nation’s nuclear power plants by 1998. The DOE’s obligations are reflected in a contract with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. APS (on behalf of itself and the other PVNGS participants) filed a lawsuit for DOE’s breach in the United States Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.2 million in damages to the PVNGS participants for costs incurred through December 2006. APS filed a subsequent lawsuit against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007 through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. See Note 16.

The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE’s authority to withdraw the Yucca Mountain construction authorization application. None of these lawsuits has been conclusively decided by the courts. However, in August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.

All spent nuclear fuel from PVNGS is being stored on-site. PVNGS has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license periods, which end in November 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the extended license periods, which end in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, the PVNGS participants will evaluate alternative storage solutions. These may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the extended license periods.

Water Supply

See Note 16 for information about PNM’s water supply.

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ENVIRONMENTAL MATTERS

Electric utilities are subject to stringent laws and regulations for protection of the environment by local, state, federal, and tribal authorities. In addition, PVNGS is subject to the jurisdiction of the NRC, which has the authority to issue permits and licenses and to regulate nuclear facilities in order to protect the health and safety of the public from radioactive hazards and to conduct environmental reviews pursuant to the National Environmental Policy Act. The liabilities under these laws and regulations can be material. In some instances, liabilities may be imposed without regard to fault, or may be imposed for past acts, whether or not such acts were lawful at the time they occurred. The construction expenditure projection includes environmental upgrades at SJGS and Four Corners aggregating $10.0 million in 2014 and $150.3 million in 2015 through 2018, as discussed in Note 16. See MD&A - Other Issues Facing the Company - Climate Change Issues for information on GHG. In addition, Note 16 contains information related to the following matters, incorporated in this item by reference:


•	PVNGS Decommissioning Funding


•	Nuclear Spent Fuel and Waste Disposal


•	Environmental Matters under the caption “The Clean Air Act”


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Endangered Species Act


•	Cooling Water Intake Structures


•	Effluent Limitation Guidelines


•	Santa Fe Generating Station


•	Environmental Matters under the caption “Coal Combustion Byproducts Waste Disposal”


•	Hazardous Air Pollutants (“HAPs”) Rulemaking

COMPETITION

Regulated utilities are generally not subject to competition from other utilities in areas that are under the jurisdiction of state regulatory commissions. In New Mexico, PNM does not have direct competition for services provided to its retail electric customers. In Texas, TNMP is not currently in any direct retail competition with any other regulated electric utility. However, PNM and TNMP are subject to customer conservation and energy efficiency activities as well as initiatives to utilize alternative energy sources, including self-generation, or otherwise bypass the PNM and TNMP systems.

PNM is subject to varying degrees of competition in certain territories adjacent to or within the areas it serves. This competition comes from other utilities in its region as well as rural electric cooperatives and municipal utilities. PNM is involved in the generation and sale of electricity into the wholesale market. It is subject to competition from regional utilities and merchant power suppliers with similar opportunities to generate and sell energy at market-based prices and larger trading entities that do not own or operate generating assets.

EMPLOYEES

The following table sets forth the number of employees of PNMR, PNM, and TNMP as of December 31, 2013:



	PNMR	PNM	TNMP
Corporate ⁽¹⁾	446	—	—
PNM	1,127	1,127	—
TNMP	351	—	351
Total	1,924	1,127	351

(1)Represents employees of PNMR Services Company.

As of December 31, 2013, PNM had 614 employees in its power plant and operations areas that are currently covered by a collective bargaining agreement with the IBEW Local 611 that was entered into in July 2012 and expires April 30, 2015.

On March 25, 2013, a petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for utility workers. On April 12, 2013, a second petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for meter technicians, who were not included in the original petition. Approximately 200 employees were covered by the petitions. Elections to determine whether the IBEW would represent the employees were held in May 2013. The employees voted to unionize through both petitions and contract negotiations have begun.

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Subsequently, on June 25, 2013, a third petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to include a group of three relay technicians, who were not included in the original petition. In August 2013, the relay technicians voted to unionize and contract negotiations have begun. As of December 31, 2013, TNMP had 192 employees represented by IBEW Local 66. The parties are still in negotiations on a collective bargaining agreement.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events or PNMR’s, PNM’s, or TNMP’s expectations, projections, estimates, intentions, goals, targets, and strategies are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates. PNMR, PNM, and TNMP assume no obligation to update this information.

Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM, and TNMP caution readers not to place undue reliance on these statements. PNMR’s, PNM’s, and TNMP’s business, financial condition, cash flows, and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:


•	The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including recovery of the net book value of SJGS Units 2 and 3 at the date of their proposed early retirement as contemplated in the revised SIP to comply with the regional haze provisions of the CAA


•	The ability of the Company to successfully forecast and manage its operating and capital expenditures


•	State and federal regulation or legislation relating to environmental matters, including the approval of the revised SIP for SJGS’s compliance with the CAA, the resultant costs of compliance, and other impacts on the operations and economic viability of PNM’s generating plants


•	The impacts on the electricity usage of the Company’s customers due to performance of state, regional, and national economies and mandatory energy efficiency measures, weather, seasonality, and other changes in supply and demand


•	State and federal regulatory, legislative, and judicial decisions and actions on ratemaking, tax, and other matters


•	Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects resulting from the scheduled expiration of the operational agreements for the projects and fuel supply for SJGS, including potential restructuring and approval issues at SJGS and Four Corners necessary for operational and environmental compliance matters


•	Uncertainty regarding the requirements and related costs of decommissioning power plants and coal mines supplying certain power plants, as well as the ability to recover decommissioning costs from customers


•	The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, extreme weather conditions, terrorism, and cybersecurity breaches


•	Variability of prices and volatility and liquidity in the wholesale power and natural gas markets


•	Changes in price and availability of fuel and water supplies, including the ability of the mines supplying coal to PNM’s coal-fired generating units and the companies involved in supplying nuclear fuel to provide adequate quantities of fuel


•	The risks associated with completion of generation, transmission, distribution, and other projects


•	Regulatory, financial, and operational risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainties


•	The risk that reliability standards regarding available transmission capacity and other FERC rulemakings may negatively impact the operation of PNM’s transmission system


•	The Company’s ability to access the financial markets, including disruptions in the credit markets, actions by ratings agencies, and fluctuations in interest rates


•	The potential unavailability of cash from PNMR’s subsidiaries due to regulatory, statutory, or contractual restrictions


•	The impacts of decreases in the values of marketable equity securities maintained to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits


•	Commodity and counterparty credit risk transactions and the effectiveness of risk management


•	The outcome of legal proceedings, including the extent of insurance coverage


•	Changes in applicable accounting principles

For information about the risks associated with the use of derivative financial instruments see Part II, Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

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SECURITIES ACT DISCLAIMER

Certain securities described in this report have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be reoffered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933 and applicable state securities laws. This Form 10-K does not constitute an offer to sell or the solicitation of an offer to buy any securities.

ITEM 1A. RISK FACTORS

The business and financial results of PNMR, PNM, and TNMP are subject to a number of risks and uncertainties, including those set forth below and in MD&A, Note 16, and Note 17. TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP’s service territories. References to customers in the risk factors discussed below also encompass the customers of these REPs who are the ultimate consumers of electricity transmitted and distributed through TNMP’s facilities.

Regulatory Factors

The profitability of PNMR’s utilities depends on being able to recover their costs through regulated rates and earn a fair return on invested capital. PNM and TNMP are facing a period of significant capital expenditures. While increased capital investments and other costs are placing upward pressure on rates, energy efficiency and a sluggish New Mexico economy are reducing usage by customers.

The rates PNM charges its customers are regulated by the NMPRC and FERC. TNMP is regulated by the PUCT. The Company is in a period requiring significant capital investment and is projecting total construction expenditures for the years 2014-2018 to be $2,267.2 million. See Note 14. The Company anticipates a trend toward increasing costs, for which it will have to seek regulatory recovery. These costs include or are related to:


•	Environmental compliance expenditures


•	The proposed early retirement of SJGS Units 2 and 3 as part of a revised plan to comply with the regional haze provisions of the CAA, including recovery of their net book value at the date of retirement and costs of generation capacity to replace those units


•	New asset construction related to generation, transmission, and distribution systems necessary to provide electric service


•	The regulatory mandate to acquire power from renewable resources


•	Increased regulation related to nuclear safety


•	Fuel costs


•	Increased interest costs to finance capital investments


•	Depreciation

At the same time the Company’s costs are increasing, there are factors placing downward pressures on the demand for power, thereby reducing load growth and customer usage in the Company’s service territories. These factors include:


•	Changing customer behaviors, including increased emphasis on energy efficiency measures and utilization of alternative sources of power


•	Reduced new sources of demand


•	Reductions in costs of energy efficient technology


•	Unpredictable weather patterns


•	Adverse economic conditions

In 2013 and 2012, PNM experienced annualized decreases in weather-normalized, retail sales of 1.8% and 0.7%. The sales decreases reflect a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery. There is no clear indication regarding the future of New Mexico’s economy. Encouraging signs such as growth in the housing industry, increased tax revenue in the Albuquerque metropolitan area, and unemployment rates below the national average are contrasted by indicators such as flat population growth and low job growth.

The combination of costs increasing relatively rapidly and the slowing of customer usage places upward pressure on the per unit prices that must be charged by the Company to recover its costs. This upward pressure on unit prices could result in additional efforts by customers to reduce consumption through energy efficiency or to pursue self-generation or other alternative

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sources of power. Without timely cost recovery and the authorization to earn a reasonable return on invested capital, the Company’s liquidity and results of operations could be negatively impacted.

Under New Mexico law, utilities may propose the use of a future test year in establishing rates. As with any forward looking financial information, a future test year presents challenges that are inherent in the forecasting process. Forecasts of both operating and capital expenditures necessitate reliance on many assumptions concerning future conditions and operating results. Accordingly, if PNM chooses to request rates based on a future test year, but cannot successfully support it, cash flows and results of operations may be negatively impacted. This could result from not being able to withstand challenges from regulators and intervenors regarding the utility’s capability to make reasonable forecasts.

The coal supply contract that provides fuel for SJGS expires in 2017. Coal supply has not been arranged for periods after the existing contract expires. It is possible that an extended contract with the existing supplier or a new contract for coal from an alternative source could result in higher prices. In late December 2013, the expiration date of the coal supply contract for Four Corners was extended from 2016 to 2031. PNM estimates fuel costs for Four Corners will increase approximately 26% during the extension period. PNM currently recovers the cost of fuel for its generation facilities through its FPPAC. Although PNM believes costs under new or extended coal supply agreements would continue to be recovered through the FPPAC, there can be no assurance that full recovery would be allowed.

PNMR’s utilities are subject to numerous federal, state, and local environmental laws and regulations that may significantly limit or affect their operations and financial results.

Compliance with federal, state, and local environmental laws and regulations, including those addressing climate change, air quality, CCBs, discharges of wastewater originating from fly ash and bottom ash handling facilities, cooling water, and other matters, may result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emission obligations. These costs could include remediation, containment, civil liability, and monitoring expenses. PNMR, PNM, and TNMP cannot predict how they would be affected if existing environmental laws and regulations were to be revised or reinterpreted, or if new environmental statutes and rules were to be adopted. See Note 16 and the Climate Change Issues subsection of the Other Issues Facing the Company section of MD&A.

EPA has issued its BART determinations for both SJGS and Four Corners under the program to address regional haze in the “four corners” area, which would reduce the levels of NOx emitted at both plants. Significant capital expenditures would be required for the installation of control technology at both generating stations and operating costs would increase. On February 15, 2013, PNM, NMED, and EPA agreed to pursue a revised plan regarding SJGS, which is discussed in Note 16. PNM is taking actions to effectuate the revised plan, but there is no assurance that it will approved by EPA or that required approvals will be obtained from the NMPRC. In addition, the other participants in SJGS must approve the necessary expenditures required by the plan. As discussed below, certain of the participants in SJGS desire to exit their ownership and the participants are attempting to negotiate a restructuring of ownership. If all of these approvals are not obtained and appropriate relief cannot be obtained from EPA, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers, which could increase costs and negatively impact earnings unless the increased costs are allowed to be recovered from customers.

EPA, environmental advocacy groups, other organizations, and some other federal and state agencies are predicted to focus considerable attention on GHG from power generation facilities, including the role of those facilities in climate change. PNM depends on fossil-fueled generation for a significant share of its electricity. Therefore, it could be exposed to possible future GHG regulations imposed by New Mexico and/or the federal government. For example, as discussed in the Climate Change Issues subsection of the Other Issues Facing the Company section of MD&A, EPA re-proposed its GHG NSPS rule for new sources in September 2013 and is scheduled to issue a draft of a GHG NSPS for modified and existing EGU’s in June 2014. Any such proposals that become regulations could result in additional operating restrictions on facilities and increased generation and compliance costs.

CCBs from the operation of SJGS are currently being used in the reclamation of a surface coal mine. These CCBs consist of fly ash, bottom ash, and gypsum. Any new regulation that would affect the reclamation process, including CCBs being classified as hazardous waste by EPA, could significantly increase the costs of the disposal of CCBs and the costs of mine reclamation.

A regulatory body may identify a site requiring environmental cleanup and designate PNM or TNMP as a responsible party. There is also uncertainty in quantifying exposure under environmental laws that impose joint and several liability on all potentially responsible parties. Failure to comply with environmental laws and regulations, even if caused by factors beyond PNM’s or TNMP’s control, may result in the assessment of civil or criminal penalties and fines.

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PNMR and its operating subsidiaries may underestimate the costs of environmental compliance, liabilities, and litigation due to the uncertainty inherent in these matters. Although there is uncertainty about the timing and form of regulations regarding climate change, CCBs, and other power plant emissions, such regulations could have a material impact on operations. The California entities that are participants in SJGS have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS, including those related to environmental compliance. Therefore, the California participants, along with one other participant, have expressed the intent to exit their ownership in SJGS no later than December 31, 2017. Negotiations have begun among the SJGS participants regarding arrangements that would allow the exit of ownership by those participants desiring to do so, including addressing continuing liabilities for reclamation, decommissioning, environmental, and other matters, but no agreements have been reached. It is possible that failure to reach a satisfactory agreement to restructure SJGS ownership, requirements to comply with the final BART determinations, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, the adequacy and timeliness of cost recovery mechanisms, and other business considerations, could jeopardize the ability of individual participants to continue participation in SJGS, as well as the economic viability of the plant. Timely regulatory recovery of costs associated with any environmental-related regulations would be needed to maintain a strong financial and operational profile. The above factors could adversely affect the Company’s business, financial position, results of operations, and liquidity.

PNMR, PNM, and TNMP are subject to complex government regulation unrelated to the environment, which may have a negative impact on their businesses, financial position and results of operations.

To operate their businesses, PNMR, PNM, and TNMP are required to have numerous permits and approvals from a variety of regulatory agencies. Regulatory bodies with jurisdiction over the utilities include the NMPRC, NMED, PUCT, TCEQ, ERCOT, FERC, NRC, EPA, and NERC. Oversight by these agencies cover many aspects of the Company’s utility operations including: location, construction, and operation of facilities; the purchase of power under long-term contracts; conditions of service; the issuance of securities; and rates charged to customers.

FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. A rule issued in 2011 revised the determination of total transmission capability under the reliability standards for transmission systems. The order could potentially reduce the capacity of the transmission facilities used to deliver power from PNM’s generation resources to its customers. Such reductions could require PNM to acquire additional transmission rights or assets, which could involve substantial investments and a significant amount of time to accomplish.

PNMR and its subsidiaries are unable to predict the impact on their business and operating results from future actions of any agency regulating the Company. Changes in existing regulations or the adoption of new ones could result in additional expenses and/or changes in business operations. In turn, operating results could be adversely impacted.

Operational Factors

Customer electricity usage could be reduced by increases in prices charged and other factors. This could result in underutilization of PNM’s generating capacity, as well as the capacities of PNM’s and TNMP’s transmission and distribution systems. Should this occur, operating and capital costs might not be fully recovered, and financial performance could be negatively impacted.

A number of factors influence customers’ electricity purchases. These factors include, but are not limited to:


•	Rates charged by PNM and TNMP


•	Rates charged by REPs utilizing TNMP’s facilities to deliver power


•	Energy efficiency initiatives


•	Availability and cost of alternative sources of power


•	National, regional, or local economic conditions

These factors and others may prompt customers to institute additional energy efficiency measures or take other actions that would result in lower power consumption. If customers bypass or underutilize the Company’s facilities through self-generation, through renewable or other energy resources, technological change, or other measures, our revenues would be negatively impacted.

PNM’s and TNMP’s service territories include several military bases and federally funded national laboratories, as well as large industrial customers that have significant direct and indirect impacts on the local economies where they operate. The Company does not directly provide service to any of the military bases or national laboratories, but does provide service to large

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industrial customers. The Company’s business could be hurt from the impacts on the local economies associated with these customer groups, as well as directly from the large industrial customers, for a number of reasons, including:


•	Federally-mandated base closures or significant curtailment of the activities at the bases or national laboratories


•	Closure of industrial facilities or significant curtailment of their activities

Another factor that could negatively impact the Company is that initiatives are periodically undertaken in various localities to municipalize or otherwise take over Company facilities. If any such municipalization initiative is successful, the result could be a material reduction in the usage of the Company’s facilities, a reduction in rate base, and reduced earnings.

Should any of the above factors result in the Company’s facilities being underutilized, the Company’s financial position, operational results, and cash flows could be significantly impacted.

Costs of decommissioning, remediation, and restoration of nuclear and fossil-fueled power plants, as well as related coal mines, could exceed the estimates of PNMR and PNM, which could negatively impact results of operations and liquidity.

PNM has interests in a nuclear power plant, two coal-fired power plants, and several natural gas-fired power plants. PNM is obligated to pay for the costs of decommissioning its share of the power plants. PNM is also obligated to pay for its share of the costs of decommissioning the mines that supply coal to the coal-fired power plants. Likewise, other owners or participants are responsible for their shares of the decommissioning obligations and it is important to PNM that those parties fulfill their obligations. Rates charged by PNM to its customers, as approved by the NMPRC, include a provision for recovery of certain costs of decommissioning, remediation, and restoration. The NMPRC has established a cap on the amount of decommissioning costs for the surface coal mines that may be recovered from customers. PNM records estimated liabilities for its share of the legal obligations for decommissioning and reclamation. These estimates include many assumptions about future events and are inherently imprecise. In the event any of these costs exceed current estimates, results of operations will be negatively impacted.

The financial performance of PNMR, PNM, and TNMP may be adversely affected if power plants and transmission and distribution systems do not operate reliably and efficiently.

The Company’s financial performance depends on the successful operation of PNM’s generation assets, as well as the transmission and distribution systems of PNM and TNMP. Unscheduled or longer than expected maintenance outages, breakdown or failure of equipment or processes due to aging infrastructure, temporary or permanent shutdowns to achieve environmental compliance, other performance problems with the electric generation assets, severe weather conditions, accidents and other catastrophic events, acts of war or terrorism, disruptions in the supply and delivery of fuel and water supplies, and other factors could result in PNM’s load requirements being larger than available system generation capacity. Assured supplies of water are important for PNM’s generating plants. Water in the southwestern United States is limited and there are conflicting claims regarding water rights. In addition, the “four corners” region where PNM’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies. In addition, unplanned outages of generating units and extensions of scheduled outages occur from time to time and are an inherent risk of the Company’s business. If these were to occur, PNM would be required to purchase electricity in either the wholesale market or spot market at the then-current market price. There can be no assurance that sufficient electricity would be available at reasonable prices, or available at all. The failure of transmission or distribution facilities may also affect PNM’s and TNMP’s ability to deliver power. These potential generation, distribution, and transmission problems, and any service interruptions related to them, could result in lost revenues and additional costs.

PNMR, PNM, and TNMP are subject to information security breaches and risks of unauthorized access to their information and operational technology systems as well as physical threats to assets.

The Company faces the risk of physical and cyber attacks, both threatened and actual, against generation facilities, transmission and distribution infrastructure used to transport power, and information technology systems and network infrastructure, which could negatively impact the ability of the Company to generate, transport, and deliver power, or otherwise operate facilities in the most efficient manner or at all.

The Company functions in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure, some of which are deemed to be critical infrastructure under NERC guidelines. Certain of the Company’s systems are interconnected with external networks. In the regular course of business, the utilities handle a range of sensitive security and customer information. PNM and TNMP are subject to the rules of various agencies concerning safeguarding and maintaining the confidentiality of this information.

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In the event a party desires to disrupt the bulk power or transmission systems in the United States, the Company’s computer and operating systems could be subject to physical or cyber attack. Although the Company has implemented security measures, critical infrastructure, including information and operational technology systems, are vulnerable to disability, failures, or unauthorized access. A successful physical or cyber attack or other similar failure of the systems could impact the reliability of PNM’s generation and PNM’s and TNMP’s transmission and distribution systems, including the possible unauthorized shutdown of facilities. Such an event could lead to significant disruptions of business operations, including the Company’s ability to generate, transport, and deliver power to serve customers, to bill customers, and to process other financial information. A major physical or cyber incident could lead to increased regulatory oversight, litigation, fines, other remedial action, and reputational damage. The costs incurred to investigate and remediate a physical or cyber security attack could be significant. If the Company’s systems were to fail or be breached and not recovered in a timely way, critical business functions could be impaired and sensitive or confidential data could be compromised. A physical or cyber attack on the Company’s critical infrastructure could have a material adverse impact on the operations and financial condition of PNMR, PNM, and TNMP.

There are inherent risks in the ownership and operation of nuclear facilities.

PNM has a 10.2% undivided interest in PVNGS, including interests in Units 1 and 2 held under leases. PVNGS represents 17.0% of PNM’s total owned and leased generating capacity. PVNGS is subject to environmental, health, and financial risks, including, but not limited to:


•	The ability to obtain adequate supplies of nuclear fuel and water


•	The ability to dispose of spent nuclear fuel


•	Decommissioning of the plant


•	Securing the facilities against possible terrorist attacks


•	Unscheduled outages due to equipment failures

PNM maintains trust funds designed to provide adequate financial resources for decommissioning at the end of the expected life of the PVNGS units. However, if the units are decommissioned before their planned date, these funds may prove to be insufficient. PNM also has external insurance coverage to minimize its financial exposure to some risks. However, it is possible that liabilities associated with nuclear operations could exceed the amount of insurance coverage. See Note 16.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generation facilities, including PVNGS. As a result of the March 2011 earthquake and tsunamis that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for nuclear power plants in the United States. Additionally, the NRC has been performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation. PNM cannot predict when or if the NRC will complete its formal actions as a result of its review. As a result of the Fukushima Daiichi event, however, the NRC has directed nuclear power plants to implement the first tier its recommendations. In response to these recommendations, PVNGS expects to spend approximately $100 million for capital enhancements to the plant over the next several years of which PNM’s share of these enhancements would be 10.2%, substantially all of which are included in PNM’s current projection of capital expenditures. PNM cannot predict whether these amounts will increase or whether additional financial and/or operational requirements on PVNGS may be imposed.

In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increased inspection regime that could ultimately result in the shut-down of a unit or civil penalties, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. Increased costs resulting from penalties, a heightened level of scrutiny, and/or implementation of plans to achieve compliance with NRC requirements could adversely affect the financial condition, results of operations, and cash flows of PNMR and PNM.

Demand for power could exceed supply capacity, resulting in increased costs for purchasing capacity in the open market or building additional generation facilities.

PNM is obligated to supply power to retail customers and certain wholesale customers. At peak times, power demand could exceed PNM’s available generation capacity. Market or competitive forces may require PNM to purchase capacity on the open market or build additional generation capabilities. Regulators or market conditions may not permit PNM to pass all of these purchases or construction costs on to customers. If that occurs, PNM may not be able to fully recover these costs. Or, there may

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be a lag between when costs are incurred and when regulators permit recovery in customers’ rates. These situations could have negative impacts on results of operations and cash flows.

General Economic and Weather Factors

General economic conditions of the nation and/or specific areas can affect the Company’s customers and suppliers. Economic recession or downturn may result in decreased consumption by customers and increased bad debt expense, and could also negatively impact suppliers, all of which could negatively impact the Company.

Economic activity is a key factor in PNMR subsidiaries’ performance. Decreased economic activity can lead to declines in energy consumption, which could adversely affect future revenues, earnings, and growth. Higher unemployment rates, both in the Company’s service territories and nationwide, could result in commercial customers ceasing operations and lower levels of income for residential customers. These customers might then be unable to pay their bills on time, which could increase bad debt expense and negatively impact results of operations and cash flows. Economic conditions also impact the supply and/or cost of commodities and materials needed to construct or acquire utility assets or make necessary repairs.

The operating results of PNMR and its operating subsidiaries fluctuate on a seasonal and quarterly basis as well as being affected by weather conditions, including regional drought.

Electric generation, transmission, and distribution are generally seasonal businesses that vary with the demand for power. With power consumption typically peaking during the hot summer months, revenues traditionally peak during that period. As a result, quarterly operating results of PNMR and its operating subsidiaries vary throughout the year. In addition, PNMR and its operating subsidiaries have historically had lower revenues resulting in lower earnings when weather conditions are milder. Unusually mild weather in the future could reduce the revenues, net earnings, and cash flows of the companies.

Drought conditions in New Mexico, especially in the “four corners” region, where SJGS and Four Corners are located, may affect the water supply for PNM’s generating plants. If inadequate precipitation occurs in the watershed that supplies that region, PNM may have to decrease generation at these plants. This would require PNM to purchase power to serve customers and/or reduce the ability to sell excess power on the wholesale market and reduce revenues. Drought conditions or actions taken by regulators or legislators could limit PNM’s supply of water, which would adversely impact PNM’s and PNMR’s business. Although PNM has in place supplemental contracts and voluntary shortage sharing agreements with tribes and other water users in the “four corners” region, PNM cannot be certain these contracts will be enforceable in the event of a major drought or that it will be able to renew these contracts in the future.

TNMP’s service areas are exposed to extreme weather, including high winds, drought, flooding, and periodic hurricanes. Extreme weather conditions, particularly high winds and severe thunderstorms, also occur periodically in PNM’s service areas. These severe weather events can physically damage TNMP’s and PNM’s owned facilities. Any such occurrence both disrupts the ability to deliver energy and increases costs. Extreme weather can also reduce customers’ usage and demand for energy. These factors could negatively impact results of operations and cash flows.

Financial Factors

PNMR may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay dividends or distributions to PNMR.

PNMR is a holding company and has no operations of its own. PNMR’s ability to meet its financial obligations and to pay dividends on its common stock primarily depends on the net income and cash flows of PNM and TNMP and their capacity to pay upstream dividends or distributions. Prior to providing funds to PNMR, PNM and TNMP have financial and regulatory obligations that must be satisfied, including among others, debt service and, in the case of PNM, preferred stock dividends.

The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC has also restricted PNM from paying dividends in any year, as determined on a rolling four-quarter basis, in excess of net earnings without prior NMPRC approval. PNM is permitted to pay dividends to PNMR from prior equity contributions made by PNMR. Additionally, PNM has various financial covenants that limit the transfer of assets, through dividends or other means.

Further, the ability of PNMR to declare dividends depends upon:


•	The extent to which cash flows will support dividends


•	The Company’s financial circumstances and performance

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•	NMPRC’s and PUCT’s decisions in various regulatory cases currently pending and which may be docketed in the future


•	Conditions imposed by the NMPRC or PUCT


•	The effect of federal regulatory decisions and legislative acts


•	Economic conditions in the United States and in the Company’s service areas


•	Future growth plans and the related capital requirements


•	Other business considerations

Disruption in the credit and capital markets may impact the Company’s growth strategy and ability to raise capital.

PNMR and its subsidiaries rely on access to both short-term and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations, including energy infrastructure investments and new projects. In general, the Company relies on its short-term credit facilities as the initial source to finance construction expenditures. This results in increased borrowings under the facilities over time. The Company is currently projecting total construction expenditures for the years 2014-2018 to be $2,267.2 million. If PNMR or its operating subsidiaries are not able to access capital at competitive rates, or at all, PNMR’s ability to finance capital requirements and implement its strategy will be limited. Disruptions in the credit markets, which could negatively impact the Company’s access to capital, could be caused by:


•	An economic recession


•	Declines in the health of the banking sector generally, and the failure of specific banks who are parties to the Company’s credit facilities


•	Deterioration in the overall health of the utility industry


•	The bankruptcy of an unrelated energy company


•	War, terrorist attacks or threatened attacks

If the Company’s cash flow and credit and capital resources are insufficient to fund capital expenditure plans, the Company may be forced to delay important capital investments, sell assets, seek additional equity or debt capital, or restructure debt. In addition, insufficient cash flows and capital resources may result in reductions of credit ratings. This could negatively impact the Company’s ability to incur additional indebtedness on acceptable terms and would result in an increase in the interest rates applicable under the Company’s credit facilities. The Company’s cash flow and capital resources may be insufficient to pay interest and principal on debt in the future. If that should occur, the Company’s capital raising or debt restructuring measures may be unsuccessful or inadequate to meet scheduled debt service obligations. This could cause the Company to default on its obligations and further impair liquidity.

Reduction in credit ratings or changing rating agency requirements could materially and adversely affect the Company’s growth, strategy, business, financial position, results of operations, and liquidity.

PNMR, PNM, and TNMP cannot be sure that any of their current ratings will remain in effect for any given period of time or that a rating will not be put under review for a downgrade, lowered, or withdrawn entirely by a rating agency. Downgrades or changing requirements could result in increased borrowing costs due to higher interest rates in future financings, a smaller potential pool of investors, and decreased funding sources. Such conditions also could require the provision of additional support in the form of letters of credit and cash or other collateral to various counterparties.

Declines in values of marketable securities held in trust funds for pension and other postretirement benefits and in the NDT could result in sustained increases in costs and funding requirements for those obligations, which may affect operational results.

The Company targets 21% of its pension trust funds and 70% of its trust funds for other postretirement benefits to be invested in marketable equity securities. Over one-half of funds held in the NDT are typically invested in marketable equity securities. Declines in market values could result in increased funding of the trusts as well as the recognition of losses as impairments for the NDT and additional expense for the benefit plans.

Impairments of goodwill and long-lived assets of PNMR, PNM, and TNMP could adversely affect the Company’s business, financial position, liquidity, and results of operations.

PNMR, PNM, and TNMP annually evaluate their recorded goodwill for impairment. They also assess long-lived assets whenever indicators of impairment exist. Factors that affect the long-term value of these assets as well as other economic and market conditions could result in impairments. Significant impairments could adversely affect the Company’s business, financial position, liquidity, and results of operations.

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PNM’s PVNGS leases describe certain events, including “Events of Loss” and “Deemed Loss Events”, the occurrence of which could require PNM to take ownership of the underlying assets and pay the lessors for the assets.

The “Events of Loss” generally relate to casualties, accidents, and other events at PVNGS, including the occurrence of specified nuclear events, which would severely adversely affect the ability of the operating agent, APS, to operate, and the ability of PNM to earn a return on its interests in PVNGS. The “Deemed Loss Events” consist primarily of legal and regulatory changes (such as issuance by the NRC of specified violation orders, changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). PNM believes that the probability of such “Events of Loss” or “Deemed Loss Events” occurring is remote for the following reasons: (1) to a large extent, prevention of “Events of Loss” and some “Deemed Loss Events” is within the control of the PVNGS participants through the general PVNGS operational and safety oversight process; and (2) other “Deemed Loss Events” would involve a significant change in current law and policy. PNM is unaware of any proposals pending or being considered for introduction in Congress, or in any state legislative or regulatory body that, if adopted, would cause any of those events. See Note 7.

Governance Factors

Provisions of PNMR’s organizational documents, as well as several other statutory and regulatory factors, will limit another party’s ability to acquire PNMR and could deprive PNMR’s shareholders of the opportunity to receive a takeover premium for shares of PNMR’s common stock.

PNMR’s restated articles of incorporation and by-laws include a number of provisions that may have the effect of discouraging persons from acquiring large blocks of PNMR’s common stock, or delaying or preventing a change in control of

PNMR. The material provisions that may have such an effect include:


•	Authorization for the Board to issue PNMR’s preferred stock in series and to fix rights and preferences of the series (including, among other things, voting rights and preferences with respect to dividends and other matters)


•	Advance notice procedures with respect to any proposal other than those adopted or recommended by the Board


•	Provisions specifying that only a majority of the Board, the chairman of the Board, the chief executive officer, or holders of at least one-tenth of all of PNMR’s shares entitled to vote may call a special meeting of stockholders

Under the New Mexico Public Utility Act, NMPRC approval is required for certain transactions that may result in PNMR’s change in control or exercise of control, including ownership of 10% or more of PNMR’s voting stock. Certain acquisitions of PNMR’s outstanding voting securities also require FERC approval.


ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.


ITEM 2.	PROPERTIES

PNMR

The significant properties owned by PNMR include those owned by PNM and TNMP and are disclosed below.

PNM

See Sources of Power in Part I, Item. 1 Business above for information on PNM’s owned and leased capacity in electric generating stations. As of December 31, 2013, PNM owned, jointly owned, or leased, 3,189 circuit miles of electric transmission lines (including the EIP), 5,849 miles of distribution overhead lines, 5,669 cable miles of underground distribution lines (excluding street lighting), and 280 substations. PNM’s electric transmission and distribution lines are generally located within easements and rights-of-way on public, private, and Native American lands. The EIP line is a 223 mile, 345 kilovolt line with a capacity of 200 MW. PNM leases interests in PVNGS Units 1 and 2 and related property, Delta, EIP and associated equipment, data processing, communication, office and other equipment, office space, vehicles, and real estate. PNM also owns and leases service and office facilities in Albuquerque and in other areas throughout its service territory. See Note 7 for additional information concerning leases, including notices given to the lessors under the PVNGS leases that PNM would renew certain of the leases and would exercise its option to purchase the assets underlying certain other leases at the expiration of the original lease terms. As discussed in Note 7, PNM agreed to exercise its option to purchase the leased portion of the EIP at expiration of the lease at fair market value. See Note 9 for additional information about the Delta operating lease and Valencia, including the potential purchase of Delta and 50% of Valencia.

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TNMP

TNMP’s facilities consist primarily of transmission and distribution facilities located in its service areas. TNMP also owns and leases service and office facilities in other areas throughout its service territory. As of December 31, 2013, TNMP owned 966 circuit miles of overhead electric transmission lines, 7,073 pole miles of overhead distribution lines, 1,098 circuit miles of underground distribution lines, and 108 substations. Substantially all of TNMP’s property is pledged to secure its first mortgage bonds. See Note 6.


ITEM 3.	LEGAL PROCEEDINGS

See Note 16 and Note 17 for information related to the following matters for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 16


•	The Clean Air Act - Regional Haze – SJGS


•	The Clean Air Act - Regional Haze – Four Corners


•	The Clean Air Act - Four Corners BART FIP Challenge


•	The Clean Air Act - Regional Haze Challenges


•	The Clean Air Act - SJGS Operating Permit Challenge


•	The Clean Air Act - Citizen Suit Under the Clean Air Act


•	The Clean Air Act - Four Corners Clean Air Act Lawsuit


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Endangered Species Act


•	Santa Fe Generating Station


•	Coal Combustion Byproducts Waste Disposal - Sierra Club Allegations


•	Continuous Highwall Mining Royalty Rate


•	SJCC Arbitration


•	Four Corners Severance Tax Assessment


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication


•	Conflicts at San Juan Mine Involving Oil and Gas Leaseholders


•	Rights-of-Way Matter


•	Complaint Against Southwestern Public Service Company


•	Navajo Nations Allottee Matters

Note 17


•	PNM - Renewable Portfolio Standard


•	PNM - Renewable Energy Rider


•	PNM - Energy Efficiency and Load Management


•	FPPAC Continuation Application


•	PNM - Emergency FFPAC


•	PNM - Application for Approvals to Purchase Delta


•	Application for Approval of La Luz Generating Station


•	San Juan Generating Station Units 2 and 3 Retirement


•	PNM - Transmission Rate Case


•	PNM - Formula Transmission Rate Case


•	TNMP - Advance Meter System Deployment


•	TNMP - Transmission Cost of Service Rates


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.

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SUPPLEMENTAL ITEM - EXECUTIVE OFFICERS OF PNM RESOURCES, INC.

All officers are elected annually by the Board of PNMR. Executive officers, their ages as of February 21, 2014 and offices held with PNMR for the past five years, or other companies if less than five years with PNMR, are as follows:



Name	Age	Office	Initial Effective Date
P. K. Collawn	55	Chairman, President, and Chief Executive Officer	January 2012
		President and Chief Executive Officer	March 2010
		President and Chief Operating Officer	August 2008

C. N. Eldred	60	Executive Vice President and Chief Financial Officer	July 2007

P. V. Apodaca	62	Senior Vice President, General Counsel and Secretary	January 2010
		University Counsel, University of New Mexico	May 2006

R. E. Talbot	53	Senior Vice President and Chief Operating Officer	January 2012
		Chief Operating Officer, Power Supply and Power Delivery - Indianapolis Power and Light Company	June 2011
		Senior Vice President, Power Supply - Indianapolis Power and Light Company	February 2007

R. N. Darnell	56	Senior Vice President, Public Policy	December 2011
		Vice President, Regulatory Affairs	April 2008

T. G. Sategna	60	Vice President and Corporate Controller	October 2003

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PART II


ITEM 5.	MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

PNMR’s common stock is traded on the New York Stock Exchange (Symbol: PNM). Ranges of sales prices of PNMR’s common stock, reported as composite transactions, and dividends declared on the common stock for 2013 and 2012, by quarters, are as follows:



Quarter Ended	Range of Sales Prices				Dividends Declared Per Share
	High		Low		Dividends Declared Per Share
2013
March 31	$	23.29	$	20.28	$	0.165
June 30	24.01		21.35		0.165
September 30	24.29		21.25		0.165
December 31	24.28		22.21		0.185
Fiscal Year	24.29		20.28		0.680
2012
March 31	$	18.94	$	17.52	$	0.145
June 30	19.54		17.84		0.145
September 30	21.42		19.75		0.145
December 31	22.32		20.05		0.145
Fiscal Year	22.32		17.52		0.580

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.145 per share in July 2012 and $0.165 per share in July 2013, which are reflected as being in the second quarter above. The Board declared dividends on common stock considered to be for the third quarter of $0.145 per share in September 2012 and $0.165 per share in September 2013, which are reflected as being in the third quarter above. On February 27, 2014, the Board declared a quarterly dividend of $0.185 per share. PNMR targets a long-term dividend payout ratio of 50% to 60% of consolidated earnings. During the period it was outstanding, PNMR’s Series A convertible preferred stock was entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock.

On February 21, 2014, there were 10,889 holders of record of PNMR’s common stock. All of the outstanding common stock of PNM and TNMP is held by PNMR.

See Note 5 for a discussion on limitations on the payments of dividends and the payment of future dividends, as well as dividends paid by PNM and TNMP.

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Preferred Stock

PNM is not aware of any active trading market for its cumulative preferred stock. Quarterly cash dividends were paid on PNM’s outstanding cumulative preferred stock at the stated rates during 2013 and 2012. PNMR purchased and retired all of its outstanding convertible preferred stock, Series A, effective September 23, 2011. TNMP does not have any preferred stock outstanding.

Sales of Unregistered Securities

None.

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ITEM 6.	SELECTED FINANCIAL DATA

The selected financial data and comparative operating statistics for PNMR should be read in conjunction with the Consolidated Financial Statements and Notes thereto and MD&A. On January 30, 2009, PNM completed the sale of its gas operations, which are considered discontinued operations and excluded from continuing operations information in the table below. PNMR sold First Choice on November 1, 2011. First Choice is included in the following information through October 31, 2011. PNMR fully impaired its equity method investment in Optim Energy in 2010 and recorded no income or loss for that investment through September 23, 2011, when Optim Energy was restructured reducing PNMR’s ownership to 1%.



PNM RESOURCES, INC. AND SUBSIDIARIES
	2013			2012			2011			2010			2009
	(In thousands except per share amounts and ratios)
Total Operating Revenues from Continuing Operations	$	1,387,923		$	1,342,403		$	1,700,619		$	1,673,517		$	1,647,744
Earnings (Loss) from Continuing Operations	$	115,556		$	120,125		$	190,934		$	(31,124	)	$	65,933
Net Earnings (Loss)	$	115,556		$	120,125		$	190,934		$	(31,124	)	$	136,734
Net Earnings (Loss) Attributable to PNMR	$	100,507		$	105,547		$	176,359		$	(45,215	)	$	124,316
Earnings (Loss) from Continuing Operations Attributable to PNMR per Common Share
Basic	$	1.26		$	1.32		$	1.98		$	(0.49	)	$	0.58
Diluted	$	1.25		$	1.31		$	1.96		$	(0.49	)	$	0.58
Net Earnings (Loss) Attributable to PNMR per Common Share
Basic	$	1.26		$	1.32		$	1.98		$	(0.49	)	$	1.36
Diluted	$	1.25		$	1.31		$	1.96		$	(0.49	)	$	1.36
Cash Flow Data
Net cash flows from operating activities	$	386,587		$	281,349		$	292,240		$	287,352		$	87,706
Net cash flows from investing activities	$	(331,446	)	$	(285,895	)	$	19,778		$	(275,906	)	$	379,726
Net cash flows from financing activities	$	(61,593	)	$	(1,560	)	$	(312,331	)	$	(10,683	)	$	(593,435	)
Total Assets	$	5,500,210		$	5,372,583		$	5,204,613		$	5,225,083		$	5,359,921
Long-Term Debt, including current installments	$	1,745,420		$	1,672,290		$	1,674,013		$	1,565,847		$	1,567,331
Common Stock Data
Market price per common share at year end	$	24.12		$	20.51		$	18.23		$	13.02		$	12.65
Book value per common share at year end	$	21.01		$	20.19		$	19.76		$	17.90		$	19.13
Tangible book value per share at year end	$	17.52		$	16.70		$	16.27		$	14.10		$	15.33
Average number of common shares outstanding - diluted	80,431			80,417			89,757			91,557			91,671
Dividends declared per common share	$	0.680		$	0.580		$	0.500		$	0.500		$	0.500
Capitalization
PNMR common stockholders’ equity	48.8		%	48.9		%	48.3		%	47.8		%	49.6		%
Convertible preferred stock	—			—			—			3.1			3.0
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.3			0.3			0.4			0.3
Long-term debt	50.9			50.8			51.4			48.7			47.1
	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%

Note: The book value per common share at year end, tangible book value per share at year end, average number of common shares outstanding, and return on average common equity reflect the Series A convertible preferred stock as if it was converted into common stock through September 23, 2011.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2013		2012		2011		2010			2009
	(In thousands)
PNM Revenues
Residential	$	411,579	$	409,005	$	390,380	$	355,905		$	320,965
Commercial	415,621		413,332		386,383		355,699			330,552
Industrial	74,552		78,637		73,742		65,358			62,699
Public authority	25,745		25,495		23,970		21,302			19,770
Economy service	32,909		25,354		21,141		20,218			16,841
Transmission	38,228		39,373		43,637		38,667			36,075
Firm-requirements wholesale	42,370		39,390		34,127		31,870			29,048
Other sales for resale	67,538		47,321		69,318		121,729			140,314
Mark-to-market activity	293		892		4,214		(3,599		)	151
Other	7,477		13,465		10,377		9,979			11,594
Total PNM Revenues	$	1,116,312	$	1,092,264	$	1,057,289	$	1,017,128		$	968,009
TNMP Revenues
Residential	$	111,373	$	103,255	$	100,290	$	83,645		$	74,739
Commercial	95,098		88,258		84,896		77,474			73,346
Industrial	13,084		13,405		13,065		12,342			12,113
Other	52,056		45,222		39,607		39,127			32,434
Total TNMP Revenues	$	271,611	$	250,140	$	237,858	$	212,588		$	192,632
First Choice Revenues
Residential	$	—	$	—	$	260,161	$	305,834		$	349,629
Commercial	—		—		166,498		159,785			160,998
Trading gains (losses)	—		—		—		(4		)	14
Other	—		—		12,791		17,588			18,177
Total First Choice Revenues	$	—	$	—	$	439,450	$	483,203		$	528,818

Notes: Under TECA, consumers in Texas can choose any REP to provide energy. TNMP delivers energy to consumers within its service area regardless of the REP chosen. Therefore, TNMP earns revenue for energy delivery and REPs earn revenue on the usage of that energy by its customers. The revenues reported above for TNMP include $33.8 million, $39.1 million, and $41.3 million received from First Choice in 2011, 2010, and 2009.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is included through October 31, 2011, when it was sold by PNMR.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2013	2012	2011	2010	2009
PNM MWh Sales
Residential	3,304,350	3,323,544	3,402,842	3,361,472	3,264,378
Commercial	3,954,774	4,022,184	4,043,796	4,015,999	3,899,121
Industrial	1,041,160	1,136,011	1,132,110	1,073,475	1,071,955
Public authority	266,368	279,169	282,062	263,424	249,554
Economy service	719,342	635,305	428,757	376,458	382,525
Firm-requirements wholesale	654,135	651,972	650,356	677,508	689,740
Other sales for resale	2,061,851	1,652,225	2,076,869	2,203,787	3,996,317
Total PNM MWh Sales	12,001,980	11,700,410	12,016,792	11,972,123	13,553,590
TNMP MWh Sales
Residential	2,796,661	2,714,511	2,862,337	2,699,601	2,582,555
Commercial	2,451,299	2,353,135	2,360,998	2,260,505	2,216,870
Industrial	2,598,442	2,727,126	2,578,877	2,241,452	1,983,165
Other	104,516	103,856	108,664	103,341	107,091
Total TNMP MWh Sales	7,950,918	7,898,628	7,910,876	7,304,899	6,889,681
First Choice MWh Sales
Residential	—	—	2,006,437	2,267,836	2,441,550
Commercial	—	—	1,538,203	1,363,746	1,218,949
Total First Choice MWh Sales	—	—	3,544,640	3,631,582	3,660,499


Notes:	The MWh reported above for TNMP include 836,599, 1,012,842, and 1,131,907 MWh for 2011, 2010, and 2009, used by consumers who chose First Choice as their REP. These MWh are also included in the First Choice MWh sales.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is included through October 31, 2011, when it was sold by PNMR.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2013		2012		2011		2010		2009
PNM Customers
Residential	453,218		450,507		448,979		447,789		445,637
Commercial	55,447		54,953		54,468		54,005		53,787
Industrial	251		250		251		259		269
Economy service	1		1		1		1		1
Other sales for resale	34		36		28		46		44
Other	928		952		983		1,003		991
Total PNM Customers	509,879		506,699		504,710		503,103		500,729
TNMP Consumers
Residential	196,799		193,550		192,356		190,809		188,812
Commercial	37,460		36,819		37,208		37,356		37,728
Industrial	70		70		73		72		73
Other	2,070		2,037		2,092		2,099		2,059
Total TNMP Consumers	236,399		232,476		231,729		230,336		228,672
First Choice Customers
Residential	—		—		176,577		172,506		183,605
Commercial	—		—		44,485		41,695		41,371
Total First Choice Customers	—		—		221,062		214,201		224,976
PNMR Generation Statistics
Net Capability - MW, including PPAs	2,572		2,537		2,547		2,631		2,711
Coincidental Peak Demand - MW	2,008		1,948		1,938		1,973		1,866
Average Fuel Cost per MMBTU	$	2.237	$	2.308	$	2.267	$	2.064	$	1.895
BTU per KWh of Net Generation	10,308		10,289		10,441		10,237		10,277


Notes:	The consumers reported above for TNMP include 64,732, 70,366, and 80,718 consumers for 2011, 2010, and 2009, who chose First Choice as their REP. These TNMP customers are also included in the First Choice customers.

PNM Gas, which was sold on January 30, 2009, is reported as discontinued operations and has been excluded from the above table.

First Choice is as of October 31, 2011, when it was sold by PNMR.

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-K General Instruction I (2). A reference to a “Note” in this Item 7 refers to the accompanying Notes to Consolidated Financial Statements included in 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 SUMMARY

Overview and Strategy

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

Strategic Goals

PNMR is focused on achieving the following strategic goals:


•	Earning authorized returns on its regulated businesses


•	Maintaining investment grade credit ratings


•	Providing a top-quartile total return to investors

In conjunction with these goals, PNM and TNMP are dedicated to:


•	Achieving industry-leading safety performance


•	Maintaining strong plant performance and system reliability


•	Delivering a superior customer experience


•	Demonstrating environmental leadership in its business operations

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities and their strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships.

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

Fair and timely rate treatment from regulators is crucial to PNMR achieving its strategic goals because it leads to PNM and TNMP earning their allowed returns. PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by credit rating agencies and would further improve the Company’s ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased total returns to investors.

PNM's interest in PVNGS Unit 3 is currently excluded from NMPRC jurisdictional rates. While PVNGS Unit 3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. Power generated from PNM’s 134 MW interest in PVNGS Unit 3 is currently sold into the wholesale market and any earnings or losses are attributable to shareholders. PNM has requested NMPRC approval to include PVNGS Unit

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3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018 as part of compliance with the requirements for BART at SJGS discussed below.

Maintaining Investment Grade Credit Ratings

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

Providing Top-Quartile Total Returns to Investors

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

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

Business Focus

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

Reliable and Affordable Power

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

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

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

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

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

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Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. In 2012 and 2013, its environmental focus has been in three key areas:


•	Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits


•	Preparing to meet New Mexico’s increasing renewable energy requirements as cost-effectively as possible


•	Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM’s power plants. The fresh water used per MWh generated has dropped by 21.0% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. In addition to the above areas of focus, the Company is also working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and has set goals for even further reductions.

Renewable Energy

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

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

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

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

SJGS

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

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

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

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requests authorization to:

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•	Retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs


•	Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018


•	Allow cost recovery for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4


•	Exchange ownership of 78 MW of PNM’s capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4

PNM requested the NMPRC issue its final ruling on the application no later than December 2014. On February 11, 2014, PNM’s application was determined to be complete. The Hearing Examiner indicated the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014. The Hearing Examiner indicated that he will schedule a public hearing to begin on August 19, 2014.

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

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

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

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

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

Energy Efficiency

Energy efficiency also plays a significant role in helping to keep customers' electricity costs low while continuing to meet their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2013, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 75 GWh. This is equivalent to the annual consumption of approximately 10,200 homes in PNM’s service territory. PNM’s load management and energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2013 resulted in energy savings totaling an estimated 17.0 GWh. This is equivalent to the annual consumption of approximately 1,650 homes in TNMP’s service territory.

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Creating Value for Customers and Communities

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

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

Recognizing the importance of environmental stewardship to customers and other stakeholders, PNM expanded engagement with environmental stakeholders to promote ongoing dialogue and input. Similarly, PNM also proactively communicated with communities about its efforts and plans related to environmental stewardship. Customers took note of PNM’s efforts in this area. A nationally recognized customer satisfaction benchmark revealed gains in awareness of PNM’s efforts to improve environmental impact, as well as customer perceptions around the commitment to preserving the environment now and for future generations. Benchmark data also demonstrates positive movement in the communication component of the customer experience.

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

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

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

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

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

Economic Factors

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

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Results of Operations

A summary of net earnings attributable to PNMR is as follows:



	Year Ended December 31,						Change
	2013		2012		2011		2013/2012			2012/2011
	(In millions, except per share amounts)

Net earnings	$	100.5	$	105.5	$	176.4	$	(5.0	)	$	(70.9	)
Average common and common equivalent shares	80.4		80.4		89.8		—			(9.4		)
Net earnings per diluted share	$	1.25	$	1.31	$	1.96	$	(0.06	)	$	(0.65	)

The components of the changes in earnings from continuing operations attributable to PNMR by segment are:



	Change
	2013/2012			2012/2011
	(In millions)
PNM	$	(3.4	)	$	37.0
TNMP	2.4			4.4
First Choice	—			(24.1		)
Corporate and Other	(4.0		)	(88.2		)
Net change	$	(5.0	)	$	(70.9	)

PNMR’s operational results were affected by the following:


•	Rate increases for PNM and TNMP - Additional information about these rate increases is provided in Note 17


•	Lower retail load at PNM partially offset by higher retail load in at TNMP


•	Milder weather


•	Fluctuating prices for sales of power from PVNGS Unit 3


•	Increased income tax expense due to impairments of state tax credits and a change in state tax rate (Note 11)


•	Exit from unregulated businesses - PNMR sold First Choice in 2011, resulting in a pre-tax gain of $174.9 million, which was included in the Corporate and Other segment. The results of operations only include First Choice through October 31, 2011.


•	Decrease in the number of common and common equivalent shares, primarily due to PNMR’s purchase of its equity as described in Note 6


•	Other factors impacting results of operation for each segment are discussed under Results of Operations below

Liquidity and Capital Resources

The Company has revolving credit facilities that provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which expire in October 2018. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $718.5 million at February 21, 2014. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

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

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RESULTS OF OPERATIONS

Segment Information

The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 2 for more information on PNMR’s operating segments.

The following discussion and analysis should be read in conjunction with the Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements in Part I, Item 1 and to Part II, Item 7A. Risk Factors.

PNM

The table below summarizes operating results for PNM:



	Year Ended December 31,									Change
	2013			2012			2011			2013/2012			2012/2011
	(In millions)
Electric operating revenues	$	1,116.3		$	1,092.3		$	1,057.3		$	24.0		$	35.0
Cost of energy	374.7			353.6			362.2			21.1			(8.6		)
Margin	741.6			738.6			695.1			3.0			43.5
Operating expenses	428.6			435.4			438.8			(6.8		)	(3.4		)
Depreciation and amortization	103.8			97.3			94.8			6.5			2.5
Operating income	209.2			205.9			161.4			3.3			44.5
Other income (deductions)	21.5			26.5			19.9			(5.0		)	6.6
Net interest charges	(79.2		)	(76.1		)	(75.3		)	(3.1		)	(0.8		)
Segment earnings before income taxes	151.5			156.3			106.0			(4.8		)	50.3
Income (taxes)	(48.8		)	(50.7		)	(37.4		)	1.9			(13.3		)
Valencia non-controlling interest	(14.5		)	(14.1		)	(14.0		)	(0.4		)	(0.1		)
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings	$	87.6		$	91.0		$	54.0		$	(3.4	)	$	37.0

The table below summarizes the significant changes to total revenues, cost of energy, and margin:



	2013/2012 Change									2012/2011 Change
	Total Revenues			Cost of Energy			Margin			Total Revenues			Cost of Energy			Margin
	(In millions)
Retail rate increases	$	—		$	—		$	—		$	40.3		$	—		$	40.3
Customer usage/load	(8.6		)	—			(8.6		)	(4.8		)	—			(4.8		)
Weather	(3.3		)	—			(3.3		)	(3.0		)	—			(3.0		)
Transmission	(1.6		)	1.0			(2.6		)	1.1			(0.2		)	1.3
Wholesale rate increase	2.9			—			2.9			4.0			—			4.0
Unregulated margins	2.8			(2.7		)	5.5			(5.9		)	1.1			(7.0		)
Energy efficiency rider	(2.1		)	—			(2.1		)	8.9			—			8.9
Renewable energy rider	14.7			6.3			8.4			6.9			2.0			4.9
Net unrealized economic hedges	(0.6		)	(0.9		)	0.3			(3.3		)	(1.1		)	(2.2		)
Other	19.8			17.4			2.5			(9.2		)	(10.4		)	1.1
Net change	$	24.0		$	21.1		$	3.0		$	35.0		$	(8.6	)	$	43.5

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The following table shows PNM operating revenues by customer class and average number of customers:



	Year Ended December 31,						Change
	2013		2012		2011		2013/2012			2012/2011
	(In millions, except customers)
Residential	$	411.6	$	409.0	$	390.4	$	2.6		$	18.6
Commercial	415.6		413.3		386.4		2.3			26.9
Industrial	74.6		78.6		73.8		(4.0		)	4.8
Public authority	25.7		25.5		24.0		0.2			1.5
Economy service	32.9		25.4		21.1		7.5			4.2
Transmission	38.2		39.4		43.6		(1.2		)	(4.2		)
Firm-requirements wholesale	42.4		39.4		34.1		3.0			5.3
Other sales for resale	67.5		47.4		69.3		20.1			(21.9		)
Mark-to-market activity	0.3		0.9		4.2		(0.6		)	(3.3		)
Other	7.5		13.4		10.4		(5.9		)	3.0
	$	1,116.3	$	1,092.3	$	1,057.3	$	24.0		$	35.0
Average retail customers (thousands)	508.2		505.6		503.9		2.6			1.7

The following table shows PNM GWh sales by customer class:



	Year Ended December 31,			Change
	2013	2012	2011	2013/2012		2012/2011
	(Gigawatt hours)
Residential	3,304.3	3,323.5	3,402.8	(19.2	)	(79.3	)
Commercial	3,954.8	4,022.2	4,043.8	(67.4	)	(21.6	)
Industrial	1,041.2	1,136.0	1,132.1	(94.8	)	3.9
Public authority	266.4	279.2	282.1	(12.8	)	(2.9	)
Economy Service	719.3	635.3	428.8	84.0		206.5
Firm-requirements wholesale	654.1	652.0	650.4	2.1		1.6
Other sales for resale	2,061.9	1,652.2	2,076.8	409.7		(424.6	)
	12,002.0	11,700.4	12,016.8	301.6		(316.4	)

On August 21, 2011, PNM implemented a $72.1 million annual non-fuel rate increase for its retail customers. This rate increase improved 2012 revenues and margins by $40.3 million. There was no retail rate increase in 2013. For 2013, retail sales were lower compared to 2012 reflecting a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area continues to lag the nation in economic recovery. PNM's weather normalized and leap-year adjusted retail KWh sales were lower in 2013 by 1.8%, which decreased margin $8.6 million compared to 2012 primarily due to the sluggish economy. In spite of the economic pressures, PNM experienced growth in average retail customers of 0.5% in 2013 compared to 2012. Weather negatively impacted revenues and margin by $3.3 million in 2013 as cooling degree days were 10.7% lower in 2013 than in 2012. In 2012, lower retail KWh sales, primarily in the residential and commercial customer classes, reflecting lower weather normalized and leap-year adjusted average usage per customer, decreased revenues and margins by $4.8 million. In addition, cooling degree days were 2.3% higher in 2012 compared to 2011, but were more than offset by lower heating degree days of 12.4%, resulting in lower revenue and margin of $3.0 million. There is no clear indication regarding the future of New Mexico’s economy. Encouraging signs such as growth in the housing industry, increased tax revenue in the Albuquerque metropolitan area, and unemployment rates below the national average are contrasted by indicators such as flat population growth and low job growth.

In 2013, lower transmission revenues as a result of expiration of contracts combined with higher third-party transmission expenses incurred to deliver power to the retail customers reduced margins by $2.6 million. In 2012, higher transmission rates as a result of the June 1, 2011 rate increase improved revenues and margins. PNM implemented new rates for NEC, its largest wholesale firm-requirements customer, in April 2012 and for Gallup, its second largest wholesale customer, in July 2013. These increases improved revenues and margins $2.9 million in 2013 and $4.0 million in 2012. PNM has responded to Gallup’s request for proposals for long-term power supply. On January 13, 2014, PNM was notified that its proposal was not the highest ranked and Gallup has stated that a contract is being negotiated with the top-ranked bidder. If a contract is executed with the top-ranked

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bidder, PNM’s contract with Gallup would expire on June 30, 2014. PNM’s 2013 revenues for power sold under the Gallup contract were $11.7 million. See Note 17. If PNM does not continue to supply power to Gallup, costs currently being recovered under the Gallup contract would be reallocated and partially included in PNM’s next retail rate case filing, which is expected to be filed by the end of 2014. In addition, PNM would consider opportunities to serve other FERC generation customers. PNM is unable to predict the outcome of this matter.

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

On August 20, 2012, PNM implemented its renewable energy rider, a mechanism approved by the NMPRC, which recovers renewable energy procurement costs, including the investment in and an allowed return on the 22 MW of PNM-owned solar PV facilities constructed to meet the RPS. See Note 17. Revenues under this rider were $6.9 million in 2012 and increased by an additional $14.7 million in 2013. Related cost of energy, reflecting the purchase cost of RECs, was $2.0 million in 2012 and increased by an additional $6.3 million in 2013. Included in revenues is the earned return component on its investment of $1.2 million in 2012, which increased by $1.8 million in 2013. The remaining revenues from this rider recover renewable energy operating, depreciation, and interest expenses.

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

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

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

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

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

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

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

Interest expense increased $3.1 million in 2013 primarily due to the deferral in 2012 of interest costs associated with the 22 MW of PNM-owned solar PV facilities, which are now being recovered through a renewable energy rate rider. In 2012, interest expense increased $7.0 million due to the issuance of $160.0 million of long-term debt in October 2011. This was partially offset by $5.6 million for the debt portion of AFUDC and $0.9 million of interest charges on PNM’s investment in renewable resources that are deferred for recovery through the renewable energy rate rider.

TNMP

The table below summarizes the operating results for TNMP:



	Year Ended December 31,									Change
	2013			2012			2011			2013/2012			2012/2011
	(In millions)
Electric operating revenues	$	271.6		$	250.1		$	237.9		$	21.5		$	12.2
Cost of energy	57.6			46.2			41.2			11.4			5.0
Margin	214.0			203.9			196.7			10.1			7.2
Operating expenses	91.6			87.1			88.2			4.5			(1.1		)
Depreciation and amortization	50.2			49.3			44.6			0.9			4.7
Operating income	72.2			67.5			63.8			4.7			3.7
Other income (deductions)	1.9			2.7			1.6			(0.8		)	1.1
Net interest charges	(27.4		)	(28.2		)	(29.3		)	0.8			1.1
Segment earnings before income taxes	46.7			42.1			36.1			4.6			6.0
Income (taxes)	(17.6		)	(15.4		)	(13.9		)	(2.2		)	(1.5		)
Segment earnings	$	29.1		$	26.7		$	22.3		$	2.4		$	4.4

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The table below summarizes the significant changes to total revenues, cost of energy, and margin:



	2013/2012 Change								2012/2011 Change
	Total Revenues			Cost of Energy		Margin			Total Revenues			Cost of Energy		Margin
	(In millions)
Rate increases	$	4.8		$	—	$	4.8		$	1.4		$	—	$	1.4
Customer usage/load	2.0			—		2.0			0.8			—		0.8
Customer growth	1.5			—		1.5			1.2			—		1.2
Demand based customers	3.6			—		3.6			—			—		—
Weather	(0.7		)	—		(0.7		)	(4.1		)	—		(4.1		)
Recovery of third-party transmission costs	11.8			11.4		0.4			4.9			5.0		(0.1		)
AMS surcharge	2.7			—		2.7			6.9			—		6.9
CTC surcharge	(3.4		)	—		(3.4		)	(0.6		)	—		(0.6		)
1999 rate settlement	(1.6		)	—		(1.6		)	1.6			—		1.6
Other	0.8			—		0.8			0.1			—		0.1
Net change	$	21.5		$	11.4	$	10.1		$	12.2		$	5.0	$	7.2

The following table shows TNMP operating revenues by retail tariff consumer class, including intersegment revenues, and average number of consumers:



	Year Ended December 31,						Change
	2013		2012		2011		2013/2012			2012/2011
	(In millions, except customers)
Residential	$	111.3	$	103.3	$	100.3	$	8.0		$	3.0
Commercial	95.1		88.3		84.9		6.8			3.4
Industrial	13.1		13.4		13.1		(0.3		)	0.3
Other	52.1		45.1		39.6		7.0			5.5
	$	271.6	$	250.1	$	237.9	$	21.5		$	12.2
Average consumers (thousands) ⁽¹⁾	235.1		233.0		231.3		2.1			1.7

⁽¹⁾

TNMP provides transmission and distribution services to REPs that provide electric service to customers in TNMP’s service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy. The average consumers reported above include 67,268 consumers of TNMP for 2011 that chose First Choice as their REP. These consumers are also included in the First Choice segment.

The following table shows TNMP GWh sales by retail tariff consumers class:



	Year Ended December 31,			Change
	2013	2012	2011	2013/2012		2012/2011
	(Gigawatt hours)⁽¹⁾
Residential	2,796.7	2,714.5	2,862.3	82.2		(147.8	)
Commercial	2,451.3	2,353.1	2,361.0	98.2		(7.9	)
Industrial	2,598.4	2,727.1	2,578.9	(128.7	)	148.2
Other	104.5	103.9	108.7	0.6		(4.8	)
	7,950.9	7,898.6	7,910.9	52.3		(12.3	)


⁽¹⁾	The GWh sales reported above include 836.6 GWhs for 2011 used by consumers of TNMP who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

Implementation of rate increases in September 2012, March 2013, and September 2013 increased revenues and margins by $4.8 million in 2013 compared to 2012. See Note 17. In 2013, TNMP experienced average customer growth of 0.9% further

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

Differences between revenues and costs charged by third-party transmission providers are deferred and recovered through a transmission cost recovery factor. Higher transmission cost of energy resulting from rate increases and higher demand based charges from other transmission service providers within ERCOT increased cost of energy $11.4 million in 2013 and $5.0 million in 2012. These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue $11.8 million in 2013 and $4.9 million in 2012.

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

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

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

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

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

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

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

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First Choice

As discussed in Note 3, PNMR sold First Choice on November 1, 2011. The table below summarizes the operating results for First Choice from January 1, 2011 through October 31, 2011:



	Ten Months Ended October 31,
	2011
	(In millions)
Electric operating revenues	$	439.5
Cost of energy	323.3
Margin	116.1
Operating expenses	76.0
Depreciation and amortization	1.1
Operating income	39.1
Other income (deductions)	(0.6		)
Net interest charges	(0.6		)
Segment earnings before income taxes	37.9
Income (taxes)	(13.8		)
Segment earnings	$	24.1

For the ten months of operations in 2011, First Choice operating revenues consisted of $260.2 million from residential customers, $166.5 million from commercial customers, and $12.8 million from other sources. First Choice’s sales were 2,006.4 GWh to residential customers and 1,538.2 GWh to commercial customers. At October 31, 2013, First Choice had 0.2 million customers. See note above in the TNMP segment discussion about the impact of TECA.

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

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

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

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Corporate and Other

The table below summarizes the operating results for Corporate and Other:



	Year Ended December 31,									Change
	2013			2012			2011			2013/2012			2012/2011
				(In millions)
Electric operating revenues	$	—		—			$	(34.0	)	$	—		$	34.0
Cost of energy	—			—			(33.8		)	—			33.8
Margin	—			—			(0.2		)	—			0.2
Operating expenses	(18.3		)	(17.9		)	(9.7		)	(0.4		)	(8.2		)
Depreciation and amortization	12.8			17.5			16.5			(4.7		)	1.0
Operating income (loss)	5.5			0.3			(7.0		)	5.2			7.3
Gain on sale of First Choice	—			1.0			174.9			(1.0		)	(173.9		)
Other income (deductions)	(13.7		)	(8.1		)	(15.8		)	(5.6		)	7.7
Net interest charges	(14.9		)	(16.6		)	(19.6		)	1.7			3.0
Segment earnings (loss) before income taxes	(23.1		)	(23.4		)	132.5			0.3			(155.9		)
Income (taxes) benefit	6.9			11.2			(56.5		)	(4.3		)	67.7
Segment earnings (loss)	$	(16.2	)	$	(12.2	)	$	76.0		$	(4.0	)	$	(88.2	)

The Corporate and Other segment includes consolidation eliminations of revenues and cost of energy between business segments related to TNMP’s sale of transmission services to First Choice prior to November 1, 2011, when PNMR sold First Choice (Note 3). Accordingly, there were no eliminations of intersegment revenues in 2012 or 2013. Corporate and Other results also include the gain on the sale of First Choice.

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP. The amounts allocated include certain expenses shown as depreciation and amortization and other income (deductions) in the table above. The operating income (loss) of $5.5 million in 2013 reflects the allocation of $4.0 million of the Company’s contributions to the PNM Resources Foundation and financial support to the PNM Good Neighbor Fund, recorded in other income (deductions), which were allocated to PNM and TNMP reducing operating expenses. The operating income (loss) of $(7.0) million in 2011 reflects legal and consulting expenses of $4.6 million related to assessment of strategic alternatives for PNMR’s competitive businesses, as well as depreciation and other operating expenses that were retained in the Corporate and Other segment. Beginning in 2012, substantially all Corporate and Other operating expenses are allocated to the utilities.

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

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

In 2013 and 2012, income tax benefits were reduced by $3.9 million and $0.7 million due to impairments of New Mexico wind energy production tax credit carry forwards. The impaired credits are not expected to be utilized prior to their expiration due to the Company’s net operating loss position and the extension of fifty percent bonus depreciation under the American Taxpayer Relief Act of 2012. Additional expense of $1.2 million was recognized in 2013 due to reductions in Corporate and Other’s deferred tax assets resulting from legislation, which reduced future New Mexico corporate income tax rates. See Note 11.

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LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The information concerning PNMR’s cash flows is summarized as follows:



	Year Ended December 31,									Change
	2013			2012			2011			2013/2012			2012/2011
	(In millions)
Net cash flows from:
Operating activities	$	386.6		$	281.3		$	292.2		$	105.3		$	(10.9	)
Investing activities	(331.4		)	(285.9		)	19.8			(45.5		)	(305.7		)
Financing activities	(61.6		)	(1.6		)	(312.3		)	(60.0		)	310.7
Net change in cash and cash equivalents	$	(6.5	)	$	(6.1	)	$	(0.3	)	$	(0.2	)	$	(5.9	)

The changes in PNMR’s cash flows from operating activities primarily relate to income tax refunds received of $95.3 million in 2013 compared to income taxes paid of $5.3 million in 2012 and refunds received of $5.5 million in 2011 and rate increases at TNMP and PNM. Contributions to the PNM and TNMP pension and other postretirement benefit plans of $66.5 million in 2013 compared to $88.5 million in 2012 and $48.3 million in 2011 also contributed to operating cash flow changes. In addition, changes in assets and liabilities resulting from normal operations impact operating cash flows. These increases were offset by refunds of $15.2 million made to customers related to the settlement of PNM’s transmission rate case in 2013, as well as governmental grants received by PNM of $21.6 million in 2012 and $2.1 million in 2011 that did not recur in 2013, and lower retail load at PNM in 2013.

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

The changes in cash flows from financing activities relate primarily to the use of proceeds from the sale of First Choice in 2011 to purchase PNMR common stock for $125.7 million, PNMR’s convertible preferred stock, Series A, for $73.5 million, and long-term debt for $58.5 million. Cash flows from financing activities in 2013 also includes long-term borrowings of $75.0 million made at PNM. In addition, $13.0 million was paid in connection with TNMP’s debt exchange and $26.9 million was paid by PNMR to repurchase $23.8 million of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in 2013. In 2012, PNMR obtained $100.0 million in new short-term borrowings, and used the proceeds to repay borrowings under the PNMR Revolving Credit Facility. PNM also refinanced $20.0 million of PCRBs in 2012. In 2011, PNM obtained $160.0 million in new long-term borrowings, using the proceeds to reduce short-term borrowings. Also in 2011, TNMP replaced $50.0 million in long-term debt with a new term loan agreement for $50.0 million.

Financing Activities

See Note 6, for additional information concerning the Company’s financing activities. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. The Company’s ability to access the credit and capital markets at a reasonable cost is largely dependent upon its:


•	Ability to earn a fair return on equity


•	Results of operations


•	Ability to obtain required regulatory approvals

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•	Conditions in the financial markets


•	Credit ratings

The $100.0 million PNMR Term Loan Agreement matures on December 26, 2014 and the $75.0 million PNM Term Loan Agreement matures on October 21, 2014. Each of the term loans contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%. These ratios reflect the present value of payments under the PVNGS and EIP leases as debt. PNMR and PNM anticipate that funds to repay these term loans will come from entering into a new arrangement similar to the existing agreements, borrowing under their revolving credit facilities, or a combination of these sources. At December 31, 2013, average interest rates were 1.02% for the PNMR Term Loan Agreement and 1.42% for the PNM Term Loan Agreement. PNM anticipates entering into a new $175.0 million term loan agreement with a term of 18 months in March 2014. PNM would use a portion of the funds borrowed under the new agreement to repay all amounts outstanding under the PNM Term Loan Agreement and would use the balance of the funds to repay other short-term borrowings.

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for PNMR common stock and PNM preferred stock. Key activities in PNMR’s current construction program include:


•	Upgrading generation resources, including expenditures for compliance with environmental requirements and for renewable energy resources


•	Expanding the electric transmission and distribution systems


•	Purchasing nuclear fuel

Projected capital requirements for 2014-2018 are:



	2014		2015-2018		Total
	(In millions)
Construction expenditures	$	509.0	$	1,758.2	$	2,267.2
Dividends on PNMR common stock	58.9		235.8		294.7
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$568.4		$1,996.1		$2,564.5

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $80.0 million related to environmental upgrades at SJGS to address regional haze and $276.3 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, additional peaking resources to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners of $80.3 million, the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, and the anticipated purchase of Delta. See Note 16 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $10.0 million in 2014.

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

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. Note 6 contains information about the maturities on long-term debt. The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances or make additional debt repurchases in the future.

Liquidity

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

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Each of the credit facilities contains one financial covenant that requires the maintenance of debt-to-capital ratios of less than or equal to 65%. For PNMR and PNM, these ratios reflect the present value of payments under the PVNGS and EIP leases as debt.

The revolving credit facilities and the PNM New Mexico Credit Facility provide short-term borrowing capacity. The revolving credit facilities also allow letters of credit to be issued. Letters of credit reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company’s business is seasonal with more revenues and cash flows from operations being generated in the summer months. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Revolving Credit Facility ranged from zero to $84.0 million during the year ended December 31, 2013, $14.0 million to $141.0 million during the year ended December 31, 2012, and zero to $106.0 million during the year ended December 31, 2011. Such borrowings ranged from zero to $28.1 million during the three months ended December 31, 2013. Borrowings under the PNM Revolving Credit Facility ranged from zero to $130.8 million during the year ended December 31, 2013, zero to $168.0 million during the year ended December 31, 2012, and zero to $298.0 million during the year ended December 31, 2011. Such borrowings ranged from zero to $51.8 million during the three months ended December 31, 2013. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $40.0 million during the year ended December 31, 2013 and from zero to $19.0 million during the three months ended December 31, 2013. There were no such borrowings in 2012 and 2011. At December 31, 2013, the average interest rate was 1.42% for the PNM Revolving Credit Facility. The PNMR Revolving Credit Facility and the TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2013.

The Company currently believes that its capital requirements can be met through internal cash generation, existing credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the recent recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM may consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

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

On April 5, 2013, S&P raised the corporate credit ratings and the senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody’s changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. On January 30, 2014, Moody’s raised the senior unsecured rating for PNMR, the senior unsecured and issuer ratings for PNM, and the senior secured and issuer ratings for TNMP. Moody’s continued to maintain the ratings outlook for PNMR, PNM, and TNMP as positive. As of February 21, 2014, ratings on the Company’s securities were as follows:



	PNMR	PNM	TNMP
S&P
Senior secured	*	*	A-
Senior unsecured	BBB-	BBB	*
Preferred stock	*	BB+	*
Moody’s
Senior secured	*	*	A2
Senior unsecured	Baa3	Baa2	*
Preferred stock	*	Ba2	*
* Not applicable

Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

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A summary of liquidity arrangements as of February 21, 2014 is as follows:



	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
			(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0
Amounts outstanding as of February 21, 2014:
Revolving credit facility	$	—	$	69.4	$	—	$	69.4
PNM New Mexico Credit Facility	—		25.0		—		25.0
Letters of credit	8.6		3.2		0.3		12.1
Total short term-debt and letters of credit	8.6		97.6		0.3		106.5
Remaining availability as of February 21, 2014	$	291.4	$	352.4	$	74.7	$	718.5
Invested cash as of February 21, 2014	$	1.9	$	—	$	—	$	1.9

The above table excludes intercompany debt. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

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

Off-Balance Sheet Arrangements

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

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

For reasons similar to the PVNGS sale and leaseback transactions, PNM built the EIP transmission line and sold it in sale and leaseback transactions in 1985. PNM currently owns 60% and operates the other 40% of the EIP line under the terms of a lease agreement. The lease expires in 2015 with fixed-rate and fair market value renewal options and a fair market value purchase option. PNM has agreed to exercise its option to purchase the leased assets at expiration of the lease at fair market value. See Note 7.

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

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

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	PVNGS Units 1&2		EIP		Delta		Total
	(In thousands)
2014	$	32,207	$	4,267	$	5,956	$	42,430
2015	25,319		—		5,956		31,275
2016	20,589		—		5,956		26,545
2017	18,139		—		5,956		24,095
2018	18,139		—		5,956		24,095
Thereafter	83,263		—		9,430		92,693
Total	$	197,656	$	4,267	$	39,210	$	241,133

As discussed in Note 7, PNM and the lessors under each of the PVNGS Unit 1 leases entered into amendments to those leases that renew the leases from their original expiration on January 15, 2015 through January 15, 2023. In addition, PNM anticipates entering into an amendment with the lessor under one of the PVNGS Unit 2 leases that would extend that lease from its original expiration on January 15, 2016 through January 15, 2024. PNM has given notice to lessors under the other three PVNGS Unit 2 leases that PNM will exercise its option to purchase the assets underlying the leases at fair market value at the expiration of the leases on January 15, 2016. The semiannual renewal payments aggregate $8.3 million under the PVNGS Unit 1 leases and are $0.8 million for the one renewed PVNGS Unit 2 lease, which amounts are included above. See Sources of Power in Part I, Item 1, Investments in Note 1, and Note 7 for additional information.

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Commitments and Contractual Obligations

The following table sets forth PNMR’s long-term contractual obligations as of December 31, 2013. See Note 7 for further details about the Company’s significant leases:



	Payments Due
Contractual Obligations	2014		2015-2016		2017-2018		2019 and Thereafter		Total
	(In thousands)
Long-term debt (a)	$	75,000	$	158,066	$	507,025	$	985,045	$	1,725,136
Interest on long-term debt (b)	113,064		208,890		188,316		681,933		1,192,203
Operating leases (c)	53,594		74,740		61,890		167,225		357,449
Transmission reservation payments	13,858		20,558		18,621		38,595		91,632
Coal contracts (d)	63,491		133,753		100,173		443,536		740,953
Coal mine decommissioning (e)	2,969		2,640		2,148		141,381		149,138
Nuclear decommissioning funding requirements (f)	2,637		5,274		5,274		10,120		23,305
Outsourcing	5,574		10,169		3,398		—		19,141
Pension and retiree medical (g)	5,470		45,953		37,176		—		88,599
Construction expenditures (h)	509,002		1,013,220		744,935		—		2,267,157
Total (i)	$	844,659	$	1,673,263	$	1,668,956	$	2,467,835	$	6,654,713


(a)	Represents total long-term debt, excluding unamortized discounts of $2.4 million and unamortized premiums of $22.7 million. The TNMP 2011 Term Loan Agreement, which is due on June 30, 2014, is not reflected as maturing in 2014 in the above table since TNMP has entered into the TNMP 2013 Bond Purchase Agreement to re-finance that debt on a long-term basis as discussed in Note 6.


(b)	Represents interest payments during the period.

(c)

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


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


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


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


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

(h)

Represents forecasted construction expenditures, including nuclear fuel, under which substantial commitments have been made. See Note 14. The Company only forecasts capital expenditures for the next five years. The construction expenditures include the purchase of the leased portion of the EIP and the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases, as well as the anticipated purchase of Delta. See Capital Requirements above, Note 7 and Note 9.

(i)

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

Contingent Provisions of Certain Obligations

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

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

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

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

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

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

Capital Structure

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



	December 31,
PNMR	2013		2012
PNMR common equity	48.8	%	48.9	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	50.9	%	50.8	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	48.2	%	50.5	%
Preferred stock	0.4	%	0.5	%
Long-term debt	51.4	%	49.0	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	59.9	%	59.8	%
Long-term debt	40.1	%	40.2	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

According to EPA, gases that trap heat in the atmosphere are called greenhouse gases. The four primary greenhouse gases are CO₂, methane, nitrous oxide, and fluorinated gases, including chlorofluorocarbons such as Freon. In 2013, GHG associated

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with PNM’s interests in its generating plants were approximately 7.0 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG. By comparison, the total GHG in the United States in 2011, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.6 billion metric tons were CO₂.

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

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

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

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

Given the geographic location of its facilities and customers, PNM generally has not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the exception of periodic drought conditions. PNM’s service areas also experience high winds and severe thunderstorms periodically. Climate changes are generally not expected to have material consequences in the near-term. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal-fired generating plants. Water shortage sharing agreements have been in place since 2004, although no shortage has been declared due to sufficient precipitation in the San Juan River basin. PNM also has a supplemental water contract in place with the Jicarilla Apache Nation to help address any water shortages from primary sources. The contract expires on

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December 31, 2016. TNMP has operations in the Gulf Coast area of Texas, which experiences periodic hurricanes and drought conditions. In addition to potentially causing physical damage to TNMP-owned facilities, which disrupt the ability to transmit and/or distribute energy, hurricanes can temporarily reduce customers’ usage and demand for energy.

EPA Regulation

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

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

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

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

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

EPA’s reproposed GHG NSPS for new sources published on September 20, 2013 apply only to new EGUs. The reproposed standard would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and

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

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

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

Federal Legislation

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

State and Regional Activity

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

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in the NMPRC analysis are necessary to impact future resource decisions. The primary consequence of the standardized cost of carbon emissions was an increase to generation portfolio costs.

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

On August 2, 2012, thirty-three New Mexico organizations representing public health, business, environmental, consumers, Native American, and other interested parties filed a petition for rulemaking with the NMPRC. The petition asked the NMPRC to issue a NOPR regarding the implementation of an Optional Clean Energy Standard for electric utilities located in New Mexico. The proposed standard would have utilities that elect to participate reduce their CO₂ emissions by 3% per year. Utilities that opt into the program would be assured recovery of their reasonable compliance costs. On October 4, 2012, the NMPRC held a workshop to discuss the proposed standard and whether it has authority to proceed with the NOPR. On August 23, 2013, the petitioners amended the August 2, 2012 petition and requested that the NMPRC issue a NOPR to implement a “Carbon Risk Reduction Rule” for electric utilities in New Mexico. The proposed rule would require affected utilities to demonstrate a 3% per year CO₂ emission reduction from a three-year average baseline period between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than one metric ton of CO₂per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords

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

Transmission Issues

At any given time, FERC has various notices of inquiry and rulemaking dockets related to transmission issues pending. Such actions may lead to changes in FERC administrative rules or ratemaking policy, but have no time frame in which action must be taken or a docket closed with no further action. Further, such notices and rulemaking dockets do not apply strictly to PNM, but will have industry-wide effects in that they will apply to all FERC-regulated entities. PNM monitors and often submits comments taking a position in such notices and rulemaking dockets or may join in larger group responses. PNM often cannot determine the full impact of a proposed rule and policy change until the final determination is made by FERC and PNM is unable to predict the outcome of these matters.

On November 24, 2009, FERC issued Order 729 approving two Modeling, Data, and Analysis Reliability Standards (“Reliability Standards”) submitted by NERC - MOD-001-1 (Available Transmission System Capability) and MOD-029-1 (Rated System Path Methodology). Both MOD-001-1 and MOD-029-1 require a consistent approach, provided for in the Reliability Standards, to measuring the total transmission capability (“TTC”) of a transmission path. The TTC level established using the two Reliability Standards could result in a reduction in the available transmission capacity currently used by PNM to deliver generation resources necessary for its jurisdictional load and for fulfilling its obligations to third-party users of the PNM transmission system.

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

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

A final ballot for MOD-001-2 concluded on December 20, 2013 and received sufficient affirmative votes for approval. On February 10, 2014, NERC filed with FERC a petition for approval of MOD-001-2 and retirement of reliability standards

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MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. The MOD-001-2 standard will become effective on the first day of the calendar quarter that is 18 months after the date the standard is approved by FERC. The retirement and changes to these MOD standards will remove the risk of reduced TTC for PNM and other southwestern utilities.

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

Financial Reform Legislation

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

Other Matters

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Unbilled Revenues

The Company records unbilled revenues representing management’s assessment of the estimated amount of revenue earned from customers for services rendered between the meter-reading dates in a particular month and the end of that month. Management estimates unbilled revenues based on daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience. The estimate requires the use of various judgments and assumptions; significant changes to these judgments and assumptions could have a material impact to the Company’s results of operations.

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Regulatory Accounting

The Company is subject to the provisions of GAAP for rate-regulated enterprises and records assets and liabilities resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities. Additional information concerning regulatory assets and liabilities is contained in Note 4.

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

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

Impairments

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

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

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

Application of the quantitative impairment test requires judgment, including assignment of assets and liabilities to reporting units and the determination of the fair value of a reporting unit. A discounted cash flow methodology is primarily used by the Company to estimate the fair value of a reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business and determination of appropriate WACC for each reporting unit.

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

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selection of a WACC is subjective and modifications to this rate could significantly increase or decrease the fair value of a reporting unit.

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

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

Decommissioning and Reclamation Costs

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

In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse the mining companies for the cost of contemporaneous reclamation as well as the costs for final reclamation of the coal mines. The reclamation costs are based on site-specific studies that estimate the costs to be incurred in the future and are dependent upon numerous assumptions, including estimates of future reclamation costs at current price levels, inflation rates, and discount rates. A 10% increase in the estimates of future reclamation costs at current price levels would have increased the mine reclamation liability by $2.9 million at December 31, 2013. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for discussion of the final reclamation costs.

Derivatives

The Company follows the provisions set forth in GAAP to account for derivatives. These provisions establish accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. GAAP also requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location market liquidity, and term of the agreement. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in

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any estimate technique. Changes in the assumptions used in the fair value determinations could have significant impacts on the results of operations and financial position of the Company. Note 8 contains additional information on commodity derivatives, including the volumes covered by derivative contracts.

Pension and Other Postretirement Benefits

The Company maintains qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs. The net periodic benefit cost or income and the calculation of the projected benefit obligations are recognized in the Company’s financial statements and depend on expected investment performance, the level of contributions made to the plans, and employee demographics. They both require the use of a number of actuarial assumptions and estimates. The most critical of the actuarial assumptions are the expected long-term rate of return, the discount rate, and projected health care cost trend rates. The Company reviews and evaluates its actuarial assumptions annually and adjusts them as necessary. Changes in the pension and OPEB assets and liabilities associated with these factors are not immediately recognized as net periodic benefit cost or income in results of operations, but are recognized in future years, generally, over the remaining life of the plan. However, these factors could have a significant impact on the financial position of the company. Note 12 contains additional information about pension and OPEB obligations, including assumptions utilized in the calculations and impacts of changes in certain of those assumptions.

Accounting for Contingencies

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

Contingencies related to litigation and claims, as well as environmental and regulatory matters, also require the use of significant judgment and estimation. The Company attempts to take into account all known factors regarding the future outcome of contingent events and records an accrual for any contingent events that are both probable and reasonably estimated based upon current available information. However the actual outcomes can vary from any amounts accrued which could have a material effect on the results of operations and financial position of the Company. See Note 16 and Note 17.

Income Taxes

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

Market Risk

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

MD&A FOR PNM

RESULTS OF OPERATIONS

PNM operates in only one reportable segment, as presented above in Results of Operations for PNMR.

MD&A FOR TNMP

RESULTS OF OPERATIONS

TNMP operates in only one reportable segment, as presented above in Results of Operations for PNMR.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Company manages the scope of its various forms of risk through a comprehensive set of policies and procedures with oversight by senior level management through the RMC. The Board’s Finance Committee sets the risk limit parameters. The RMC has oversight over the risk control organization. The RMC is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions on an enterprise-wide basis. The RMC’s responsibilities include:

• Establishment of policies regarding risk exposure levels and activities in each of the business segments

• Approval of the types of derivatives entered into for hedging

• Review and approval of hedging risk activities

• Establishment of policies regarding counterparty exposure and limits

• Authorization and delegation of transaction limits

• Review and approval of controls and procedures for derivative activities

• Review and approval of models and assumptions used to calculate mark-to-market and market risk exposure

• Proposing risk limits to the Board’s Finance Committee for its approval

• Quarterly reporting to the Board’s Audit and Finance Committees on these activities.

To the extent an open position exists, fluctuating commodity prices, interest rates, equity prices, and economic conditions can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with certainty the impact that its risk management decisions may have on its businesses, operating results, or financial position.

Commodity Risk

Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 8, including a summary of the fair values of mark-to-market energy related derivative contracts included in the Consolidated Balance Sheets. At December 31, 2013 and 2012, PNMR and PNM had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts, other than those that do not meet the definition of a derivative under GAAP and those derivatives designated as normal purchases and normal sales, are recorded at fair value on the Consolidated Balance Sheet. The following table details the changes in the net asset or liability balance sheet position for mark-to-market energy transactions.



	Economic Hedges
	PNMR and PNM
	(In thousands)
Sources of fair value gain (loss):
Net fair value at December 31, 2011	$	(356	)
Amount realized on contracts delivered during period	(4,110		)
Changes in fair value	5,708
Net mark-to-market change recorded in earnings	1,598
Net change recorded as regulatory liability	(38		)
Net fair value at December 31, 2012	1,204
Amount realized on contracts delivered during period	(970		)
Changes in fair value	2,836
Net mark-to-market change recorded in earnings	1,866
Net change recorded as regulatory liability	203
Net fair value at December 31, 2013	$	3,273

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The following table provides the maturity of the net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and generate (use) cash.

Fair Value of Mark-to-Market Instruments at December 31, 2013



	2014		2015		2016
PNMR and PNM	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—
Prices provided by other external sources	1,366		2,281		(374		)
Prices based on models and other valuations	—		—		—
Total	$	1,366	$	2,281	$	(374	)

PNM measures the market risk of its long-term contracts and wholesale activities using a Monte Carlo VaR simulation model to report the possible loss in value from price movements. VaR is not a measure of the potential accounting mark-to-market loss. The quantitative risk information is limited by the parameters established in creating the model. The Monte Carlo VaR methodology employs the following critical parameters: historical volatility estimates, market values of all contractual commitments, a three-day holding period, seasonally adjusted and cross-commodity correlation estimates, and a 95% confidence level. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used.

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the year ended December 31, 2013, the high, low, and average VaR amounts were $1.4 million, $0.6 million, and $0.9 million. For the year ended December 31, 2012, the high, low and average VaR amounts were $1.4 million, $0.3 million, and $0.6 million. At December 31, 2013 and December 31, 2012, the VaR amounts for the PNM wholesale portfolio were $0.6 million and $0.5 million.

The VaR limits, which were not exceeded during 2013 or 2012, represent an estimate of the potential gains or losses that could be recognized on the Company’s portfolios, subject to market risk, given current volatility in the market, and are not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.

Credit Risk

The Company is exposed to credit risk from its retail and wholesale customers, as well as the counterparties to derivative instruments. The Company conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. The following table provides information related to credit exposure by the credit worthiness (credit rating) of the counterparties and concentration of credit risk to counterparties. All credit exposures at December 31, 2013 will mature in less than two years.

Schedule of Credit Risk Exposure

December 31, 2013



Rating ⁽¹⁾	Credit Risk Exposure⁽²⁾		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
PNMR and PNM
External ratings:
Investment grade	$	9,130	2	$	8,954
Non-investment grade	—		—	—
Internal ratings:
Investment grade	477		—	—
Non-investment grade	410		—	—
Total	$	10,017		$	8,954

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⁽¹⁾	The rating “Investment Grade” is for counterparties, or a guarantor, with a minimum S&P rating of BBB- or Moody’s rating of Baa3. The category “Internal Ratings - Investment Grade” includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company’s credit policy.

⁽²⁾

The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than full-requirements customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At December 31, 2013, PNMR and PNM held $0.2 million of cash collateral to offset their credit exposure.

Net credit risk for PNMR’s and PNM’s largest counterparty as of December 31, 2013 was $6.7 million, which is due from a full requirements customer.

The PVNGS lessor notes are not exposed to credit risk, since the notes are repaid as PNM makes payments on the underlying leases. Other investments have no significant counterparty credit risk.

Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of long-term debt instruments for PNMR, PNM, and TNMP would increase by 2.5%, 2.4%, and 3.5%, if interest rates were to decline by 50 basis points from their levels at December 31, 2013. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. As described in Note 6, TNMP has long-term debt of $50.0 million that bears interest at a variable rate. However, TNMP has also entered into a hedging arrangement that effectively results in this debt bearing interest at a fixed rate, thereby eliminating interest rate risk. At February 21, 2014, PNMR, PNM, and TNMP had zero, $69.4 million, and zero of short-term debt outstanding under their revolving credit facilities, which allow for a maximum aggregate borrowing capacity of $300.0 million for PNMR, $400.0 million for PNM, and $75.0 million for TNMP. PNM also had borrowings of $25.0 million under the $50.0 million PNM New Mexico Credit Facility at February 21, 2014. The revolving credit facilities, the PNM New Mexico Credit Facility, the $75.0 million PNM Term Loan, and the $100.0 million PNMR Term Loan Agreement bear interest at variable rates, which averaged 1.01% for the PNMR Term Loan Agreement, 1.41% for the PNM Revolving Credit Facility, 1.41% for the PNM New Mexico Credit Facility, and 1.41% for the PNM Term Loan on February 21, 2014 borrowings, and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The investments held by PNM in trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits had an estimated fair value of $858.2 million at December 31, 2013, of which 52.0% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2013, the decrease in the fair value of the fixed-rate securities would be 5.7%, or $25.4 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $76.0 million at December 31, 2013, of which 46.6% were fixed-rate debt securities that subject TNMP to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2013, the decrease in the fair value of the fixed-rate securities would be 6.3%, or $2.2 million.

PNM and TNMP do not directly recover or return through rates any losses or gains on the securities, including equity and alternative investments discussed below, in the trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits. However, the overall performance of these trusts does enter into the periodic determinations of expense and funding levels, which are factored into the rate making process to the extent applicable to regulated operations. PNM and TNMP are at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market and alternatives investment risks discussed below to the extent not ultimately recovered through rates charged to customers.

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation and trusts established for PNM’s and TNMP’s pension and post-employment benefits plans include certain equity securities at December 31, 2013. These equity securities expose PNM and TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 36.3% and 31.0% of the securities held by the various PNM and TNMP trusts as of December 31, 2013. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $31.2 million for PNM and $2.4 million for TNMP.

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There was a significant decline in the general price levels of marketable equity securities in late 2008 and in early 2009. The impacts of these declines were considered in the funding and expense valuations performed for 2011 and 2012, which resulted in reduced income or increased expense related to the pension plans being recorded and required increased levels of funding beginning in 2010.

Alternatives Investment Risk

The Company had 15.4% of its pension assets invested in the alternatives asset class as of December 31, 2013. The Company has changed the target for this class to 14.8%. This includes real estate, private equity, and hedge funds. These investments are limited partner structures that are multi-manager multi-strategy funds. This investment approach gives broad diversification and minimizes risk compared to a direct investment in any one component of the funds. The general partner oversees the selection and monitoring of the underlying managers. The Company’s Corporate Investment Committee, assisted by its investment consultant, monitors the performance of the funds and general partner’s investment process. There is risk associated with these funds due to the nature of the strategies and techniques and the use of investments that do not have readily determinable fair value. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $9.6 million. The valuation of the alternative asset class was also impacted by the significant decline in the general price levels of marketable equity securities in 2008 and 2009.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX



		Page
Management’s Annual Reports on Internal Control Over Financial Reporting		B- 2
Reports of Independent Registered Public Accounting Firms		B- 5
Financial Statements:
PNM Resources, Inc. and Subsidiaries
Consolidated Statements of Earnings		B- 12
Consolidated Statements of Comprehensive Income		B- 13
Consolidated Statements of Cash Flows		B- 14
Consolidated Balance Sheets		B- 16
Consolidated Statements of Changes in Equity		B- 18
Public Service Company of New Mexico and Subsidiaries
Consolidated Statements of Earnings		B- 19
Consolidated Statements of Comprehensive Income		B- 20
Consolidated Statements of Cash Flows		B- 21
Consolidated Balance Sheets		B- 23
Consolidated Statements of Changes in Equity		B- 25
Texas-New Mexico Power Company and Subsidiaries
Consolidated Statements of Earnings		B- 26
Consolidated Statements of Comprehensive Income		B- 27
Consolidated Statements of Cash Flows		B- 28
Consolidated Balance Sheets		B- 30
Consolidated Statements of Changes in Common Stockholder’s Equity		B- 32
Notes to Consolidated Financial Statements		B- 33
Supplementary Data:
Reports of Independent Registered Public Accounting Firms on Schedules		B- 122
Schedule I - Condensed Financial Information of Parent Company		B- 124
Schedule II - Valuation and Qualifying Accounts		B- 127

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of PNM Resources, Inc. and subsidiaries (“PNMR”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.

Management assessed the effectiveness of PNMR’s internal control over financial reporting based on the Internal Control – Integrated Framework (1992) set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that PNMR’s internal control over financial reporting was effective as of December 31, 2013.

KPMG LLP, an independent registered public accounting firm, has issued an attestation report on PNMR’s internal control over financial reporting which is included herein.

/s/ Patricia K. Collawn

Patricia K. Collawn,

Chairman, President, and Chief Executive Officer

/s/ Charles Eldred

Charles Eldred

Executive Vice President and

Chief Financial Officer

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Public Service Company of New Mexico and subsidiaries (“PNM”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.

Management assessed the effectiveness of PNM’s internal control over financial reporting based on the Internal Control – Integrated Framework (1992) set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that PNM’s internal control over financial reporting was effective as of December 31, 2013.

/s/ Patricia K. Collawn

Patricia K. Collawn,

President and Chief Executive Officer

/s/ Charles Eldred

Charles Eldred

Executive Vice President and

Chief Financial Officer

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Texas-New Mexico Power Company and subsidiaries (“TNMP”) is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended.

Management assessed the effectiveness of TNMP’s internal control over financial reporting based on the Internal Control – Integrated Framework (1992) set forth by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment performed, management concludes that TNMP’s internal control over financial reporting was effective as of December 31, 2013.

/s/ Patricia K. Collawn

Patricia K. Collawn,

Chief Executive Officer

/s/ Thomas G. Sategna

Thomas G. Sategna

Vice President and Controller

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

PNM Resources, Inc:

We have audited PNM Resources, Inc and subsidiaries (the Company) internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, PNM Resources, Inc and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Company as of December 31, 2013, the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended, and our report dated February 28, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

PNM Resources, Inc:

We have audited the accompanying consolidated balance sheet of PNM Resources, Inc and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of PNM Resources, Inc and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PNM Resources, Inc and subsidiaries internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

PNM Resources, Inc.

Albuquerque, New Mexico

We have audited the accompanying consolidated balance sheets of PNM Resources, Inc. and subsidiaries (the "Company") as of December 31, 2012, and the related consolidated statements of earnings, comprehensive income, changes in equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PNM Resources, Inc. and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2013

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Public Service Company of New Mexico:

We have audited the accompanying consolidated balance sheet of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of New Mexico and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Company of New Mexico

Albuquerque, New Mexico

We have audited the accompanying consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the "Company") as of December 31, 2012, and the related consolidated statements of earnings, comprehensive income, changes in equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Mexico and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2013

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder

Texas-New Mexico Power Company:

We have audited the accompanying consolidated balance sheet of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in common stockholder’s equity, and consolidated statement of cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Texas-New Mexico Power Company and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Texas-New Mexico Power Company

Lewisville, Texas

We have audited the accompanying consolidated balance sheets of Texas-New Mexico Power Company and subsidiaries (the "Company") as of December 31, 2012, and the related consolidated statements of earnings, comprehensive income, changes in common stockholder’s equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Texas-New Mexico Power Company and subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2013

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS



	Year Ended December 31,
	2013			2012			2011
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,387,923		$	1,342,403		$	1,700,619
Operating Expenses:
Cost of energy	432,316			399,850			692,922
Administrative and general	179,210			187,740			257,774
Energy production costs	175,819			185,417			180,850
Regulatory disallowances	12,235			—			21,402
Depreciation and amortization	166,881			164,173			157,047
Transmission and distribution costs	70,124			71,125			69,693
Taxes other than income taxes	64,496			60,377			63,632
Total operating expenses	1,101,081			1,068,682			1,443,320
Operating income	286,842			273,721			257,299
Other Income and Deductions:
Interest income	10,043			13,072			15,515
Gains on available-for-sale securities	10,612			12,965			8,985
Other income	10,572			12,746			5,309
Gain on sale of First Choice	—			1,012			174,925
Other (deductions)	(21,552		)	(17,636		)	(24,715		)
Net other income and deductions	9,675			22,159			180,019
Interest Charges	121,448			120,845			124,849
Earnings before Income Taxes	175,069			175,035			312,469
Income Taxes	59,513			54,910			121,535
Net Earnings	115,556			120,125			190,934
(Earnings) Attributable to Valencia Non-controlling Interest	(14,521		)	(14,050		)	(14,047		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Net Earnings Attributable to PNMR	$	100,507		$	105,547		$	176,359
Net Earnings Attributable to PNMR per Common Share:
Basic	$	1.26		$	1.32		$	1.98
Diluted	$	1.25		$	1.31		$	1.96

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Net Earnings	$	115,556		$	120,125		$	190,934
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(10,855), $(15,262), and $(13,577)	16,564			23,286			20,718
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $4,734, $14,755, and $13,956	(7,222		)	(22,514		)	(21,295		)
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit of $(6,781), $11,910 and $1,187	10,355			(18,174		)	(1,771		)
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,524), $(1,825) and $(1,699)	3,840			2,786			2,593
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $98, $153, and $349	(181		)	(275		)	(653		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(73), $(65), and $(1,230)	134			117			2,218
Total Other Comprehensive Income (Loss)	23,490			(14,774		)	1,810
Comprehensive Income	139,046			105,351			192,744
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,521		)	(14,050		)	(14,047		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Comprehensive Income Attributable to PNMR	$	123,997		$	90,773		$	178,169

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	115,556		$	120,125		$	190,934
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	208,173			206,499			195,366
Bad debt expense	2,849			3,367			24,116
Deferred income tax expense	60,430			56,243			124,424
(Gain) on sale of First Choice	—			(1,012		)	(174,925		)
Net unrealized (gains) on derivatives	(1,866		)	(1,598		)	(8,713		)
Realized (gains) on available-for-sale securities	(10,612		)	(12,965		)	(8,985		)
Loss on reacquired debt	3,253			—			9,209
Abandonment of leased premises	—			7,411			—
Stock based compensation expense	5,320			3,585			6,556
Regulatory disallowances	12,235			—			21,402
Other, net	(4,496		)	(4,165		)	(3,497		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(7,562		)	(2,547		)	(70,734		)
Materials, supplies, and fuel stock	(7,580		)	(5,412		)	(2,200		)
Other current assets	8,577			(2,598		)	(21,979		)
Other assets	(12,801		)	(30,778		)	(15,835		)
Accounts payable	4,484			14,020			20,969
Accrued interest and taxes	91,537			255			7,304
Other current liabilities	(19,648		)	(19,905		)	3,460
Proceeds from governmental grants	—			21,567			2,103
Other liabilities	(61,262		)	(70,743		)	(6,735		)
Net cash flows from operating activities	386,587			281,349			292,240
Cash Flows From Investing Activities:
Utility plant additions	(348,039		)	(308,909		)	(326,931		)
Proceeds from sales of available-for-sale securities	271,140			167,330			145,286
Purchases of available-for-sale securities	(282,000		)	(176,748		)	(149,185		)
Proceeds from sale of First Choice	—			4,034			329,281
Transaction costs for sale of First Choice	—			—			(10,930		)
Return of principal on PVNGS lessor notes	23,357			23,455			32,274
Other, net	4,096			4,943			(17		)
Net cash flows from investing activities	(331,446		)	(285,895		)	19,778

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Financing Activities:
Short-term loan	—			100,000			—
Revolving credit facilities borrowings (repayments), net	(9,500		)	(24,000		)	(139,300		)
Long-term borrowings	75,000			20,000			210,000
Repayment of long-term debt	(29,468		)	(22,387		)	(110,752		)
Cash paid in debt exchange	(13,048		)	—			—
Purchase of preferred stock	—			—			(73,475		)
Purchase of common stock	—			—			(125,683		)
Proceeds from stock option exercise	4,618			11,684			5,622
Purchases to satisfy awards of common stock	(13,807		)	(25,168		)	(10,104		)
Dividends paid	(51,508		)	(45,137		)	(45,656		)
Valencia’s transactions with its owner	(18,335		)	(15,630		)	(16,801		)
Other, net	(5,545		)	(922		)	(6,182		)
Net cash flows from financing activities	(61,593		)	(1,560		)	(312,331		)
Change in Cash and Cash Equivalents	(6,452		)	(6,106		)	(313		)
Cash and Cash Equivalents at Beginning of Year	8,985			15,091			15,404
Cash and Cash Equivalents at End of Year	$	2,533		$	8,985		$	15,091
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	99,382		$	113,265		$	116,391
Income taxes paid (refunded), net	$	(95,327	)	$	5,302		$	(5,527	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	6,006		$	(17,983	)	$	24,768
Premium on long-term debt incurred in connection with debt exchange	$	36,297

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

	December 31,
	2013		2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,533	$	8,985
Accounts receivable, net of allowance for uncollectible accounts of $1,423 and $1,751	90,251		87,093
Unbilled revenues	58,806		57,266
Other receivables	53,909		53,332
Materials, supplies, and fuel stock	67,223		59,643
Regulatory assets	24,416		39,120
Commodity derivative instruments	4,064		3,785
Income taxes receivable	7,066		101,477
Current portion of accumulated deferred income taxes	58,681		—
Other current assets	34,590		31,490
Total current assets	401,539		442,191
Other Property and Investments:
Investment in PVNGS lessor notes	32,200		54,325
Available-for-sale securities	226,855		192,511
Other investments	1,835		5,599
Non-utility property, net of accumulated depreciation of $61 and $131	4,353		4,487
Total other property and investments	265,243		256,922
Utility Plant:
Plant in service and plant held for future use	5,563,061		5,313,796
Less accumulated depreciation and amortization	1,838,832		1,774,223
	3,724,229		3,539,573
Construction work in progress	132,080		125,287
Nuclear fuel, net of accumulated amortization of $47,347 and $42,644	77,602		81,627
Net utility plant	3,933,911		3,746,487
Deferred Charges and Other Assets:
Regulatory assets	523,955		555,577
Goodwill	278,297		278,297
Commodity derivative instruments	3,002		352
Other deferred charges	94,263		92,757
Total deferred charges and other assets	899,517		926,983
	$	5,500,210	$	5,372,583

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	149,200		$	158,700
Current installments of long-term debt	75,000			2,530
Accounts payable	109,666			99,177
Customer deposits	13,456			18,176
Accrued interest and taxes	49,600			52,003
Regulatory liabilities	1,081			15,173
Commodity derivative instruments	2,699			1,000
Dividends declared	14,864			11,679
Current portion of accumulated deferred income taxes	—			258
Other current liabilities	77,105			75,407
Total current liabilities	492,671			434,103
Long-term Debt	1,670,420			1,669,760
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	801,408			701,545
Accumulated deferred investment tax credits	25,855			14,242
Regulatory liabilities	460,649			423,460
Asset retirement obligations	96,135			85,893
Accrued pension liability and postretirement benefit cost	80,046			224,565
Commodity derivative instruments	1,094			1,933
Other deferred credits	109,805			116,523
Total deferred credits and other liabilities	1,574,992			1,568,161
Total liabilities	3,738,083			3,672,024
Commitments and Contingencies (See Note 16)
Cumulative Preferred Stock of Subsidiary
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNMR common stockholders’ equity:
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369			1,182,819
Accumulated other comprehensive income (loss), net of income taxes	(58,140		)	(81,630		)
Retained earnings	553,340			506,998
Total PNMR common stockholders’ equity	1,673,569			1,608,187
Non-controlling interest in Valencia	77,029			80,843
Total equity	1,750,598			1,689,030
	$	5,500,210		$	5,372,583

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Attributable to PNMR															Non- controlling Interest in Valencia
				PNMR Common Stockholders’ Equity
	Preferred Stock, Series A			Common Stock			AOCI			Retained Earnings			Total						Total Equity
	(In thousands)
Balance at December 31, 2010	$	100,000		$	1,290,465		$	(68,666	)	$	314,943		$	1,536,742		$	85,177		$	1,721,919
Proceeds from stock option exercise	—			5,622			—			—			5,622			—			5,622
Purchases to satisfy awards of common stock	—			(10,104		)	—			—			(10,104		)	—			(10,104		)
Stock based compensation expense	—			6,556			—			—			6,556			—			6,556
Valencia’s transactions with its owner	—			—			—			—			—			(16,801		)	(16,801		)
Purchase of preferred stock	(100,000		)	26,490			—			—			26,490			—			(73,510		)
Purchase of common stock	—			(125,838		)	—			—			(125,838		)	—			(125,838		)
Net earnings excluding subsidiary preferred stock dividends	—			—			—			176,887			176,887			14,047			190,934
Subsidiary preferred stock dividends	—			—			—			(528		)	(528		)	—			(528		)
Total other comprehensive income	—			—			1,810			—			1,810			—			1,810
Dividends declared on common stock	—			—			—			(43,652		)	(43,652		)	—			(43,652		)
Balance at December 31, 2011	—			1,193,191			(66,856		)	447,650			1,573,985			82,423			1,656,408
Proceeds from stock option exercise	—			11,684			—			—			11,684			—			11,684
Purchases to satisfy awards of common stock	—			(25,168		)	—			—			(25,168		)	—			(25,168		)
Excess tax (shortfall) from stock-based payment arrangements	—			(473		)	—			—			(473		)	—			(473		)
Stock based compensation expense	—			3,585			—			—			3,585			—			3,585
Valencia’s transactions with its owner	—			—			—			—			—			(15,630		)	(15,630		)
Net earnings excluding subsidiary preferred stock dividends	—			—			—			106,075			106,075			14,050			120,125
Subsidiary preferred stock dividends	—			—			—			(528		)	(528		)	—			(528		)
Total other comprehensive income (loss)	—			—			(14,774		)	—			(14,774		)	—			(14,774		)
Dividends declared on common stock	—			—			—			(46,199		)	(46,199		)	—			(46,199		)
Balance at December 31, 2012	—			1,182,819			(81,630		)	506,998			1,608,187			80,843			$	1,689,030
Proceeds from stock option exercise	—			4,618			—			—			4,618			—			4,618
Purchases to satisfy awards of common stock	—			(13,807		)	—			—			(13,807		)	—			(13,807		)
Excess tax (shortfall) from stock-based payment arrangements	—			(581		)	—			—			(581		)	—			(581		)
Stock based compensation expense	—			5,320			—			—			5,320			—			5,320
Valencia’s transactions with its owner	—			—			—			—			—			(18,335		)	(18,335		)
Net earnings excluding subsidiary preferred stock dividends	—			—			—			101,035			101,035			14,521			115,556
Subsidiary preferred stock dividends	—			—			—			(528		)	(528		)	—			(528		)
Total other comprehensive income	—			—			23,490			—			23,490			—			23,490
Dividends declared on common stock	—			—			—			(54,165		)	(54,165		)	—			(54,165		)
Balance at December 31, 2013	$	—		$	1,178,369		$	(58,140	)	$	553,340		$	1,673,569		$	77,029		$	1,750,598

The accompanying notes, as they relate to PNMR, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF EARNINGS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Electric Operating Revenues	$	1,116,312		$	1,092,264		$	1,057,289
Operating Expenses:
Cost of energy	374,710			353,649			362,237
Administrative and general	157,144			169,285			157,217
Energy production costs	175,819			185,403			180,802
Regulatory disallowances	12,235			—			17,479
Depreciation and amortization	103,826			97,291			94,787
Transmission and distribution costs	45,936			46,039			45,768
Taxes other than income taxes	37,457			34,715			37,556
Total operating expenses	907,127			886,382			895,846
Operating income	209,185			205,882			161,443
Other Income and Deductions:
Interest income	10,182			13,243			15,562
Gains on available-for-sale securities	10,612			12,965			8,985
Other income	7,650			8,126			2,220
Other (deductions)	(6,974		)	(7,801		)	(6,896		)
Net other income and deductions	21,470			26,533			19,871
Interest Charges	79,175			76,101			75,349
Earnings before Income Taxes	151,480			156,314			105,965
Income Taxes	48,804			50,713			37,427
Net Earnings	102,676			105,601			68,538
(Earnings) Attributable to Valencia Non-controlling Interest	(14,521		)	(14,050		)	(14,047		)
Net Earnings Attributable to PNM	88,155			91,551			54,491
Preferred Stock Dividends Requirements	(528		)	(528		)	(528		)
Net Earnings Available for PNM Common Stock	$	87,627		$	91,023		$	53,963

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Year ended December 31,
	2013			2012			2011
	(In thousands)
Net Earnings	$	102,676		$	105,601		$	68,538
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(10,855), $(15,262), and $(13,577)	16,564			23,286			20,718
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $4,734, $14,755, and $13,956	(7,222		)	(22,514		)	(21,295		)
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit of $(6,781), $11,910 and $1,334	10,355			(18,174		)	(2,035		)
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,524), $(1,825) and $(1,694)	3,840			2,786			2,584
Fair Value Adjustment for Designated Cash Flow Hedges:
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $0, and $(11)	—			—			16
Total Other Comprehensive Income (Loss)	23,537			(14,616		)	(12		)
Comprehensive Income	126,213			90,985			68,526
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,521		)	(14,050		)	(14,047		)
Comprehensive Income Attributable to PNM	$	111,692		$	76,935		$	54,479

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	102,676		$	105,601		$	68,538
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	136,732			129,514			123,216
Deferred income tax expense	50,043			65,479			90,567
Net unrealized (gains) losses on derivatives	(1,866		)	(1,598		)	(3,822		)
Realized (gains) on available-for-sale securities	(10,612		)	(12,965		)	(8,985		)
Regulatory disallowances	12,235			—			17,479
Other, net	(1,614		)	(170		)	1,658
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(3,021		)	(4,756		)	(23,487		)
Materials, supplies, and fuel stock	(7,730		)	(5,268		)	(2,067		)
Other current assets	8,556			(3,014		)	(14,916		)
Other assets	(13,363		)	(27,338		)	(795		)
Accounts payable	2,807			11,028			12,524
Accrued interest and taxes	72,740			47,666			(45,579		)
Other current liabilities	(27,376		)	(2,539		)	15,216
Proceeds from governmental grants	—			21,567			2,103
Other liabilities	(59,753		)	(54,787		)	(18,612		)
Net cash flows from operating activities	260,454			268,420			213,038
Cash Flows From Investing Activities:
Utility plant additions	(239,906		)	(196,800		)	(251,345		)
Proceeds from sales of available-for-sale securities	271,140			167,330			145,286
Purchases of available-for-sale securities	(282,000		)	(176,748		)	(149,185		)
Return of principal on PVNGS lessor notes	23,357			23,455			32,274
Other, net	3,843			2,406			1,782
Net cash flows from investing activities	(223,566		)	(180,357		)	(221,188		)

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	28,100			(44,900		)	(124,000		)
Short-term borrowings (repayments) - affiliate, net	32,500			—			—
Long-term borrowings	75,000			20,000			160,000
Repayment of long-term debt	—			(20,000		)	—
Equity contribution from parent	—			—			43,000
Valencia’s transactions with its owner	(18,335		)	(15,630		)	(16,801		)
Dividends paid	(155,556		)	(34,961		)	(47,862		)
Other, net	(2,534		)	(921		)	(4,216		)
Net cash flows from financing activities	(40,825		)	(96,412		)	10,121

Change in Cash and Cash Equivalents	(3,937		)	(8,349		)	1,971
Cash and Cash Equivalents at Beginning of Year	3,958			12,307			10,336
Cash and Cash Equivalents at End of Year	$	21		$	3,958		$	12,307

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	71,306		$	73,036		$	69,995
Income taxes paid (refunded), net	$	(77,434	)	$	(63,113	)	$	(1,541	)

Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	7,921		$	(19,732	)	$	18,164

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED BALANCE SHEETS

	December 31,
	2013		2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	21	$	3,958
Accounts receivable, net of allowance for uncollectible accounts of $1,423 and $1,751	70,126		69,876
Unbilled revenues	48,992		49,085
Other receivables	52,964		50,975
Affiliate receivables	10,054		9,050
Materials, supplies, and fuel stock	64,520		56,790
Regulatory assets	19,394		36,490
Commodity derivative instruments	4,064		3,785
Income taxes receivable	4,030		80,223
Current portion of accumulated deferred income taxes	43,827		—
Other current assets	30,510		27,457
Total current assets	348,502		387,689
Other Property and Investments:
Investment in PVNGS lessor notes	32,200		54,325
Available-for-sale securities	226,855		192,511
Other investments	445		494
Non-utility property	976		976
Total other property and investments	260,476		248,306
Utility Plant:
Plant in service and plant held for future use	4,314,016		4,133,532
Less accumulated depreciation and amortization	1,402,531		1,355,240
	2,911,485		2,778,292
Construction work in progress	107,344		102,329
Nuclear fuel, net of accumulated amortization of $47,347 and $42,644	77,602		81,627
Net utility plant	3,096,431		2,962,248
Deferred Charges and Other Assets:
Regulatory assets	384,217		431,956
Goodwill	51,632		51,632
Commodity derivative instruments	3,002		352
Other deferred charges	83,356		81,724
Total deferred charges and other assets	522,207		565,664
	$	4,227,616	$	4,163,907

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	49,200		$	21,100
Short-term debt - affiliate	32,500			—
Current installments of long-term debt	75,000			—
Accounts payable	84,643			73,914
Affiliate payables	20,498			25,340
Customer deposits	13,456			18,176
Accrued interest and taxes	27,665			30,320
Regulatory liabilities	1,081			15,172
Commodity derivative instruments	2,699			1,000
Dividends declared	132			132
Current portion of accumulated deferred income taxes	—			3,447
Other current liabilities	50,392			54,150
Total current liabilities	357,266			242,751
Long-term Debt	1,215,618			1,215,579
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	651,239			573,881
Accumulated deferred investment tax credits	25,855			14,242
Regulatory liabilities	414,611			379,841
Asset retirement obligations	95,225			85,042
Accrued pension liability and postretirement benefit cost	76,611			208,618
Commodity derivative instruments	1,094			1,933
Other deferred credits	91,340			95,585
Total deferred credits and liabilities	1,355,975			1,359,142
Total liabilities	2,928,859			2,817,472
Commitments and Contingencies (See Note 16)
Cumulative Preferred Stock
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNM common stockholder’s equity:
Common stock (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares)	1,061,776			1,061,776
Accumulated other comprehensive income (loss), net of income tax	(57,877		)	(81,414		)
Retained earnings	206,300			273,701
Total PNM common stockholder’s equity	1,210,199			1,254,063
Non-controlling interest in Valencia	77,029			80,843
Total equity	1,287,228			1,334,906
	$	4,227,616		$	4,163,907

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Attributable to PNM
	Common Stock		AOCI			Retained Earnings			Total PNM Common Stockholder’s Equity			Non- controlling Interest in Valencia			Total Equity
	(In thousands)
Balance at December 31, 2010	$	1,018,776	$	(66,786	)	$	171,359		$	1,123,349		$	85,177		$	1,208,526
Valencia’s transactions with its owner	—		—			—			—			(16,801		)	(16,801		)
Net earnings	—		—			54,491			54,491			14,047			68,538
Total other comprehensive income (loss)	—		(12		)	—			(12		)	—			(12		)
Equity contributions from parent	43,000		—			—			43,000			—			43,000
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(8,211		)	(8,211		)	—			(8,211		)
Balance at December 31, 2011	1,061,776		(66,798		)	217,111			1,212,089			82,423			1,294,512
Valencia’s transactions with its owner	—		—			—			—			(15,630		)	(15,630		)
Net earnings	—		—			91,551			91,551			14,050			105,601
Total other comprehensive income (loss)	—		(14,616		)	—			(14,616		)	—			(14,616		)
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(34,433		)	(34,433		)	—			(34,433		)
Balance at December 31, 2012	1,061,776		(81,414		)	273,701			1,254,063			80,843			1,334,906
Valencia’s transactions with its owner	—		—			—			—			(18,335		)	(18,335		)
Net earnings	—		—			88,155			88,155			14,521			102,676
Total other comprehensive income	—		23,537			—			23,537			—			23,537
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(155,028		)	(155,028		)	—			(155,028		)
Balance at December 31, 2013	$	1,061,776	$	(57,877	)	$	206,300		$	1,210,199		$	77,029		$	1,287,228

The accompanying notes, as they relate to PNM, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF EARNINGS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Electric Operating Revenues:
Non-affiliates	$	271,611		$	250,140		$	204,045
Affiliate	—			—			33,813
Total electric operating revenues	271,611			250,140			237,858
Operating Expenses:
Cost of energy	57,606			46,201			41,166
Administrative and general	44,635			40,775			39,485
Regulatory disallowances	—			—			3,923
Depreciation and amortization	50,219			49,340			44,616
Transmission and distribution costs	24,188			25,086			23,915
Taxes other than income taxes	22,778			21,218			20,911
Total operating expenses	199,426			182,620			174,016
Operating income	72,185			67,520			63,842
Other Income and Deductions:
Interest income	—			1			2
Other income	2,377			4,698			1,753
Other (deductions)	(458		)	(1,959		)	(173		)
Net other income and deductions	1,919			2,740			1,582
Interest Charges	27,393			28,161			29,286
Earnings Before Income Taxes	46,711			42,099			36,138
Income Taxes	17,621			15,352			13,881
Net Earnings	$	29,090		$	26,747		$	22,257

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Net Earnings	$	29,090		$	26,747		$	22,257
Other Comprehensive Income (Loss):
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit of $0, $0 and $(147)	—			—			267
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $0, $0 and $(5)	—			—			8
Fair Value Adjustment for Designated Cash Flow Hedge:
Change in fair value, net of income tax (expense) benefit of $98, $153, and $430	(181		)	(275		)	(777		)
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit) of $(73), $(65), and $(1,068)	134			117			1,929
Total Other Comprehensive Income (Loss)	(47		)	(158		)	1,427
Comprehensive Income	$	29,043		$	26,589		$	23,684

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	29,090		$	26,747		$	22,257
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	54,395			54,396			48,572
Regulatory disallowances	—			—			3,923
Deferred income tax expense	20,662			4,378			15,478
Other, net	(30		)	(889		)	(532		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(4,542		)	2,208			(9,130		)
Materials and supplies	150			(143		)	77
Other current assets	(1,137		)	(3,515		)	4,777
Other assets	941			(3,145		)	(3,247		)
Accounts payable	3,709			(666		)	2,225
Accrued interest and taxes	(6,713		)	9,825			(2,520		)
Other current liabilities	(3,197		)	(2,106		)	513
Other liabilities	460			4,311			(611		)
Net cash flows from operating activities	93,788			91,401			81,782
Cash Flows From Investing Activities:
Utility plant additions	(89,117		)	(92,973		)	(67,407		)
Net cash flows from investing activities	(89,117		)	(92,973		)	(67,407		)

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2013			2012			2011
	(In thousands)

Cash Flow From Financing Activities:
Short-term borrowings (repayments) – affiliate, net	1,100			27,600			(500		)
Long-term borrowings	—			—			50,000
Repayment of long-term debt	—			—			(50,000		)
Cash paid in debt exchange	(13,048		)	—			—
Equity contribution from parent	13,800			—			—
Dividends paid	(3,726		)	(26,028		)	(13,714		)
Other, net	(2,797		)	—			(161		)
Net cash flows from financing activities	(4,671		)	1,572			(14,375		)
Change in Cash and Cash Equivalents	—			—			—
Cash and Cash Equivalents at Beginning of Year	1			1			1
Cash and Cash Equivalents at End of Year	$	1		$	1		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	14,049		$	25,360		$	27,236
Income taxes paid, (refunded) net	$	4,484		$	1,848		$	1,466

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	141		$	(2,749	)	$	4,501

Premium on long-term debt incurred in connection with debt exchange	$	36,297

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED BALANCE SHEETS

	December 31,
	2013		2012
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	20,125		17,217
Unbilled revenues	9,814		8,181
Other receivables	1,246		2,359
Materials and supplies	2,703		2,853
Regulatory assets	5,022		2,630
Current portion of accumulated deferred income taxes	6,501		1,131
Other current assets	980		1,107
Total current assets	46,392		35,479
Other Property and Investments:
Other investments	245		281
Non-utility property	2,240		2,240
Total other property and investments	2,485		2,521
Utility Plant:
Plant in service and plant held for future use	1,074,193		1,009,108
Less accumulated depreciation and amortization	352,105		339,315
	722,088		669,793
Construction work in progress	16,790		19,801
Net utility plant	738,878		689,594
Deferred Charges and Other Assets:
Regulatory assets	139,738		123,621
Goodwill	226,665		226,665
Other deferred charges	8,273		8,349
Total deferred charges and other assets	374,676		358,635
	$	1,162,431	$	1,086,229

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC. CONSOLIDATED BALANCE SHEETS

	December 31,
	2013			2012
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	29,400		$	28,300
Accounts payable	12,543			8,848
Affiliate payables	3,181			4,381
Accrued interest and taxes	23,778			30,491
Other current liabilities	8,999			8,854
Total current liabilities	77,901			80,874
Long-term Debt	336,036			311,589
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	190,197			163,710
Regulatory liabilities	46,038			43,619
Asset retirement obligations	782			732
Accrued pension liability and postretirement benefit cost	3,435			15,947
Other deferred credits	5,111			5,944
Total deferred credits and other liabilities	245,563			229,952
Total liabilities	659,500			622,415
Commitments and Contingencies (See Note 16)
Common Stockholder’s Equity:
Common stock ($10 par value; 12,000,000 shares authorized; issued and outstanding 6,358 shares)	64			64
Paid-in-capital	404,166			390,366
Accumulated other comprehensive income (loss), net of income tax	(263		)	(216		)
Retained earnings	98,964			73,600
Total common stockholder’s equity	502,931			463,814
	$	1,162,431		$	1,086,229

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER’S EQUITY



	Common Stock		Paid-in Capital			AOCI			Retained Earnings			Total Common Stockholder’s Equity
						(In thousands)
Balance at December 31, 2010	$	64	$	430,108		$	(1,485	)	$	24,596		$	453,283
Net earnings	—		—			—			22,257			22,257
Total other comprehensive income	—		—			1,427			—			1,427
Dividends declared on common stock	—		(13,714		)	—			—			(13,714		)
Balance at December 31, 2011	64		416,394			(58		)	46,853			463,253
Net earnings	—		—			—			26,747			26,747
Total other comprehensive income (loss)	—		—			(158		)	—			(158		)
Dividends declared on common stock	—		(26,028		)	—			—			(26,028		)
Balance at December 31, 2012	64		390,366			(216		)	73,600			463,814
Net earnings	—		—			—			29,090			29,090
Total other comprehensive income (loss)	—		—			(47		)	—			(47		)
Equity contributions from parent	—		13,800			—			—			13,800
Dividends declared on common stock	—		—			—			(3,726		)	(3,726		)
Balance at December 31, 2013	$	64	$	404,166		$	(263	)	$	98,964		$	502,931

The accompanying notes, as they relate to TNMP, are an integral part of these consolidated financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(1)	Summary of the Business and Significant Accounting Policies

Nature of Business

PNMR is an investor-owned holding company of energy and energy-related businesses. PNMR’s primary subsidiaries are PNM and TNMP. PNM is a public utility with regulated operations primarily engaged in the generation, transmission, and distribution of electricity. TNMP is a wholly owned subsidiary of TNP, which is a holding company that is wholly owned by PNMR. TNMP provides regulated transmission and distribution services in Texas. PNMR completed the sale of First Choice (Note 3), which was also a subsidiary of TNP, on November 1, 2011. First Choice was a competitive REP operating in Texas. Until September 23, 2011, PNMR owned 50% of Optim Energy (Note 20), which was focused on unregulated electric operations, principally within the areas of Texas covered by ERCOT. PNMR’s common stock trades on the New York Stock Exchange under the symbol PNM.

Financial Statement Preparation and Presentation

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated.

The Notes to Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. For discussion purposes, this report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such.

Certain amounts in the 2012 and 2011 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2013 financial statement presentation.

GAAP defines subsequent events as events or transactions that occur after the balance sheet date but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.

Principles of Consolidation

The Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia (Note 9). PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments. These services are billed at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include transmission and distribution services; lease, interest, and income tax sharing payments; and equity transactions. All intercompany transactions and balances have been eliminated. See Note 18.

Accounting for the Effects of Certain Types of Regulation

The Company maintains its accounting records in accordance with the uniform system of accounts prescribed by FERC and adopted by the NMPRC and PUCT.

Certain of the Company’s operations are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to the regulated operations. Regulators may assign costs to accounting periods that differ from accounting methods applied by non-regulated utilities. When it is probable that regulators will permit recovery of costs through future rates, costs that otherwise would be expensed are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred. Regulatory assets and liabilities are amortized into earnings over the authorized recovery period.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of FERC, the NMPRC, and the PUCT. Information on regulatory assets and regulatory liabilities is contained in Note 4.

In some circumstances, regulators allow a requested increase in rates to be implemented, subject to refund, before the regulatory process has been completed and a decision rendered by the regulator. When this occurs, the Company assesses the possible outcomes of the rate proceeding. The Company records a provision for refund to the extent the amounts being collected, subject to refund, exceed the amount the Company determines is probable of ultimately being allowed by the regulator.

Cash and Cash Equivalents

Investments in highly liquid investments with original maturities of three months or less at the date of purchase are considered cash equivalents.

Utility Plant

Utility plant is stated at cost, which includes capitalized payroll-related costs such as taxes, pension, and other fringe benefits, administrative costs, and AFUDC where authorized by rate regulation.

Repairs, including major maintenance activities, and minor replacements of property are expensed when incurred, except as required by regulators for ratemaking purposes. Major replacements are charged to utility plant. Gains or losses resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to accumulated depreciation.

Allowance for Funds Used During Construction

As provided by the FERC uniform systems of accounts, AFUDC is charged to regulated utility plant for construction projects. This allowance is a non-cash item designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. It represents the cost of borrowed funds (allowance for borrowed funds used during construction) and a return on other funds (allowance for equity funds used during construction). The allowance for borrowed funds used during construction is recorded in interest charges and the allowance for equity funds used during construction is recorded in other income on the Consolidated Statements of Earnings.

For the years ended December 31, 2013, 2012, and 2011, PNM recorded $3.3 million, $3.5 million, and $1.5 million of allowance for borrowed funds used during construction and $4.4 million, $3.8 million, and zero of allowance for equity funds used during construction. TNMP recorded $0.4 million, $0.7 million, and $0.6 million of allowance for borrowed funds used during construction and zero, $0.6 million, and $0.6 million of allowance for equity funds used during construction.

Capitalized Interest

PNMR capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC. Interest was capitalized at the overall weighted average borrowing rate of 6.9%, 6.6%, and 6.6% for 2013, 2012, and 2011. In 2013, 2012, and 2011, PNMR’s capitalized interest was $1.5 million, $1.2 million, and $0.5 million; PNM’s was $1.1 million, $0.8 million, and $0.2 million; and TNMP had no capitalized interest.

Competition Transition Charge

In connection with the adoption of Senate Bill 7 by the Texas Legislature in 1999 that deregulated electric utilities operating within ERCOT, TNMP was allowed to recover its stranded costs through the CTC and to also recover a carrying charge on the CTC. The amounts yet to be collect are recorded as regulatory assets by TNMP. TNMP’s calculation of allowable carrying charges on stranded costs recoverable from its transmission and distribution customers is based on a Texas Supreme Court ruling and the PUCT’s application of that ruling.

Materials, Supplies, and Fuel Stock

Materials and supplies relate to transmission, distribution, and generating assets. Materials and supplies are charged to inventory when purchased and are expensed or capitalized as appropriate when issued. Materials and supplies are valued using an average costing method.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Coal is valued using a rolling weighted average costing method that is updated based on the current period cost per ton. Periodic aerial surveys are performed on the coal piles and adjustments are made.

Inventories consisted of the following at December 31:



	PNMR				PNM				TNMP
	2013		2012		2013		2012		2013		2012
	(In thousands)
Coal	$	24,872	$	19,231	$	24,872	$	19,231	$	—	$	—
Materials and supplies	42,351		40,412		39,648		37,559		2,703		2,853
	$	67,223	$	59,643	$	64,520	$	56,790	$	2,703	$	2,853

Investments

In 1985 and 1986, PNM entered into eleven operating leases for interests in certain PVNGS generation facilities (Note 7). The 10.3% and 10.15% lessor notes that were issued by the owners of the assets subject to these leases were subsequently purchased by and are now held by the PVNGS Capital Trust, which is consolidated by PNM. Eight leases continue and are classified as operating leases (Note 7). The PVNGS Capital Trust intends to hold the lessor notes until such notes mature in 2015 and 2016. The PVNGS lessor notes are carried at amortized cost. Similarly, in 1985, PNM entered into two operating leases for the EIP transmission line for which the owners had issued lessor notes. In 2003, PNM acquired a 60% ownership interest in the EIP, collapsing the lease relating to it. In 2004, PNM purchased the outstanding lessor note relating to the remaining 40% interest. The remaining EIP lessor note bore interest at 10.25% and matured in 2012.

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). All of these investments are classified as available-for-sale. PNM evaluates the securities for impairment on an on-going basis. Since third party investment managers have sole discretion over the purchase and sales of the securities, PNM records a realized loss as an impairment for any security that has a market value that is less than cost at the end of each quarter. For the years ended December 31, 2013, 2012, and 2011, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $3.5 million, $4.8 million, and $12.5 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI. The available-for-sale securities are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in PNM’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions.

Investment in Optim Energy

Through September 23, 2011, PNMR accounted for its investment in Optim Energy using the equity method of accounting because PNMR’s ownership interest resulted in significant influence, but not control, over Optim Energy and its operations. On September 23, 2011, PNMR’s ownership interest in Optim Energy was reduced to 1% and PNMR began using the cost method of accounting. On January 4, 2012, ECJV acquired PNMR’s remaining 1% ownership interest at fair market value, which was determined to be zero. PNMR’s investment in Optim Energy was reduced to zero at December 31, 2010 due to the determination that the investment was fully impaired. See Note 20.

Goodwill and Other Intangible Assets

Under GAAP, the Company does not amortize goodwill. In 2011, certain intangible assets were amortized over their estimated useful lives. Goodwill and non-amortizable other intangible assets are evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill and intangible assets might be impaired. Amortizable other intangible assets are amortized over the shorter of their economic or legal lives and are evaluated for impairment when events and circumstances indicate that the assets might be impaired. See Note 21.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Asset Impairment

Tangible long-lived assets are evaluated in relation to the future undiscounted cash flows to assess recoverability when events and circumstances indicate that the assets might be impaired.

Revenue Recognition

Electric operating revenues are recorded in the period of energy delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading and the corresponding unbilled revenue are estimated. Unbilled electric revenue is estimated based on the daily generation volumes, estimated customer usage by class, weather factors, line losses, and applicable customer rates reflecting historical trends and experience.

PNM’s wholesale electricity sales are recorded as electric operating revenues and the wholesale electricity purchases are recorded as costs of energy sold. In accordance with GAAP, derivative contracts that are net settled or “booked-out” are recorded net in earnings. A book-out is the planned or unplanned netting of off-setting purchase and sale transactions. A book-out is a transmission mechanism to reduce congestion on the transmission system or administrative burden. For accounting purposes, a book-out is the recording of net revenues upon the settlement of a derivative contract.

Unrealized gains and losses on contracts that do not qualify for the normal purchases or normal sales exception or are not designated for hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power and fuel supply agreements, used to hedge generation assets and purchased power costs. Changes in the fair value of economic hedges are reflected in results of operations, with changes related to economic hedges on sales included in operating revenues and changes related to economic hedges on purchases included in cost of energy sold. The Company has no trading transactions.

Accounts Receivable and Allowance for Uncollectible Accounts

Accounts receivable consists primarily of trade receivables from customers. In the normal course of business, credit is extended to customers on a short-term basis. The Company calculates the allowance for uncollectible accounts based on historical experience and estimated default rates. The accounts receivable balances are reviewed monthly and adjustments to the allowance for uncollectible accounts and bad debt expense are made as necessary. Amounts that are deemed uncollectible are written off.

Depreciation and Amortization

PNM’s provision for depreciation and amortization of utility plant, other than nuclear fuel, is based upon composite straight-line rates approved by the NMPRC. Amortization of nuclear fuel is based on units-of-production. TNMP’s provision for depreciation and amortization of utility plant is based upon straight-line rates approved by the PUCT. Depreciation of non-utility property is computed based on the straight-line method. The provision for depreciation of certain equipment is allocated between operating expenses and construction projects based on the use of the equipment. Average straight-line rates used were as follows:



	Year ended December 31
	2013		2012		2011
PNM
Electric plant	2.27	%	2.25	%	2.24	%
Common, intangible, and general plant	4.87	%	5.35	%	6.03	%
TNMP	3.66	%	3.56	%	3.41	%

Amortization of Debt Acquisition Costs

Discount, premium, and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. Gains and losses incurred upon the early retirement of long-term debt are recognized in other income or other deductions, except for amounts attributable to NMPRC, FERC, or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Derivatives

The Company records derivative instruments, other than those designated as normal purchases or normal sales, in the balance sheet as either an asset or liability measured at their fair value. GAAP requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific hedge accounting or normal purchase or normal sale criteria are met. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 8.

The Company treats all forward electric purchases and sales contracts subject to unplanned netting or book-out by the transmission provider as derivative instruments subject to mark-to-market accounting, unless the contract qualifies for the normal exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity.

GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the economic hedge.

Decommissioning Costs

PNM owns and leases nuclear and fossil-fuel generating facilities. In accordance with GAAP, PNM is only required to recognize and measure decommissioning liabilities for tangible long-lived assets for which a legal obligation exists. Nuclear decommissioning costs and related accruals are based on site-specific estimates of the costs for removing all radioactive and other structures at PVNGS and are dependent upon numerous assumptions. PNM’s accruals for PVNGS Units 1, 2, and 3, including portions held under leases, have been made based on such estimates, the guidelines of the NRC, and the extended PVNGS license period. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 is currently excluded. PNM collects a provision for ultimate decommissioning of PVNGS Units 1 and 2 and its fossil-fueled generation facilities in its rates and recognizes a corresponding expense and liability for these amounts. See Note 15 and Note 16.

Environmental Costs

The normal operations of the Company involve activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred.

The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Amounts recorded for environmental expense in the years ended December 31, 2013, 2012, and 2011, as well as the amounts of environmental liabilities at December 31, 2013 and 2012 were insignificant.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Pension and Other Postretirement Benefits

See Note 12 for a discussion of pension and postretirement benefits expense, including a discussion of the actuarial assumptions.

Stock-Based Compensation

See Note 13 for a discussion of stock-based compensation expense.

Income Taxes

Income taxes are recognized using the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current NMPRC, FERC, and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC, FERC, and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets. See Note 11.

The Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. Year-to-date income tax expense is then calculated by applying the anticipated annual effective tax rate to year-to-date earnings before taxes, which includes the earnings attributable to the Valencia non-controlling interest. GAAP also provides that certain unusual or infrequently occurring items, as well as adjustments due to enactment of new tax laws, be excluded from the estimated annual effective tax rate calculation.

Excise Taxes

The Company pays certain fees or taxes which are either considered to be an excise tax or similar to an excise tax. Substantially all of these taxes are recorded on a net basis in the Consolidated Statements of Earnings.

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

Accounting Standards Update 2013-11 - Income Taxes: Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

The FASB released guidance that requires entities to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for net operating losses in certain circumstances. The guidance is to be applied prospectively and is effective for annual and interim reporting periods beginning after December 15, 2013, with early adoption permitted. The Company will implement the update in 2014. Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss deferred tax assets of $19.9 million for PNMR, $11.1 million for PNM, and $6.8 million for TNMP, along with the elimination of corresponding assets and liabilities associated with unrecognized tax benefits (Note 11). No impact to earnings is anticipated.


(2)	Segment Information

The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also includes the generation and sale of electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity includes the asset optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale and transmission rates.

TNMP

TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT.

First Choice

First Choice, which was sold by PNMR on November 1, 2011 (Note 3), operated as a certified REP in Texas. First Choice provided electricity to residential, small commercial, and governmental customers. Although First Choice was regulated in certain respects by the PUCT, it was not subject to traditional rate regulation.

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.

The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.

PNMR SEGMENT INFORMATION



2013	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Electric operating revenues	$	1,116,312		$	271,611		$	—		$	1,387,923
Cost of energy	374,710			57,606			—			432,316
Margin	741,602			214,005			—			955,607
Other operating expenses	428,591			91,601			(18,308		)	501,884
Depreciation and amortization	103,826			50,219			12,836			166,881
Operating income	209,185			72,185			5,472			286,842
Interest income	10,182			—			(139		)	10,043
Other income (deductions)	11,288			1,919			(13,575		)	(368		)
Net interest charges	(79,175		)	(27,393		)	(14,880		)	(121,448		)
Segment earnings (loss) before income taxes	151,480			46,711			(23,122		)	175,069
Income taxes (benefit)	48,804			17,621			(6,912		)	59,513
Segment earnings (loss)	102,676			29,090			(16,210		)	115,556
Valencia non-controlling interest	(14,521		)	—			—			(14,521		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	87,627		$	29,090		$	(16,210	)	$	100,507

Gross property additions	$	239,906		$	89,117		$	19,016		$	348,039
At December 31, 2013:
Total Assets	$	4,227,616		$	1,162,431		$	110,163		$	5,500,210
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



2012	PNM			TNMP			Corporate and Other			Consolidated

Electric operating revenues	$	1,092,264		$	250,140		$	(1	)	$	1,342,403
Cost of energy	353,649			46,201			—			399,850
Margin	738,615			203,939			(1		)	942,553
Other operating expenses	435,442			87,079			(17,862		)	504,659
Depreciation and amortization	97,291			49,340			17,542			164,173
Operating income	205,882			67,520			319			273,721
Interest income	13,243			1			(172		)	13,072
Gain on sale of First Choice	—			—			1,012			1,012
Other income (deductions)	13,290			2,739			(7,954		)	8,075
Net interest charges	(76,101		)	(28,161		)	(16,583		)	(120,845		)
Segment earnings (loss) before income taxes	156,314			42,099			(23,378		)	175,035
Income taxes (benefit)	50,713			15,352			(11,155		)	54,910
Segment earnings (loss)	105,601			26,747			(12,223		)	120,125
Valencia non-controlling interest	(14,050		)	—			—			(14,050		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	91,023		$	26,747		$	(12,223	)	$	105,547

Gross property additions	$	196,800		$	92,973		$	19,136		$	308,909
At December 31, 2012:
Total Assets	$	4,163,907		$	1,086,229		$	122,447		$	5,372,583
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



2011	PNM			TNMP			First Choice			Corporate and Other			Consolidated
							(In thousands)
Electric operating revenues:
Non-affiliates	$	1,057,289		$	204,045		$	439,450		$	(165	)	$	1,700,619
Affiliate	—			33,813			—			(33,813		)	—
Total electric operating revenues	1,057,289			237,858			439,450			(33,978		)	1,700,619
Cost of energy	362,237			41,166			323,331			(33,812		)	692,922
Margin	695,052			196,692			116,119			(166		)	1,007,697
Other operating expenses	438,822			88,234			75,966			(9,671		)	593,351
Depreciation and amortization	94,787			44,616			1,098			16,546			157,047
Operating income (loss)	161,443			63,842			39,055			(7,041		)	257,299
Interest income	15,562			2			64			(113		)	15,515
Gain on sale of First Choice	—			—			—			174,925			174,925
Other income (deductions)	4,309			1,580			(650		)	(15,660		)	(10,421		)
Net interest charges	(75,349		)	(29,286		)	(581		)	(19,633		)	(124,849		)
Segment earnings before income taxes	105,965			36,138			37,888			132,478			312,469
Income taxes	37,427			13,881			13,772			56,455			121,535
Segment earnings	68,538			22,257			24,116			76,023			190,934
Valencia non-controlling interest	(14,047		)	—			—			—			(14,047		)
Subsidiary preferred stock dividends	(528		)	—			—			—			(528		)
Segment earnings attributable to PNMR	$	53,963		$	22,257		$	24,116		$	76,023		$	176,359

Gross property additions	$	251,345		$	67,407		$	2,089		$	6,090		$	326,931
At December 31, 2011:
Total Assets	$	4,095,287		$	1,037,445		$	—		$	71,881		$	5,204,613
Goodwill	$	51,632		$	226,665		$	—		$	—		$	278,297

Major Customers

No individual customer accounted for more than 10% of the electric operating revenues of PNMR or PNM. The acquiror of First Choice, including the former First Choice operations, accounted for 17% and 19% of TNMP’s electric operating revenues in 2013 and 2012. Two other unaffiliated customers of TNMP accounted for revenues of 16% in 2013, 17% in 2012, and 19% in 2011 and 10% in 2013, 10% in 2012, and 12% in 2011. First Choice accounted for 17% of TNMP’s revenues in 2011.


(3)	Sale of First Choice

On September 23, 2011, PNMR entered into an agreement for the sale of First Choice to Direct LP, Inc. for $270.0 million, subject to adjustment to reflect the actual amounts of certain components of working capital at closing. Closing occurred on November 1, 2011, with PNMR receiving $329.3 million, which included an estimate of the components of working capital. For accounting purposes, the sale was effective as of the close of business on October 31, 2011. PNMR recognized a pre-tax gain of $174.9 million on the sale in 2011. The amount received was subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. The parties could not agree on the working capital amount and, in accordance with the agreement for the sale, this matter was submitted to an independent party for a decision binding on the parties. A decision was received in August 2012. The decision resulted in PNMR being awarded $6.4 million of the $8.2 million in dispute. PNMR recorded an additional pre-tax gain of $1.0 million in 2012. PNMR used the net proceeds from the sale of First Choice to repurchase certain of PNMR’s outstanding debt and equity securities (Note 6) and for other corporate purposes, including repayment of borrowings under the PNMR Revolving Credit Facility. PNMR Services Company continued to provide certain services at cost to First Choice for a transitional period through August 1, 2012. Because PNMR continues to have direct cash flows resulting

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations. After October 31, 2011, TNMP’s revenues from First Choice are not intercompany and are not eliminated in consolidation by PNMR.


(4)	Regulatory Assets and Liabilities

The operations of PNM and TNMP are regulated by the NMPRC, PUCT, and FERC and the provisions of GAAP for rate-regulated enterprises are applied to its regulated operations. Regulatory assets represent probable future recovery of previously incurred costs that will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets are presented below.

PNM



	December 31,
	2013			2012
Assets:	(In thousands)
Current:
FPPAC	$	19,394		$	36,266
Other	—			224
	19,394			36,490
Non-Current:
Coal mine reclamation costs	40,144			46,065
Deferred income taxes	61,850			54,781
Loss on reacquired debt	27,490			29,702
Pension and OPEB	206,691			254,351
FPPAC	25,386			18,619
Renewable energy costs	13,311			18,768
Other	9,345			9,670
	384,217			431,956
Total regulatory assets	$	403,611		$	468,446
Liabilities:
Current:
Other	$	(1,081	)	$	(15,172	)
Non-Current:
Cost of removal	$	(266,075	)	$	(257,396	)
Deferred income taxes	(80,495		)	(49,723		)
AROs	(37,567		)	(39,280		)
Renewable energy tax benefits	(26,011		)	(26,988		)
Other	(4,463		)	(6,454		)
	(414,611		)	(379,841		)
Total regulatory liabilities	$	(415,692	)	$	(395,013	)

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

TNMP



	December 31,
	2013			2012
Assets:	(In thousands)
Current:
Transmission cost recovery factor	$	4,250		$	2,287
Other	772			343
	5,022			2,630
Non-Current:
CTC, including carrying charges	63,606			71,240
Deferred income taxes	10,868			11,179
Pension	19,938			28,307
Loss on reacquired debt	38,616			1,711
Hurricane recovery costs	—			4,572
AMS retirement costs	5,083			3,538
Other	1,627			3,074
	139,738			123,621
Total regulatory assets	$	144,760		$	126,251
Liabilities:
Non-Current:
Cost of removal	$	(30,863	)	$	(31,115	)
Deferred income taxes	(4,563		)	(5,203		)
AMS surcharge	(7,251		)	(6,386		)
OPEB	(3,361		)	(915		)
Total regulatory liabilities	$	(46,038	)	$	(43,619	)

The Company’s regulatory assets and regulatory liabilities are reflected in rates charged to customers or have been addressed in a regulatory proceeding. The Company does not receive or pay a rate of return on the following regulatory assets and regulatory liabilities (and their remaining amortization periods): coal mine reclamation costs (through 2020); deferred income taxes (over the remaining life of the taxable item, up to the remaining life of utility plant); pension and OPEB costs (through 2033); FPPAC deferrals greater than $49.1 million (based on future FPPAC activity and regulatory proceedings); and AROs (to be determined in a future regulatory proceeding). In addition, TNMP does not receive a return on substantially all of its loss on reacquired debt (through 2043).

The Company is permitted, under rate regulation, to accrue and record a regulatory liability for the estimated cost of removal and salvage associated with certain of its assets through depreciation expense. Under GAAP, actuarial losses and prior service costs for pension plans are required to be recorded in AOCI; however, to the extent authorized for recovery through the regulatory process these amounts are recorded as regulatory assets or liabilities. Based on prior regulatory approvals, the amortization of these amounts will be included in the Company’s rates.

Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that future recovery of its regulatory assets are probable.


(5)	Stockholders’ Equity

Common Stock and Equity Contributions

PNMR, PNM and TNMP did not issue any common stock during the three year period ended December 31, 2013. See Note 6 for additional information related to PNMR’s common stock. PNMR made a cash equity contribution to PNM of $43.0 million in 2011. PNMR funded a cash equity contribution of $13.8 million to TNMP in 2013.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Dividends on Common Stock

The declaration of common dividends by PNMR is dependent upon a number of factors including the ability of PNMR’s subsidiaries to pay dividends. PNMR’s primary sources of dividends are its operating subsidiaries.

PNM declared and paid cash dividends to PNMR of $155.0 million, $34.4 million, and $8.2 million in 2013, 2012, and 2011. In addition, PNM declared a dividend of $39.1 million in December 2010 that was paid in January 2011. TNMP paid cash dividends to PNMR of $3.7 million, $26.0 million, and $13.7 million in 2013, 2012, and 2011. TNMP dividends paid in 2012 and 2011 were recorded as reductions of paid-in-capital.

The NMPRC has placed certain restrictions on the ability of PNM to pay dividends to PNMR, including the restriction that PNM cannot pay dividends that cause its debt rating to fall below investment grade. The NMPRC provisions allow PNM to pay dividends from equity contributions previously made by PNMR and current earnings, determined on a rolling four quarter basis, without prior NMPRC approval. The Federal Power Act also imposes certain restrictions on dividends by public utilities. Each of the PNMR Revolving Credit Facility, PNMR Term Loan Agreement, PNM Revolving Credit Facility, PNM Term Loan Agreement, PNM New Mexico Credit Facility, TNMP Revolving Credit Facility, and TNMP 2011 Term Loan Agreement contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%, which could limit amounts of dividends that could be paid. For PNMR and PNM these ratios reflect the present value of payments under the PVNGS and EIP leases as debt. PNM also has other financial covenants that limit the transfer of assets, through dividends or other means, including a requirement to obtain approval of certain financial counterparties to transfer more than five percent of PNM’s assets. As of December 31, 2013, none of the numerical tests would restrict the payment of dividends from the retained earnings of PNMR, PNM, or TNMP, except that PNM would not be able to distribute amounts in excess of approximately $206 million and TNMP would not be able to distribute amounts in excess of approximately $199 million without approval of regulators or financial counterparties.

In addition, the ability of PNMR to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, financial circumstances and performance, current and future regulatory decisions, Congressional and legislative acts, and economic conditions. Conditions imposed by the NMPRC or PUCT, future growth plans and related capital requirements, and business considerations may also affect PNMR’s ability to pay dividends.

Preferred Stock

PNMR had 477,800 shares of Series A convertible preferred stock outstanding through September 23, 2011 when it entered into an agreement to purchase all of the outstanding shares from Cascade. See Note 6. The Series A convertible preferred stock was convertible into PNMR common stock in a ratio of 10 shares of common stock for each share of preferred stock and received dividends equivalent to dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The Series A convertible preferred stock was entitled to vote on all matters voted upon by common stockholders, except for the election of the Board, and would have received distributions substantially equivalent to common stock in the event of liquidation of PNMR. The terms of the Series A convertible preferred stock resulted in it being substantially equivalent to common stock. Therefore, for earnings per share purposes, the number of common shares into which the Series A convertible preferred stock was convertible was included in the weighted average number of common shares outstanding for periods the Series A convertible preferred stock was outstanding. Similarly, dividends on the Series A convertible preferred stock were considered to be common dividends in the accompanying Consolidated Financial Statements.

PNM’s cumulative preferred shares outstanding bear dividends at 4.58% per annum. PNM preferred stock does not have a mandatory redemption requirement but may be redeemed, at PNM’s option, at 102% of the stated value plus accrued dividends. The holders of the PNM preferred stock are entitled to payment before the holders of common stock in the event of any liquidation or dissolution or distribution of assets of PNM. In addition, PNM’s preferred stock is not entitled to a sinking fund and cannot be converted into any other class of stock of PNM.

TNMP has no preferred stock outstanding. The number of authorized shares of TNMP cumulative preferred stock is 1 million shares.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(6)	Financing

Financing Activities

PNMR

On September 23, 2011, PNMR entered into an agreement to purchase all of its outstanding Series A convertible preferred stock from Cascade. Cascade owned all of the 477,800 outstanding shares of the preferred stock, which were convertible into 4,778,000 shares of PNMR common stock. Upon signing, the agreement obligated PNMR to purchase the preferred stock at a 2% discount from the arithmetic mean of the daily volume weighted average price per share of PNMR’s common stock on each trading day in the period beginning September 19, 2011 and ending on September 30, 2011 times the number of shares of PNMR common stock into which the preferred stock was convertible. The purchase of the preferred stock closed on October 5, 2011 with PNMR paying Cascade an aggregate purchase price of $73.5 million. The difference between the purchase price and the $100.0 million carrying value of the preferred stock is reflected as an addition to common stock in the Consolidated Financial Statements. PNMR utilized a borrowing under its revolving credit facility to fund the purchase of the preferred stock. Such borrowing was repaid on November 1, 2011 with a portion of the proceeds from the sale of First Choice. See Note 3.

On October 24, 2011, PNMR commenced a cash tender offer to purchase up to $50.0 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015. PNMR offered to pay a premium of up to 17%, depending on when the notes were tendered. The tender offer expired on November 21, 2011 and was oversubscribed. On November 22, 2011, PNMR purchased $50.0 million of the notes for $58.5 million, plus accrued and unpaid interest. PNMR used a portion of the proceeds from the sale of First Choice to fund the purchase. PNMR recognized a loss of $9.2 million on the purchase, including transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which is included in other deductions on the Consolidated Statements of Earnings.

In the year ended December 31, 2013, PNMR purchased $23.8 million aggregate principal amount of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in several small open-market purchases, for $26.9 million plus accrued and unpaid interest. PNMR recognized losses of $3.3 million on these purchases, including transaction costs and write-off of the proportionate amount of the deferred costs of the original issuance of the notes, which are included in other deductions on the Consolidated Statements of Earnings.

On November 4, 2011, PNMR entered into an agreement to purchase up to 7,019,550 shares of common stock from Cascade. Upon signing, the agreement obligated PNMR to purchase the common stock at a 2% discount from the arithmetic mean of the volume weighted average price on each trading day in the period beginning October 27, 2011 and ending November 9, 2011. The purchase of the common stock closed on November 10, 2011 with PNMR purchasing all 7,019,550 shares of common stock owned by Cascade for an aggregate purchase price of $125.7 million. The shares of common stock repurchased have become authorized but unissued shares, as determined by the Board. PNMR used a portion of the proceeds from the sale of First Choice to fund the purchase.

On December 14, 2012, PNMR entered into a $100.0 million Term Loan Agreement (the “PNMR Term Loan Agreement”) among PNMR, the lenders identified therein, and JPMorgan Chase Bank, N.A., as Administrative Agent. Funding of the PNMR Term Loan Agreement occurred on December 27, 2012. PNMR borrowed $100.0 million under the agreement and used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility. PNMR pays interest on its borrowing under the agreement, which matured on December 27, 2013. The PNMR Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio, and customary events of default. The PNMR Term Loan Agreement has a cross default provision and a change of control provision. On December 27, 2013, PNMR entered into an agreement that amends and restates the PNMR Term Loan Agreement extending the maturity date to December 26, 2014.

PNMR offers shares of PNMR common stock through the PNMR Direct Plan. PNMR utilizes shares of its common stock purchased on the open market, by an independent agent, rather than issuing additional shares to satisfy subscriptions under the PNMR Direct Plan. The shares of PNMR common stock utilized in the PNMR Direct Plan are offered under a SEC shelf registration statement that expires in August 2015.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

For offerings of equity and debt 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.

PNM

On October 6, 2011, PNM priced a public offering of $160.0 million aggregate principal amount of its 5.35% Senior Unsecured Notes due 2021. The bonds were offered at 99.857% of face amount and the offering closed on October 12, 2011. Proceeds from the offering were used to repay outstanding short-term debt.

In April 2012, PNM filed an application with the NMPRC requesting approval to participate in the refunding of $20.0 million of PCRBs, which was approved in May 2012. PNM also received NMPRC authority to exercise the two one-year extension options under the PNM Revolving Credit Facility. 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 PCRBs 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.

On April 22, 2013, PNM entered into a $75.0 million Term Loan Agreement (the “PNM Term Loan Agreement”) among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM Term Loan Agreement occurred on April 22, 2013, at which time the funds were used to repay $75.0 million in borrowings made under the PNM Revolving Credit Facility. The PNM Term Loan Agreement bears interest at a variable rate and must be repaid on or before October 21, 2014. The PNM Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Term Loan Agreement has a cross default provision and a change of control provision.

PNM has a shelf registration statement for the issuance of up to $440.0 million of senior unsecured notes that will expire in May 2014.

TNMP

On September 30, 2011, TNMP entered into the TNMP 2011 Term Loan Agreement with JPMorgan Chase Bank, N.A and borrowed $50.0 million under it. The TNMP 2011 Term Loan Agreement replaces a previous term loan agreement. Borrowings under the TNMP 2011 Term Loan Agreement must be repaid by June 30, 2014 and are secured by $50.0 million aggregate principal amount of first mortgage bonds of TNMP (the “Series 2011A Bonds”). TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing of 1.475% through March 30, 2014 and 1.985% thereafter, which is an effective rate of 3.566% over the life of the debt considering the amounts paid to exit the prior arrangements and enter into the new arrangements. The hedging obligations entered into in connection with the TNMP 2011 Term Loan Agreement are also secured by the Series 2011A Bonds. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.2 million and $0.3 million at December 31, 2013 and 2012, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

On March 6, 2013, TNMP commenced an offer to exchange any and all of TNMP’s $265.5 million aggregate principal amount outstanding 9.50% First Mortgage Bonds, due 2019, Series 2009A, for a new series of 6.95% First Mortgage Bonds, due 2043, Series 2013A, and up to $140 in cash for each $1,000 of bonds exchanged. Settlement of the exchange offer occurred on April 3, 2013. Upon settlement, TNMP issued $93.2 million of 6.95% First Mortgage Bonds and paid an aggregate of $13.0 million in cash in exchange for $93.2 million of 9.50% First Mortgage Bonds, in addition to payment of accrued and unpaid interest on the exchanged bonds. The exchange resulted in a premium on the 6.95% First Mortgage Bonds reflecting the contractual interest rate being in excess of the market rate of interest on the date of the exchange. The premium amounted to $23.2 million, after reduction for the cash paid in the exchange. A regulatory asset was recorded offsetting the premium, including the cash consideration paid in the exchange.

On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provides that TNMP will issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”). The terms of the TNMP 2013 Bond Purchase Agreement provide that, subject to satisfaction of certain conditions, TNMP will issue the Series 2014A Bonds on or about June 27, 2014. TNMP anticipates using $50.0 million of the proceeds from the issuance to repay the TNMP 2011 Term Loan Agreement at its maturity and using the remaining proceeds to reduce short-term

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

debt under the TNMP Revolving Credit Facility and/or TNMP’s intercompany borrowings from PNMR. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement, which are due on June 30, 2014, are reflected as being long-term in the Consolidated Balance Sheet at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrates TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis.

Borrowing Arrangements Between PNMR and its Subsidiaries

PNMR has one-year intercompany loan agreements with its subsidiaries. Individual subsidiary loan agreements vary in amount up to $100.0 million and have either reciprocal or non-reciprocal terms. Interest charged to the subsidiaries is equivalent to interest paid by PNMR on its short-term borrowings. As of December 31, 2013 and 2012, PNM had outstanding borrowings of $32.5 million and zero and TNMP had outstanding borrowings of $29.4 million and $28.3 million from PNMR. At February 21, 2014, PNM and TNMP had borrowings of $17.3 million and $35.8 million from PNMR.

Short-term Debt

The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. On September 18, 2013, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from December 16, 2015 to September 18, 2018.

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. These facilities replaced existing facilities and provided for two one-year extension options, subject to approval by a majority of the lenders and, with respect to the PNM Revolving Credit Facility, regulatory approval. In October 2012 and October 2013, these extension options were exercised and both facilities now expire on October 31, 2018. 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.

On January 8, 2014, PNM entered into a new $50.0 million unsecured revolving credit facility (the “PNM New Mexico Credit Facility”) by and among PNM, the lenders identified therein, U.S. Bank National Association, as Administrative Agent, and BOKF, NA dba Bank of Albuquerque, as Syndication Agent. The nine participating lenders are all banks that have a significant presence in New Mexico and PNM’s service territory or are headquartered in New Mexico. The PNM New Mexico Credit Facility expires on January 8, 2018 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility.

As discussed above, PNMR borrowed $100.0 million under the PNMR Term Loan Agreement in December 2012 and extended the maturity of that arrangement in December 2013. PNMR used the funds to repay $100.0 million in borrowings made under the PNMR Revolving Credit Facility.

At December 31, 2013, the weighted average interest rate was 1.02% for the PNMR Term Loan Agreement, 1.42% for the PNM Revolving Credit Facility, and 1.42% for the PNM Term Loan Agreement. The PNMR Revolving Credit Facility and the TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2013. Short-term debt outstanding consists of:



	December 31,
Short-term Debt	2013		2012
	(In thousands)
PNM Revolving Credit Facility	$	49,200	$	21,100
TNMP Revolving Credit Facility	—		—
PNMR
Revolving Credit Facility	—		37,600
PNMR Term Loan Agreement	100,000		100,000
	$	149,200	$	158,700

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $8.6 million, $3.2 million, and $0.3 million at December 31, 2013 that reduce the available capacity under their respective revolving credit facilities.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

At February 21, 2014, PNMR, PNM, and TNMP had $291.4 million, $327.4 million, and $74.7 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $25.0 million of availability under the PNM New Mexico Credit Facility. Total availability at February 21, 2014, on a consolidated basis, was $718.5 million for PNMR. At February 21, 2014, PNMR had invested cash of $1.9 million. PNM and TNMP had no invested cash at February 21, 2014.

Long-Term Debt

Information concerning long-term debt outstanding is as follows:



	December 31,
Long-term Debt	2013			2012
	(In thousands)
PNM Debt
Senior Unsecured Notes, Pollution Control Revenue Bonds:
4.875% due 2033	$	146,000		$	146,000
6.25% due 2038	36,000			36,000
4.75% due 2040, mandatory tender at June 1, 2017	37,000			37,000
5.20% due 2040, mandatory tender at June 1, 2020	40,045			40,045
5.90% due 2040	255,000			255,000
6.25% due 2040	11,500			11,500
2.54% due 2042, mandatory tender at June 1, 2017	20,000			20,000
4.00% due 2043, mandatory tender at June 1, 2015	39,300			39,300
5.20% due 2043, mandatory tender at June 1, 2020	21,000			21,000
Senior Unsecured Notes:
7.95% due 2018	350,000			350,000
7.50% due 2018	100,025			100,025
5.35% due 2021	160,000			160,000
PNM Term Loan Agreement due 2014	75,000			—
Unamortized premiums (discounts)	(252		)	(291		)
	1,290,618			1,215,579
Less current maturities	75,000			—
	1,215,618			1,215,579
TNMP Debt
First Mortgage Bonds:
2011 Term Loan Agreement, due 2014	50,000			50,000
9.50% due 2019, Series 2009A	172,302			265,500
6.95% due 2043, Series 2013A	93,198			—
Unamortized premiums (discounts)	20,536			(3,911		)
	336,036			311,589
Less current maturities	—			—
	336,036			311,589
PNMR Debt
Senior unsecured notes, 9.25% due 2015	118,766			142,592
Other	—			2,530
	118,766			145,122
Less current maturities	—			2,530
	118,766			142,592
Total Consolidated PNMR Debt	1,745,420			1,672,290
Less current maturities	75,000			2,530
	$	1,670,420		$	1,669,760

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Reflecting mandatory tender dates, long-term debt matures as follows:



	PNMR		PNM		TNMP		PNMR Consolidated
	(In thousands)
2014	$	—	$	75,000	$	—	$	75,000
2015	118,766		39,300		—		158,066
2016	—		—		—		—
2017	—		57,000		—		57,000
2018	—		450,025		—		450,025
Thereafter	—		669,545		315,500		985,045
Total	$	118,766	$	1,290,870	$	315,500	$	1,725,136

The TNMP 2011 Term Loan Agreement, which is due on June 30, 2014, is not reflected as maturing in 2014 in the above tables since TNMP has entered into the TNMP 2013 Bond Purchase Agreement to re-finance that debt on a long-term basis as discussed in Financing Activities above.


(7)	Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and an interest in the EIP transmission line. Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. PNM has completed several renewals of rights-of-way, the largest of which is a renewal with the Navajo Nation, and has no significant rights-of-way that will expire before 2020. PNM is obligated to pay the Navajo Nation annual payments of $6.0 million, subject to adjustment each year based on the Consumer Price Index, through 2029. The Navajo Nation rights-of-way agreement is accounted for as an operating lease.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. Each of the leases provide PNM with an option to purchase the leased assets at fair market value at the end of the leases, but PNM does not have a fixed price purchase option. In addition, the leases provide PNM with options to renew the leases at fixed rates set forth in each of the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years (the “Maximum Option Period”) if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. The rental payments during the fixed renewal option periods would be 50% of the amounts during the original terms of the leases. Gross annual lease payments, before considering the impacts of amounts returned to PNM through ownership of the lessor notes, aggregate $33.0 million for the Unit 1 leases and $23.7 million for the Unit 2 leases. If the leases are extended, the leases provide PNM with the option to purchase the leased assets at fair market value at the end of the extended lease terms.

Each lease provides that no later than three years prior to the expiration of the lease, PNM must give notice to the lessor if it wishes to “retain” the leased assets (but without specifying whether it would purchase the leased assets or extend the lease) or “return” the leased assets to the lessor. Furthermore, each lease provides that, if PNM gives notice to “retain” the leased assets, PNM must give notice as to which of the purchase or renewal options it will exercise no later than two years prior to the expiration of the lease. The elections PNM makes under each of the leases is independent of the elections made under the other leases.

In accordance with the notice provisions, PNM notified each of the lessors that PNM will “retain” the assets leased upon the expiration of the basic lease term on January 6, 2012 for the Unit 1 leases and on January 9, 2013 for the Unit 2 leases. On January 9, 2013, PNM notified each of the lessors of the Unit 1 leases that it will extend each Unit 1 Lease for the Maximum Option Period. On December 11, 2013, PNM and each of the Unit 1 lessors entered into amendments to each of the Unit 1 leases setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period of January 15, 2023 and provide for certain casualty values during the extended terms. On December 30, 2013, PNM notified the lessor of the one Unit 2 lease containing the Maximum Option Period provision that it will extend that lease for the Maximum Option Period. PNM anticipates entering into an amendment to that Unit 2 lease that would extend the term of the

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

lease through a Maximum Option Period of January 15, 2024. The annual payments during the renewal periods aggregate $16.5 million for the PVNGS Unit 1 leases and $1.6 million for the Unit 2 lease. The table of future lease payments as of December 31, 2013 shown below includes payments during the renewal periods for those leases that will be extended at the end of their original terms.

On January 13, 2014, PNM provided notices to each of the lessors under the three other Unit 2 leases, which are not subject to the Maximum Option Period provision, that PNM will exercise its option under the terms of each of those leases to purchase the assets underlying the leases at fair market value at the expiration of the leases on January 15, 2016. As provided in the leases, the fair market value of the leased assets under each of the leases will be determined by negotiation between the parties, or, if the parties are unable to agree on the fair market value, then the fair market value will be determined under the appraisal procedure specified in each of the leases. The appraisal process outlined in the leases anticipates the process to be completed within approximately six months. On February 25, 2014, PNM and the lessor under one of the Unit 2 leases entered into a letter agreement that establishes that the purchase price, representing the fair market value, to be paid by PNM for the assets underlying that lease will be $78.1 million on January 15, 2016. This lease is for 31.2494 MW of the entitlement from PVNGS Unit 2. The lease remains in existence and PNM will record the purchase at the termination of the lease on January 15, 2016.

Covenants in PNM’s PVNGS Units 1 and 2 lease agreements limit PNM’s ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. PNM is exposed to losses under the PVNGS lease arrangements upon the occurrence of certain events that PNM does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to PVNGS or the occurrence of specified nuclear events), PNM would be required to make specified payments to the equity participants, and take title to the leased interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2013, PNM could have been required to pay the equity participants up to approximately $154.1 million. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Exercise of renewal options under the leases requires that amounts payable to equity participants under the circumstances described above would increase to the fair market value as of the renewal date.

PNM owns 60% of the EIP and leases the other 40%, under a lease that expires on April 1, 2015. The lease provides PNM the option, with 24 months advance notice, of purchasing the leased assets at the end of the lease for fair market value, as well as options to renew the lease. On November 1, 2012, PNM and the lessor entered into a definitive agreement for PNM to exercise the option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million. The lease remains in existence and PNM will record the purchase at the termination of the lease on April 1, 2015. The definitive agreement sets forth the terms and conditions under which PNM would also assume responsibility for scheduling long-term transmission service on the leased capacity.

PNMR leases a building that was used as part of its corporate headquarters, as well as housing certain support functions for the utility operations of PNM and TNMP. The lease expires on November 30, 2015 and provides for annual rents of $1.9 million, which are included in the tables below. PNMR is also obligated to pay taxes, insurance, and utilities applicable to the building. In November 2011, PNMR notified the lessor of its intent to vacate the building by the end of 2012 and made a settlement offer to terminate the lease. A termination agreement was not reached with the lessor. As of December 31, 2012, PNMR completed the abandonment of this building, as well as the partial abandonment of another leased building. In accordance with GAAP, PNMR recorded an abandonment expense of $7.4 million at December 31, 2012. PNM was allocated $6.2 million and TNMP was allocated $1.2 million of the abandonment expense for the period ended December 31, 2012, which is reflected as administrative and general expense.

PNM has a PPA for the entire output of Delta, a gas-fired generating plant in Albuquerque, New Mexico, which is classified as an operating lease with imputed annual lease payments of $6.0 million. See Note 9 for additional information about the Delta operating lease, including the potential purchase of Delta.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Operating lease expense, including the PVNGS and EIP leases, was:



	PNMR		PNM		TNMP
	(In thousands)
2013	$	82,882	$	78,306	$	2,663
2012	$	84,794	$	78,483	$	2,871
2011	$	86,323	$	78,422	$	3,606

As discussed under Investments in Note 1, the PVNGS Capital Trust, which is consolidated by PNM, acquired the lessor notes that were issued by the PVNGS lessors and PNM acquired the remaining lessor note issued by the remaining EIP lessor. Future minimum operating lease payments at December 31, 2013 shown below have been reduced by payments on the PVNGS lessor notes of $25.4 million in 2014, $24.0 million in 2015, and $9.0 million in 2016 that will be returned in cash to PNM:



	PNMR		PNM		TNMP
	(In thousands)
2014	$	53,594	$	49,580	$	815
2015	40,952		38,290		676
2016	33,788		33,363		237
2017	30,942		30,749		—
2018	30,948		30,749		—
Later years	167,225		166,830		—
	357,449		349,561		1,728
Future payments under non-cancelable subleases	93		—		—
Net minimum lease payments	$	357,356	$	349,561	$	1,728


(8)	Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

On November 1, 2011, PNMR completed the sale of First Choice. See Note 3. Accordingly, PNMR information reflects activity for First Choice through October 31, 2011. The difference between the PNMR and PNM amounts represents First Choice.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

First Choice was responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers were negotiated with each customer. First Choice purchased power at wholesale and sold power at retail to customers in the competitive ERCOT retail markets. First Choice’s strategy was to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. However, First Choice had a residual exposure to wholesale power price risk for the mismatch between the forecast and actual load.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. Energy contracts that meet the definition of a derivative under GAAP and do not qualify, or are not designated, for the normal purchases and normal sales exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met and elected. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle.

For derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. The Company assesses the effectiveness of hedge relationships at least quarterly using statistical data. Ineffectiveness gains and losses were immaterial for all periods presented. Gains or losses related to cash flow hedge instruments, including those de-designated, are reclassified from AOCI when the hedged transaction settles and impacts earnings. As of December 31, 2013 and 2012, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges.

The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Commodity Derivatives

Commodity derivative instruments, recorded at fair value are summarized as follows:



	Economic Hedges
	December 31,
	2013			2012
	(In thousands)
PNM and PNMR
Current assets	$	4,064		$	3,785
Deferred charges	3,002			352
	7,066			4,137
Current liabilities	(2,699		)	(1,000		)
Long-term liabilities	(1,094		)	(1,933		)
	(3,793		)	(2,933		)
Net	$	3,273		$	1,204

Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements was immaterial at December 31, 2013 and 2012.

At December 31, 2013 and 2012, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at December 31, 2013 and 2012, amounts posted as cash collateral under margin arrangements were $2.8 million and $1.9 million for both PNMR and PNM. At December 31, 2013 and 2012, PNMR and PNM had obligations to return cash collateral of approximately $0.2 million and zero. Cash collateral amounts are included in other current assets and other current liabilities on the Consolidated Balance Sheets.

PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.4 million of current assets and $0.1 million of current liabilities at December 31, 2013, and less than $0.1 million of current assets and current liabilities at December 31, 2012 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Consolidated Balance Sheets.

The following table presents the effect of mark-to-market commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, including de-designated hedges, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



	Economic Hedges								Qualified Cash Flow Hedges
	Year Ended December 31,								Year Ended December 31,
	2013		2012			2011			2013		2012		2011
	(In thousands)
PNMR
Electric operating revenues	$	1,727	$	6,168		$	5,682		$	—	$	—	$	—
Cost of energy	1,109		(460		)	(2,201		)	—		—		(422		)
Total gain (loss)	$	2,836	$	5,708		$	3,481		$	—	$	—	$	(422	)
Recognized in OCI									$	—	$	—	$	422
PNM
Electric operating revenues	$	1,727	$	6,168		$	5,682		$	—	$	—	$	—
Cost of energy	1,109		(460		)	(1,058		)	—		—		—
Total gain (loss)	$	2,836	$	5,708		$	4,624		$	—	$	—	$	—
Recognized in OCI									$	—	$	—	$	—

Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:



	Economic Hedges
	MMBTU	MWh
December 31, 2013
PNMR and PNM	905,000	(3,343,783	)
December 31, 2012
PNMR and PNM	1,127,500	(2,477,520	)

In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral.

The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under the existing contracts and does not reflect letters of credit under the Company’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.



Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152
December 31, 2012
PNMR and PNM	$	2,933	$	—	$	2,777

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is excluded from retail rates, that unit’s power is being sold in the wholesale market. Since January 1, 2011, PNM has been selling power from its interest in PVNGS Unit 3 at market prices. As of December 31, 2013, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales through the end of 2014 through hedging arrangements that are accounted for as economic hedges. PNM is also partially hedged for 2015.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and, beginning in August 2012, a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). PNMR and PNM do not have any unrealized losses on available-for-sale securities. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2013 and 2012, the fair value of available-for-sale securities included $222.5 million and $189.0 million for the NDT and $4.4 million and $3.5 million for the mine reclamation trust.



	December 31, 2013				December 31, 2012
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,356	$	—	$	4,628
Equity securities:
Domestic value	14,523		39,460		5,223		30,044
Domestic growth	25,656		76,292		15,212		51,650
International and other	1,040		16,633		247		14,868
Fixed income securities:
U.S. Government	158		21,941		1,305		32,592
Municipals	1,018		58,568		4,069		43,861
Corporate and other	207		10,605		1,100		14,868
	$	42,602	$	226,855	$	27,156	$	192,511

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold.



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Proceeds from sales	$	271,140		$	167,330		$	145,286
Gross realized gains	$	14,308		$	15,907		$	17,493
Gross realized (losses)	$	(4,298	)	$	(8,170	)	$	(6,223	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments.

The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

At December 31, 2013, the available-for-sale and held-to-maturity debt securities had the following final maturities:



	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	3,025	$	1,149	$	1,149
After 1 year through 5 years	24,068		57,497		56,130
After 5 years through 10 years	10,128		—		—
After 10 years through 15 years	6,136		—		—
After 15 years through 20 years	10,331		—		—
After 20 years	37,426		—		—
	$	91,114	$	58,646	$	57,279

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models.

For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar type assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the years ended December 31, 2013 and 2012.

Derivatives and Investments

Items recorded at fair value on the Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at December 31, 2013 and 2012 for items recorded at fair value.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
December 31, 2013				(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356		$	3,356	$	—
Equity securities:
Domestic value	39,460			39,460		—
Domestic growth	76,292			76,292		—
International and other	16,633			16,633		—
Fixed income securities:
U.S. Government	21,941			20,194		1,747
Municipals	58,568			—		58,568
Corporate and other	10,605			2,245		8,360
	$	226,855		$	158,180	$	68,675

Commodity derivative assets	$	7,066		$	—	$	7,066
Commodity derivative liabilities	(3,793		)	—		(3,793		)
Net	$	3,273		$	—	$	3,273



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
December 31, 2012				(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	4,628		$	4,628	$	—
Equity securities:
Domestic value	30,044			30,044		—
Domestic growth	51,650			51,650		—
International and other	14,868			14,868		—
Fixed income securities:
U.S. Government	32,592			27,737		4,855
Municipals	43,861			—		43,861
Corporate and other	14,868			—		14,868
	$	192,511		$	128,927	$	63,584

Commodity derivative assets	$	4,137		$	—	$	4,137
Commodity derivative liabilities	(2,933		)	—		(2,933		)
Net	$	1,204		$	—	$	1,204

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Consolidated Balance Sheets are presented below:



					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
December 31, 2013	(In thousands)
PNMR
Long-term debt	$	1,745,420	$	1,905,230	$	—	$	1,905,230	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	1,835	$	3,196	$	690	$	—	$	2,506
PNM
Long-term debt	$	1,290,618	$	1,382,938	$	—	$	1,382,938	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279
Other investments	$	445	$	445	$	445	$	—	$	—
TNMP
Long-term debt	$	336,036	$	390,814	$	—	$	390,814	$	—
Other investments	$	245	$	245	$	245	$	—	$	—

December 31, 2012
PNMR
Long-term debt	$	1,672,290	$	1,969,362	$	—	$	1,966,725	$	2,637
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	5,599	$	6,965	$	774	$	—	$	6,191
PNM
Long-term debt	$	1,215,579	$	1,385,433	$	—	$	1,385,433	$	—
Investment in PVNGS lessor notes	$	77,682	$	84,198	$	—	$	—	$	84,198
Other investments	$	494	$	494	$	494	$	—	$	—
TNMP
Long-term debt	$	311,589	$	418,166	$	—	$	418,166	$	—
Other investments	$	281	$	281	$	281	$	—	$	—

Investments Held by Employee Benefit Plans

As discussed in Note 12, PNM and TNMP have trusts that hold investment assets for their pension and other postretirement benefit plans. The fair value of the assets held by the trusts impacts the determination of the funded status of each plan, but the assets are not reflected on the Company’s Consolidated Balance Sheets. Both the PNM Pension Plan and the TNMP Pension Plan hold units of participation in the PNM Resources, Inc. Master Trust (the “PNMR Master Trust”), which was established for the investment of assets of the pension plans. Level 2 and Level 3 fair values are provided by fund managers utilizing a pricing service. For level 2 fair values, the pricing provider predominately uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. Level 2 investments in mutual funds are measured at net asset value as year-end. Level 3 investments are comprised of alternative investments, which are measured at net asset value at year-end and include private equity funds, hedge funds, and real estate funds. The private equity funds are not voluntarily redeemable. These investments are realized through periodic distributions occurring over a 10 to 15-year term after the initial investment. The real estate funds and hedge funds may be voluntarily redeemed but are subject to redemption provisions

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

that may result in the funds not being able to be redeemed in the near term. Audited financial statements are received for each fund and are reviewed by the Company annually.

The valuation of alternative investments requires significant judgment by the pricing provider due to the absence of quoted market values, changes in market conditions, and the long-term nature of the assets. The significant unobservable inputs include the trading multiples of public companies that are considered comparable to the company being valued, company specific issues, estimates of liquidation value, current operating performance and future expectations of performance, changes in market outlook and the financing environment, capitalization rates, discount rates and cash flows. The fair values of investments held by the employee benefit plans are as follows:



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2013			(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	557,258	$	145,364	$	330,903	$	80,991
TNMP Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	66,285	$	18,657	$	32,620	$	15,008
PNM OPEB Plan
Cash and cash equivalents	$	1,152	$	1,152	$	—	$	—
Equity securities:
International funds	3,057		—		3,057		—
Domestic value	6,388		6,388		—		—
Domestic growth	54,851		20,769		34,082		—
Other funds	5,564		—		5,564		—
Fixed income securities:
Mutual funds	3,121		3,121		—		—
	$	74,133	$	31,430	$	42,703	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	302	$	302	$	—	$	—
Equity securities:
International funds	1,334		—		1,334		—
Domestic value	381		381		—		—
Domestic growth	1,848		1,848		—		—
Other funds	4,167		—		4,167		—
Fixed income securities:
Mutual funds	1,702		1,702		—		—
	$	9,734	$	4,233	$	5,501	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2012	(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust	$	517,238	$	205,491	$	232,730	$	79,017
TNMP Pension Plan
Participation in PNMR Master Trust	$	66,450	$	26,462	$	25,817	$	14,171
PNM OPEB Plan
Cash and cash equivalents	$	4,976	$	4,976	$	—	$	—
Equity securities:
International funds	2,651		—		2,651		—
Domestic growth	46,145		19,511		26,634		—
Other funds	7,588		—		7,588		—
Fixed income securities:
Mutual funds	4,176		4,176		—		—
	$	65,536	$	28,663	$	36,873	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	42	$	42	$	—	$	—
Equity securities:
International funds	1,444		—		1,444		—
Domestic growth	1,289		1,289		—		—
Other funds	3,660		—		3,660		—
Fixed income securities:
Mutual funds	2,325		2,325		—		—
	$	8,760	$	3,656	$	5,104	$	—

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The fair values of investments in the PNMR Master Trust are as follows:



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2013	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	16,281	$	16,281	$	—	$	—
Equity securities:
International	24,471		24,471		—		—
Domestic value	41,451		41,451		—		—
Domestic growth	36,805		36,805		—		—
Other funds	22,522		—		22,522		—
Fixed income securities:
Corporate	202,897		363		202,358		176
U.S. Government	99,748		44,541		55,207		—
Municipals	17,259		—		17,259		—
Other funds	66,286		109		66,177		—
Alternative investments:
Private equity funds	39,122		—		—		39,122
Hedge funds	34,912		—		—		34,912
Real estate funds	21,789		—		—		21,789
	$	623,543	$	164,021	$	363,523	$	95,999
December 31, 2012
PNMR Master Trust
Cash and cash equivalents	$	10,404	$	10,404	$	—	$	—
Equity securities:
International	39,867		39,867		—		—
Domestic value	39,492		39,492		—		—
Domestic growth	63,888		63,888		—		—
Other funds	17,035		—		17,035		—
Fixed income securities:
Corporate	101,936		—		101,936		—
U.S. Government	148,341		78,302		70,039		—
Municipals	3,639		—		3,639		—
Other funds	65,898		—		65,898		—
Alternative investments:
Private equity funds	38,212		—		—		38,212
Hedge funds	31,277		—		—		31,277
Real estate funds	23,699		—		—		23,699
	$	583,688	$	231,953	$	258,547	$	93,188

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

A reconciliation of the changes in Level 3 fair value measurements is as follows:



	Year Ended December 31,
Level 3 Fair Value Assets and Liabilities	2013			2012
	(In thousands)
PNM Pension	Master Trust			Master Trust
Balance at beginning of period	$	79,017		$	84,133
Actual return on assets sold during the period	3,303			2,627
Actual return on assets still held at period end	3,361			2,386
Purchases	15,110			5,498
Sales	(19,800		)	(15,627		)
Balance at end of period	$	80,991		$	79,017
TNMP Pension
Balance at beginning of period	$	14,171		$	14,555
Actual return on assets sold during the period	1,400			197
Actual return on assets still held at period end	1,425			179
Purchases	6,408			413
Sales	(8,396		)	(1,173		)
Balance at end of period	$	15,008		$	14,171

Additional information concerning changes in Level 3 fair value measurements for the PNMR Master Trust is as follows:

Level 3 Fair Value Assets and Liabilities



PNMR Master Trust	Private equity funds			Hedge funds			Real estate funds			Fixed income - corporate		Total
				(In thousands)
Balance at December 31, 2011	$	37,100		$	36,904		$	24,684		$	—	$	98,688
Actual return on assets sold during the period	2,966			(80		)	(62		)	—		2,824
Actual return on assets still held at period end	40			2,453			72			—		2,565
Purchases	3,906			—			2,005			—		5,911
Sales	(5,800		)	(8,000		)	(3,000		)	—		(16,800		)
Balance at December 31, 2012	38,212			31,277			23,699			—		93,188
Actual return on assets sold during the period	4,677			135			(109		)	—		4,703
Actual return on assets still held at period end	1,162			3,500			123			1		4,786
Purchases	3,117			16,151			2,076			175		21,519
Sales	(8,046		)	(16,151		)	(4,000		)	—		(28,197		)
Balance at December 31, 2013	$	39,122		$	34,912		$	21,789		$	176	$	95,999

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(9)	Variable Interest Entities

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity.

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the years ended December 31, 2013, 2012, and 2011, PNM paid $18.9 million, $18.8 million, and $18.3 million for fixed charges and $1.2 million, $0.9 million, and $1.4 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.

PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. Therefore, PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:



Results of Operations
	Year ended December 31,
	2013			2012			2011
	(In thousands)
Operating revenues	$	20,166		$	19,585		$	19,720
Operating expenses	(5,645		)	(5,535		)	(5,673		)
Earnings attributable to non-controlling interest	$	14,521		$	14,050		$	14,047



Financial Position
	December 31,
	2013		2012
	(In thousands)
Current assets	$	2,658	$	3,655
Net property, plant and equipment	75,137		77,953
Total assets	77,795		81,608
Current liabilities	766		765
Owners’ equity – non-controlling interest	$	77,029	$	80,843

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process has been initiated since the parties failed to reach agreement on fair market value within 60 days. After the purchase price has been determined through the appraisal process, PNM may in its sole discretion determine whether or not it desires to exercise its option to purchase the 50% interest. In that regard, PNM will evaluate all its alternatives with respect to Valencia with the goal of achieving a fair and economical benefit for its customers. Also, PNM is in the process of developing its 2014 IRP (Note 17). Through this process, PNM will evaluate all of its resource options, including Valencia, to determine the optimal way to serve its customers. If PNM decides to exercise its option, the approval of the NMPRC and FERC would be required, which process could take up to 15 months. Since the purchase price is yet to be established, PNM cannot determine whether or not it will exercise its option or if required regulatory approvals would be received.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. The leases provide PNM with an option to purchase the leased assets at appraised value at the end of the leases, but PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provide PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets are greater than parameters set forth in the leases. See Note 7 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $52.5 million over the remaining original terms of the leases and $145.2 million during the renewal terms of the leases that PNM has elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of December 31, 2013, PNM could have been required to pay the beneficial owners up to approximately $154.1 million, which would result in PNM taking ownership of the leased assets and termination of the leases. During the terms of the leases: PNM has no other financial obligations or commitments to the trusts or the beneficial owners; creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments; and PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Consolidated Balance Sheets related to the trusts other than accrued lease payments of $26.0 million at December 31, 2013 and 2012, which are included in other current liabilities on the Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including the notices provided through January 2014 to the lessors (Note 7), and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts during the original and extended lease terms and, therefore, is not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since the operating licenses for the plants have been extended for twenty years through 2045 for Unit 1 and 2046 for Unit 2; PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease terms, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so does not significantly influence the day-to-day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from potential carbon legislation or regulation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Delta

PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. PNM makes fixed and variable payments to Delta under the PPA. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. For the years ended December 31, 2013, 2012, and 2011, PNM incurred fixed capacity charges of $6.4 million, $6.2 million, and $6.0 million and variable energy charges of $1.8 million, $0.8 million, and $1.5 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of December 31, 2013, aggregated $39.2 million through the end of the PPA in 2020. PNM will also pay variable costs, which cannot be quantified since the amounts are based on how much the generating plant is in operation.

This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owns Delta. At closing PNM would make a cash payment of $23.0 million, which would be adjusted for actual working capital compared to a targeted working capital and certain prepayments of debt. Delta had project financing debt of $19.2 million at December 31, 2012, including $3.0 million due in 2013, which PNM would retire at closing of the purchase. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing is subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM and Delta are working with the City of Albuquerque and EPA in order to remedy certain environmental issues. Closing of the purchase will occur once those issues are resolved.

Delta informed PNM that at December 31, 2013 and December 31, 2012, it had total assets of $23.7 million and $26.6 million, including net property, plant, and equipment of $20.3 million and $23.1 million, and total liabilities of $18.2 million and $21.1 million. Delta’s project financing debt amounted to $16.2 million at December 31, 2013, of which $3.3 million is due in 2014. Delta also indicated its 2013 and 2012 revenues were $9.5 million and $7.4 million and its net earnings were $1.2 million and $0.9 million. Consolidation of Delta would be immaterial to the Consolidated Balance Sheets for PNMR and PNM. Since all of Delta’s revenues and expenses are attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Consolidated Statements of Earnings for PNMR and PNM would be to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(10)	Earnings and Dividends Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share and dividends per share is as follows:



	Year Ended December 31,
	2013		2012		2011
	(In thousands, except per share amounts)
Earnings Attributable to PNMR	$	100,507	$	105,547	$	176,359
Average Number of Common Shares:
Outstanding during year	79,654		79,654		85,558
Equivalents from convertible preferred stock (Note 5)	—		—		3,469
Vested awards of restricted stock	191		145		174
Average Shares - Basic	79,845		79,799		89,201
Dilutive Effect of Common Stock Equivalents ⁽¹⁾:
Stock options and restricted stock	586		618		556
Average Shares – Diluted	80,431		80,417		89,757
Net Earnings Per Share of Common Stock:
Basic	$	1.26	$	1.32	$	1.98
Diluted	$	1.25	$	1.31	$	1.96
Dividends Declared per Common Share	$	0.68	$	0.58	0.50


⁽¹⁾	Excludes out-of-the-money options for 509,916 shares of common stock at December 31, 2013. See Note 13.


(11)	Income Taxes

PNMR

PNMR’s income taxes consist of the following components:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Current federal income tax	$	—		$	(1,296	)	$	1,319
Current state income tax	(917		)	(37		)	(4,208		)
Deferred federal income tax	50,044			51,559			119,280
Deferred state income tax	12,578			6,921			7,462
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Total income taxes	$	59,513		$	54,910		$	121,535

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

PNMR’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Federal income tax at statutory rates	$	61,274		$	61,262		$	109,364
First Choice goodwill	—			—			15,055
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Flow-through of depreciation items	1,132			1,284			3,659
Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
State income tax, net of federal benefit	3,818			4,646			3,395
Impairment of state production tax credits, net of federal benefit	3,880			718			—
Other	(3,317		)	(5,845		)	(2,703		)
Total income taxes	$	59,513		$	54,910		$	121,535
Effective tax rate	33.99		%	31.37		%	38.90		%

The components of PNMR’s net accumulated deferred income tax liability were:



	December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Net operating loss	$	134,418		$	110,989
Pension	—			26,452
Regulatory liabilities related to income taxes	83,838			53,439
Other	144,126			129,801
Total deferred tax assets	362,382			320,681
Deferred tax liabilities:
Depreciation and plant related	(814,671		)	(759,587		)
Investment tax credit	(25,855		)	(14,242		)
Regulatory assets related to income taxes	(66,352		)	(59,471		)
CTC	(22,262		)	(24,934		)
Pension	(58,780		)	—
Other	(143,044		)	(178,492		)
Total deferred tax liabilities	(1,130,964		)	(1,036,726		)
Net accumulated deferred income tax liabilities	(768,582		)	(716,045		)
Current accumulated deferred income tax (asset) liability	(58,681		)	258
Non-current accumulated deferred income tax liability	$	(827,263	)	$	(715,787	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following table reconciles the change in PNMR’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:



	Year Ended
	December 31, 2013
	(In thousands)
Net change in deferred income tax liability per above table	$	52,537
Change in tax effects of income tax related regulatory assets and liabilities	23,592
Tax effect of mark-to-market adjustments	(6,096		)
Tax effect of excess pension liability	(9,305		)
Adjustment for uncertain income tax positions	691
Other	(989		)
Deferred income taxes	$	60,430

PNM

PNM’s income taxes consist of the following components:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Current federal income tax	$	(479	)	$	(12,951	)	$	(46,364	)
Current state income tax	(760		)	(1,815		)	(6,776		)
Deferred federal income tax	42,806			56,194			78,673
Deferred state income tax	9,429			11,522			14,212
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Total income taxes	$	48,804		$	50,713		$	37,427

PNM’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Federal income tax at statutory rates	$	53,018		$	54,710		$	37,088
Amortization of accumulated investment tax credits	(2,192		)	(2,237		)	(2,318		)
Flow-through of depreciation items	1,115			1,268			3,656
Earnings attributable to non-controlling interest in Valencia	(5,082		)	(4,918		)	(4,917		)
State income tax, net of federal benefit	6,202			6,500			4,797
Other	(4,257		)	(4,610		)	(879		)
Total income taxes	$	48,804		$	50,713		$	37,427
Effective tax rate	32.22		%	32.44		%	35.32		%

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The components of PNM’s net accumulated deferred income tax liability were:



	December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Net operating loss	$	99,247		$	93,980
Pension	—			32,532
Regulatory liabilities related to income taxes	78,849			48,027
Other	67,179			55,629
Total deferred tax assets	245,275			230,168
Deferred tax liabilities:
Depreciation and plant related	(661,239		)	(624,724		)
Investment tax credit	(25,855		)	(14,242		)
Regulatory assets related to income taxes	(55,844		)	(48,726		)
Pension	(52,104		)	—
Other	(83,500		)	(134,046		)
Total deferred tax liabilities	(878,542		)	(821,738		)
Net accumulated deferred income tax liabilities	(633,267		)	(591,570		)
Current accumulated deferred income tax (asset) liability	(43,827		)	3,447
Non-current accumulated deferred income tax liability	$	(677,094	)	$	(588,123	)

The following table reconciles the change in PNM’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:



	Year Ended
	December 31, 2013
	(In thousands)

Net change in deferred income tax liability per above table	$	41,697
Change in tax effects of income tax related regulatory assets and liabilities	23,704
Tax effect of mark-to-market adjustments	(6,121		)
Tax effect of excess pension liability	(9,305		)
Adjustment for uncertain income tax positions	691
Other	(623		)
Deferred income taxes	$	50,043

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

TNMP

TNMP’s income taxes consist of the following components:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Current federal income tax	$	(4,957	)	$	9,152		$	(3,578	)
Current state income tax	1,916			1,822			1,981
Deferred federal income tax	20,688			4,406			15,507
Deferred state income tax	(26		)	(28		)	(29		)
Total income taxes	$	17,621		$	15,352		$	13,881

TNMP’s provision for income taxes differed from the federal income tax computed at the statutory rate for each of the periods shown. The differences are attributable to the following factors:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Federal income tax at statutory rates	$	16,349		$	14,735		$	12,648
State income tax, net of federal benefit	1,247			1,185			1,288
Other	25			(568		)	(55		)
Total income taxes	$	17,621		$	15,352		$	13,881
Effective tax rate	37.72		%	36.47		%	38.41		%

The components of TNMP’s net accumulated deferred income tax liability at December 31, were:



	December 31,
	2013			2012
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	4,988		$	5,412
Other	23,479			16,702
Total deferred tax assets	28,467			22,114
Deferred tax liabilities:
Depreciation and plant related	(151,581		)	(133,686		)
CTC	(22,262		)	(24,934		)
Regulatory assets related to income taxes	(10,509		)	(10,745		)
Loss on reacquired debt	(13,516		)	(599		)
Other	(14,295		)	(14,729		)
Total deferred tax liabilities	(212,163		)	(184,693		)
Net accumulated deferred income tax liabilities	(183,696		)	(162,579		)
Current accumulated deferred income tax (asset)	(6,501		)	(1,131		)
Non-current accumulated deferred income tax liability	$	(190,197	)	$	(163,710	)

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following table reconciles the change in TNMP’s net accumulated deferred income tax liability to the deferred income tax benefit included in the Consolidated Statement of Earnings:



	Year Ended
	December 31, 2013
	(In thousands)
Net change in deferred income tax liability per above table	$	21,117
Change in tax effects of income tax related regulatory assets and liabilities	(112		)
Other	(343		)
Deferred income taxes	$	20,662

Other Disclosures

GAAP requires that the Company recognize only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the taxing authority. A reconciliation of unrecognized tax benefits (expenses) is as follows:



	PNMR			PNM			TNMP
	(In thousands)
Balance at December 31, 2010	$	36,105		$	11,918		$	7,788
Additions based on tax positions related to 2011	(790		)	(717		)	(74		)
Reductions for tax positions of prior years	(15,735		)	(449		)	(13		)
Settlements	—			—			—
Balance at December 31, 2011	19,580			10,752			7,701
Additions based on tax positions related to 2012	2,046			1,152			—
Reductions for tax positions of prior years	(2,428		)	(1,522		)	(905		)
Settlements	—			—			—
Balance at December 31, 2012	19,198			10,382			6,796
Reductions based on tax positions related to 2013	(54		)	(54		)	—
Additions for tax positions of prior years	745			745			—
Settlements	—			—			—
Balance at December 31, 2013	$	19,889		$	11,073		$	6,796

Included in the balance at December 31, 2013 are $5.6 million and $1.4 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate for PNMR and PNM. None of TNMP’s unrecognized tax benefits at December 31, 2013 would affect the effective tax rate if recognized. The Company believes that it is reasonably possible that approximately $5.5 million of PNMR’s unrecognized tax expenses, $0.4 million of PNM’s unrecognized tax benefits, and $6.8 million of TNMP’s unrecognized tax expenses will be reduced or settled in 2014 as a result of the conclusion of income tax examinations. As discussed in Note 1, the Company has elected not to early adopt Accounting Standards Update 2013-11.

Estimated interest income related to refunds the Company expects to receive is included in Other Income and estimated interest expense and penalties related to potential cash settlements are included in interest expense in the Consolidated Statements of Earnings (Loss). Interest income (expense) related to income taxes is as follows:



	PNMR		PNM		TNMP
	(In thousands)
2013	$	242	$	251	$	(2	)
2012	$	243	$	244	$	(3	)
2011	$	467	$	401	$	2

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Accumulated accrued interest receivable (payable) related to income taxes is as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2013:
Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)
December 31, 2012:
Accumulated accrued interest receivable	$	3,796		$	3,796		$	—
Accumulated accrued interest payable	$	(1,108	)	$	(23	)	$	(116	)

The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2003 are closed to examination by either federal or state taxing authorities. Tax year 2003 is open for examination only for certain items. Tax year 2004 is closed to examination by federal and state taxing authorities. Other tax years are open to examination by federal and state taxing authorities. At December 31, 2013, the Company has $301.2 million of federal net operating loss carryforwards that expire beginning in 2030 and $40.6 million of federal tax credit carryforwards that expire beginning in 2023. State net operating losses expire beginning in 2015 and vary from federal due to differences between state and federal tax law.

PNMR has New Mexico wind energy production tax credit carry forwards with statutory expiration dates beginning in 2013. In 2012, PNMR impaired $0.7 million, after federal tax benefit, of the New Mexico wind energy production tax credit carry forwards that were not expected to be utilized prior to their expiration due to the Company’s net operating loss position. The impairment is reflected in PNMR’s Corporate and Other segment.

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 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR recorded this impairment, which after federal income tax benefit, amounted to $1.5 million as additional income tax expense during the year ended December 31, 2013. The impairment is reflected in PNMR’s Corporate and Other segment.

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction will be phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse. The portion of the adjustment related to PNM's regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The increase in the regulatory liability was $23.9 million. The portion of the adjustment that is not related to PNM's regulated activities was recorded as a reduction in deferred tax assets and an increase in income tax expense of $1.2 million during the year ended December 31, 2013. This additional income tax expense is reflected in PNMR's Corporate and Other segment.

The future reduction in taxes payable to the State of New Mexico resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income resulted in a further impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit, amounted to $2.4 million as additional income tax expense during the year ended December 31, 2013. This impairment is reflected in PNMR's Corporate and Other segment.

The impairments of the New Mexico wind energy production tax credits discussed above are reflected as a valuation allowance against deferred tax assets. At December 31, 2013, PNMR had a total allowance of $7.2 million, all of which is attributable to these credits. During the year ended December 31, 2013, the valuation allowance increased by $3.9 million. PNM and TNMP have no such valuation allowances.

In April 2013, the IRS issued Revenue Procedure 2013-24, which provides a safe harbor method of accounting that taxpayers may use to determine repair costs for electric generation property. Adoption of the safe harbor method is elective for

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

years ending on or after December 31, 2012. On July 11, 2013, the IRS issued a directive that suspends most current examination activity related to generation repairs methodology for any company that is eligible for the safe harbor. PNM is evaluating the possible effects of adopting the safe harbor method and the ultimate outcome cannot be determined at this time although the effects are not expected to be material.

In September 2013, the IRS issued final regulations addressing the recovery of amounts paid to acquire, produce, or improve tangible personal property and the accounting for and retirement of depreciable property. Also issued were proposed regulations addressing dispositions of property. Repairs of electric transmission and distribution property and repairs of electric generation property are specifically addressed in other Revenue Procedures issued by the IRS. The effects of the remainder of regulations are being evaluated by the Company and cannot be determined at this time. However, due to PNMR's net operating loss carryforward position for income tax purposes, the effects are not expected to be material.

In May 2013, PNMR received a refund of federal income taxes paid in prior years, which primarily was due to bonus tax depreciation and changes in the Company's method of accounting for repairs expense for income tax purposes. The total refund was $96.2 million of which $77.4 million was attributable to PNM.


(12)	Pension and Other Postretirement Benefits

PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (“PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans. The periodic costs or income of the PNM Plans and TNMP Plans are included in regulated rates to the extent attributable to regulated operations. PNM receives a regulated return on the amount it has funded for its pension plan in excess of the periodic cost or income to the extent included in retail rates.

Participants in the PNM Plans include eligible employees and retirees of PNMR and other subsidiaries of PNMR. Participants in the TNMP Plans include eligible employees and retirees of TNMP. The PNM pension plan was frozen at the end of 1997 with regard to new participants, salary levels, and benefits. Through December 31, 2007, additional credited service could be accrued under the PNM pension plan up to a limit determined by age and service. The TNMP pension plan was frozen at December 31, 2005 with regard to new participants, salary levels, and benefits.

GAAP requires a plan sponsor to (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (b) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year; and (c) recognize changes in the funded status of a defined benefit postretirement plan in the year in which the changes occur.

GAAP requires unrecognized prior service costs and unrecognized gains or losses to be recorded in AOCI and subsequently amortized. The amortization of these incurred costs will ultimately be included as pension and postretirement benefit periodic cost or income in subsequent years. To the extent the amortization of these items will ultimately be recovered in future rates, PNM and TNMP record the costs as a regulatory asset or regulatory liability.

For the PNM Plans and TNMP Plans, the Company has in place a policy that defines the investment objectives, establishes performance goals of the asset managers, and provides procedures for the manner in which investments are to be reviewed. The plans implement investment strategies to achieve the following objectives:


•	Maximize the return on assets, commensurate with the risk that the Corporate Investment Committee deems appropriate to meet the obligations of the pension plans and OPEB plans, minimize the volatility of expense, and account for contingencies


•	Transition asset mix over time to a higher proportion of high quality fixed income investments as the plans’ funded statuses improve

Management is responsible for the determination of the asset target mix and the expected rate of return. The target asset allocations are determined based on consultations with external investment advisors. The expected long-term rate of return on pension and postretirement plan assets is calculated on the market-related value of assets. GAAP requires that actual gains and losses on pension and postretirement plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility. For the PNM Plans and TNMP Plans, the market-related value of assets is equal to the prior year’s market related value of assets adjusted for contributions, benefit payments and investment gains

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

and losses that are within a corridor of plus or minus 4.0% around the expected return on market value. Gains and losses that are outside the corridor are amortized over five years.

Pension Plans

For defined benefit pension plans, including the executive retirement plans, the PBO represents the actuarial present value of all benefits attributed by the pension benefit formula to employee service rendered prior to that date using assumptions regarding future compensation levels. The ABO represents the PBO without considering future compensation levels. Since the plans are frozen, the PBO and ABO are equal. The following table presents information about the PBO, fair value of plan assets, and funded status of the plans:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(In thousands)
PBO at beginning of year	$	675,549		$	588,874		$	76,640		$	67,234
Service cost	—			—			—			—
Interest cost	28,142			32,232			3,087			3,635
Plan amendment	(6,346		)	—			—			—
Actuarial (gain) loss	(56,533		)	94,361			(7,820		)	11,434
Benefits paid	(41,275		)	(39,918		)	(5,748		)	(5,663		)
PBO at end of year	599,537			675,549			66,159			76,640
Fair value of plan assets at beginning of year	518,095			427,386			66,540			59,952
Actual return on plan assets	19,533			52,927			4,326			6,951
Employer contributions	60,000			77,700			1,000			5,300
Benefits paid	(41,275		)	(39,918		)	(5,748		)	(5,663		)
Fair value of plan assets at end of year	556,353			518,095			66,118			66,540
Funded status – asset (liability) for pension benefits	$	(43,184	)	$	(157,454	)	$	(41	)	$	(10,100	)

Effective January 1, 2014, the PNM Pension Plan was amended to allow for all participants, terminating after the effective date, to elect a lump sum payment of benefits. This change is reflected in the above table as of December 31, 2013.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2013.



	PNM Plan						TNMP Plan
	December 31, 2013						December 31, 2013
	Prior service cost			Net actuarial (gain) loss			Net actuarial (gain) loss
	(In thousands)
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at beginning of year	$	32		$	159,826		$	—
Experience loss (gain)	—			(34,136		)	(7,297		)
Regulatory asset (liability) adjustment	—			19,799			7,297
Plan amendment	(2,665		)	—			—
Amortization recognized in net periodic benefit cost (income)	(32		)	(6,233		)	—
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,665	)	$	139,256		$	—
Amortization expected to be recognized in 2014	$	(405	)	$	5,469		$	—

The following table presents the components of net periodic benefit cost (income):



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
PNM Plan
Service cost	$	—		$	—		$	—
Interest cost	28,142			32,232			32,804
Expected return on plan assets	(41,930		)	(41,301		)	(37,075		)
Amortization of net (gain) loss	14,840			10,516			9,209
Amortization of prior service cost	76			317			317
Net periodic benefit cost	$	1,128		$	1,764		$	5,255
TNMP Plan
Service cost	$	—		$	—		$	—
Interest cost	3,087			3,635			3,800
Expected return on plan assets	(4,849		)	(5,324		)	(5,470		)
Amortization of net (gain) loss	1,049			462			346
Amortization of prior service cost	—			—			—
Net periodic benefit cost (income)	$	(713	)	$	(1,227	)	$	(1,324	)

The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost (income). Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost (income) would be affected.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



	Year Ended December 31,
PNM Plan	2013		2012		2011
Discount rate for determining December 31 PBO	5.27	%	4.30	%	5.67	%
Discount rate for determining net periodic benefit cost (income)	4.30	%	5.67	%	5.72	%
Expected return on plan assets	7.65	%	8.25	%	8.50	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.06	%	4.19	%	5.69	%
Discount rate for determining net periodic benefit cost (income)	4.19	%	5.69	%	5.50	%
Expected return on plan assets	7.65	%	8.25	%	8.50	%
Rate of compensation increase	N/A		N/A		N/A

The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in discount rates resulted in a decrease in the PNM PBO of $60.9 million at December 31, 2013 and an increase of $86.4 million at December 31, 2012. Changes in discount rates resulted in a decrease in the TNMP PBO of $6.4 million at December 31, 2013 and an increase of $10.7 million at December 31, 2012. Changes in demographic experiences also resulted in actuarial losses in the PNM PBO of $4.4 million and $8.0 million at December 31, 2013 and 2012. Changes in demographic experiences resulted in an actuarial gain in the TNMP PBO of $1.4 million at December 31, 2013 and an actuarial loss of $0.8 million at December 31, 2012. The impacts of other changes in assumptions and experience were not significant. These changes are reflected as actuarial (gain) loss above. In 2011, TNMP had an actuarial loss due to changes in demographics associated with the early retirement of First Choice employees. The loss was not significant and is not included in the net periodic benefit (income) cost above.

The expected long-term rate of return on plan assets reflects the average rate of earnings expected on the funds invested, or to be invested, to provide for the benefits included in the PBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates) and current and target asset allocations between asset categories. The expected long-term rate of return assumption for the PNM and TNMP pension plans compares to the actual return of 3.5% and 6.7% for the year ended December 31, 2013. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2014 net periodic cost to increase $5.3 million and $0.7 million (analogous changes would result from a 1% increase).

The Company’s long-term pension investment strategy is to invest in assets whose interest rate sensitivity is correlated with the pension liability. The Company has chosen to implement this strategy known as Liability Driven Investing (“LDI”) by increasing the liability matching investments as the funded status of the pension plans improves. These liability matching investments are currently fixed income securities. The pension plans current targeted asset allocation is 21% equities, 65% fixed income, and 14% alternative investments. Equity investments are primarily in domestic securities that include large, mid, and small capitalization companies. The pension plans have a 6% targeted allocation to equities of companies domiciled primarily in developed countries outside of the United States. This category includes actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries, and government securities. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. The hedge funds and private equity funds are structured as multi-manager multi-strategy fund of funds to achieve a diversified position in these asset classes. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, buy-outs, and venture capital. The real estate investment is structured as an open-ended, commingled private real estate portfolio that invests in a diversified portfolio of assets including commercial property and multi-family housing. See Note 8 for fair value information concerning assets held by the pension plans.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following pension benefit payments are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2014	$	54,356	$	6,111
2015	52,532		6,181
2016	52,204		5,831
2017	50,954		5,631
2018	49,325		5,696
2019 – 2023	222,241		23,804

Due to declines in the general price levels of marketable equity securities held by the pension plans, PNM and TNMP have been making contributions to the pension plans since 2010. The Company does not anticipate making any contributions to the pension plans in 2014 due to the current funded status of the PNM and TNMP pension plans. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the pension plan trust for 2015-2018 are estimated to total $61.5 million for PNM and none for TNMP. These anticipated contributions were developed using current funding assumptions with discount rates of 5.2% to 5.5%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate.

Other Postretirement Benefit Plans

For postretirement benefit plans, the APBO is the actuarial present value of all future benefits attributed under the terms of the postretirement benefit plan to employee service rendered to date.

The following table presents information about the APBO, the fair value of plan assets, and the funded status of the plans:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(In thousands)
APBO at beginning of year	$	99,613		$	96,221		$	13,678		$	11,344
Service cost	260			217			299			244
Interest cost	4,113			5,293			566			624
Participant contributions	2,537			2,266			373			404
Actuarial (gain) loss	(4,566		)	5,008			(1,080		)	2,727
Benefits paid	(9,792		)	(9,392		)	(1,570		)	(1,665		)
APBO at end of year	92,165			99,613			12,266			13,678
Fair value of plan assets at beginning of year	64,464			58,776			8,643			8,303
Actual return on plan assets	12,780			9,285			1,813			1,259
Employer contributions	3,576			3,529			342			342
Participant contributions	2,537			2,266			373			404
Benefits paid	(9,792		)	(9,392		)	(1,570		)	(1,665		)
Fair value of plan assets at end of year	73,565			64,464			9,601			8,643
Funded status – asset (liability)	$	(18,600	)	$	(35,149	)	$	(2,665	)	$	(5,035	)

In the year ended December 31, 2013, actuarial gains of $12.3 million and $2.4 million were recorded as regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2013.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following table presents the components of net periodic benefit cost:



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
PNM Plan
Service cost	$	260		$	217		$	259
Interest cost	4,113			5,293			5,378
Expected return on plan assets	(5,043		)	(4,901		)	(5,388		)
Amortization of net (gain) loss	4,242			3,888			3,205
Amortization of prior service credit	(1,343		)	(1,343		)	(2,648		)
Net periodic benefit cost	$	2,229		$	3,154		$	806
TNMP Plan
Service cost	$	299		$	244		$	306
Interest cost	566			624			654
Expected return on plan assets	(503		)	(516		)	(533		)
Amortization of net (gain) loss	—			(209		)	(193		)
Amortization of prior service cost	57			57			60
Net periodic benefit cost	$	419		$	200		$	294

The following significant weighted-average assumptions were used to determine the APBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the APBO and net periodic benefit cost would be affected.



	Year Ended December 31,
PNM Plan	2013		2012		2011
Discount rate for determining December 31 APBO	5.21	%	4.26	%	5.70	%
Discount rate for determining net periodic benefit cost	4.26	%	5.70	%	5.59	%
Expected return on plan assets	8.50	%	8.50	%	8.50	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 APBO	5.21	%	4.26	%	5.70	%
Discount rate for determining net periodic benefit cost	4.26	%	5.70	%	5.59	%
Expected return on plan assets	6.50	%	6.50	%	6.30	%
Rate of compensation increase	N/A		N/A		N/A

The assumed discount rate for determining the APBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in the discount rates resulted in a decrease in the PNM APBO of $8.8 million at December 31, 2013 and an increase of $13.1 million at December 31, 2012. Changes in discount rates resulted in a decrease in the TNMP APBO of $1.3 million at December 31, 2013 and an increase of $2.0 million at December 31, 2012. Changes in claims, contributions, medical trends and demographic experience also resulted in actuarial losses in the PNM plan of $4.2 million at December 31, 2013 and actuarial gains of $8.1 million at December 31, 2012. Changes in claims, contributions, and demographic experience resulted in an actuarial losses in the TNMP plan of $0.2 million at December 31, 2013 and $0.8 million at December 31, 2012. The impacts of other changes in assumptions and experience were not significant. These changes are reflected as actuarial (gain) loss above.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

benefit plans compares to the actual return of 20.4% and 22.1% for the year ended December 31, 2013. If all other factors were to remain unchanged, a 1% decrease in the expected long-term rate of return would cause PNM’s and TNMP’s 2014 postretirement benefit cost to increase $0.7 million and $0.1 million (analogous changes would result from a 1% increase).

TNMP’s exposure to cost increases in the postretirement benefit plan is minimized by a provision that limits TNMP’s share of costs under the plan. Costs of the plan in excess of the limit are wholly borne by the participants. TNMP reached the cost limit at the end of 2001. As a result, a one-percentage-point change in assumed health care cost trend rates would have no effect on either the net periodic expense or the year-end APBO.

The following table shows the assumed health care cost trend rates:



	PNM Plan
	December 31,
	2013		2012
Health care cost trend rate assumed for next year	7.5	%	7.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2019		2017

The following table shows the impact of a one-percentage-point change in assumed health care cost trend rates:



	PNM Plan
	1-Percentage- Point Increase		1-Percentage- Point Decrease
	(In thousands)
Effect on total of service and interest cost	$	322	$	(274	)
Effect on APBO	$	5,859	$	(4,826	)

The Company’s other postretirement benefit plans invest in a portfolio that is diversified by asset class and style strategies. The other postretirement benefit plans generally use the same pension fixed income and equity investment managers and utilize the same overall investment strategy as described above for the pension plans, except there is no allocation to alternative investments. The other postretirement benefit plans have a target asset allocation of 70% equities and 30% fixed income. See Note 8 for fair value information concerning assets held by the other postretirement benefit plans.

The following other postretirement benefit payments, which reflect expected future service, are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2014	$	6,586	$	787
2015	6,720		795
2016	6,943		815
2017	7,080		833
2018	7,306		852
2019 - 2023	36,569		4,558

PNM expects to make contributions to the PNM postretirement benefit plan totaling $3.5 million in 2014 and $14.0 million for 2015-2018. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.3 million in 2014 and $1.4 million for 2015-2018 .

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Executive Retirement Programs

For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2013			2012			2013			2012
	(In thousands)
PBO at beginning of year	$	17,467		$	16,191		$	902		$	844
Service cost	—			—			—			—
Interest cost	720			876			36			45
Actuarial (gain) loss	(330		)	1,895			(21		)	107
Benefits paid	(1,494		)	(1,495		)	(94		)	(94		)
PBO at end of year – funded status	16,363			17,467			823			902
Less current liability	1,536			1,452			94			90
Non-current liability	$	14,827		$	16,015		$	729		$	812

The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2013.



	December 31, 2013
	PNM Plan			TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,069		$	—
Experience loss (gain)	(330		)	(22		)
Regulatory asset (liability) adjustment	192			22
Amortization recognized in net periodic benefit cost (income)	(98		)	—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	1,833		$	—
Amortization expected to be recognized in 2014	$	88		$	—

The following table presents the components of net periodic benefit:



	Year Ended December 31,
	2013		2012		2011
	(In thousands)
PNM Plan
Service cost	$	—	$	—	$	—
Interest cost	720		876		930
Amortization of net (gain) loss	232		83		93
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	952	$	959	$	1,023
TNMP Plan
Service cost	$	—	$	—	$	—
Interest cost	36		45		46
Amortization of net (gain) loss	—		—		—
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	36	$	45	$	46

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.



	Year Ended December 31,
PNM Plan	2013		2012		2011
Discount rate for determining December 31 PBO	5.27	%	4.30	%	5.67	%
Discount rate for determining net periodic benefit cost	4.30	%	5.67	%	5.72	%
Long-term rate of return on plan assets	N/A		N/A		N/A
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.06	%	4.19	%	5.69	%
Discount rate for determining net periodic benefit cost	4.19	%	5.69	%	5.50	%
Long-term rate of return on plan assets	N/A		N/A		N/A
Rate of compensation increase	N/A		N/A		N/A

The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The impacts of changes in assumptions or experience were not significant.

The following executive retirement plan payments, which reflect expected future service, are expected:



	PNM Plan		TNMP Plan
	(In thousands)
2014	$	1,535	$	93
2015	1,516		92
2016	1,494		90
2017	1,468		88
2018	1,438		85
2019 – 2023	6,580		365

Other Retirement Plans

PNMR sponsors a 401(k) defined contribution plan for eligible employees, including those of its subsidiaries. PNMR’s contributions to the 401(k) plan consist of a discretionary matching contribution equal to 75% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. PNMR also makes a non-matching contribution ranging from 3% to 10% of eligible compensation based on the eligible employee’s age.

PNMR also provides executive deferred compensation benefits through an unfunded, non-qualified plan. The purpose of this plan is to permit certain key employees of PNMR who participate in the 401(k) defined contribution plan to defer compensation and receive credits without reference to the certain limitations on contributions. Eligible employees are allowed to save on an after-tax basis. This plan has been amended and the after-tax provision will be eliminated on June 30, 2015.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

A summary of expenses for these other retirement plans is as follows:



	Year Ended December 31,
	2013		2012		2011
	(In thousands)
PNMR
401(k) plan	$	16,785	$	16,185	$	17,000
Non-qualified plan	$	2,204	$	1,491	$	1,931
PNM
401(k) plan	$	12,952	$	12,427	$	12,541
Non-qualified plan	$	1,691	$	1,143	$	1,407
TNMP
401(k) plan	$	3,953	$	3,739	$	3,723
Non-qualified plan	$	513	$	327	$	431


(13)	Stock-Based Compensation Plans

PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options were granted in 2011, 2012, or 2013 and awards of restricted stock increased. Certain restricted stock awards are subject to achieving performance or market targets and some also have time vesting requirements. Other awards of restricted stock are only subject to time vesting requirements.

Performance Equity Plan

The PEP provides for the granting of non-qualified stock options, restricted stock rights, performance shares, performance units, and stock appreciation rights to officers, key employees, and non-employee board members. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions not to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions and plan provisions provide that upon retirement, participants become 100% vested in stock awards. The total number of shares of PNMR common stock subject to all awards under the PEP may not exceed 12.34 million shares, subject to adjustment under certain circumstances defined in the PEP. The number of shares of PNMR common stock subject to the grant of restricted stock rights, performance shares and units and stock appreciation rights is limited to 3.24 million shares. Re-pricing of stock options is prohibited unless specific shareholder approval is obtained.

Source of Shares

The source of shares for exercised stock options and vested restricted stock is shares acquired on the open market by an independent agent, rather than newly issued shares.

Accounting for Stock Awards

The stock-based compensation expense related to stock options and restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for stock options and restricted stock awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees remain with the Company during the period.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2013, 2012, and 2011 was $5.3 million, $3.6 million, and $6.2 million. Stock compensation expense of $3.8 million, $2.7 million, and $4.3 million was charged to PNM and $1.5 million, $1.0 million, and $1.4 million was charged to TNMP.

PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date.

At December 31, 2013, PNMR had no unrecognized compensation expense related to stock options. Unrecognized compensation expense of $3.4 million related to restricted stock and performance-based shares and $1.2 million related to market-based shares is expected to be recognized over an average of 1.7 years.

The Company uses the Black Scholes option pricing model to estimate the fair value of stock option awards based on multiple factors, including historical exercise patterns of employees in relatively homogenous groups with respect to exercise and post-vesting employment termination behaviors, expected exercising patterns for these same homogenous groups, and both the implied and historical volatility of PNMR’s stock price. The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:



	Year Ended December 31,
Restricted Shares and Performance-Based Shares	2013			2012			2011
Expected quarterly dividends per share	$	0.165		$	0.145		$	0.125
Risk-free interest rate	0.34		%	1.22		%	1.35		%

Market-Based Shares
Dividend yield	2.86		%	3.45		%	N/A
Expected volatility	25.11		%	43.98		%	N/A
Risk-free interest rate	0.36		%	1.04		%	N/A

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares:



	Stock Options				Restricted Stock
	Shares		Weighted Average Exercise Price		Shares		Weighted-Average Grant Date Fair Value
Outstanding at December 31, 2012	1,992,700		$	20.72	353,722		$	14.03
Granted	—		$	—	249,113		$	20.03
Exercised	(319,239	)	$	14.47	(275,988	)	$	15.92
Forfeited	—		$	—	(11,542	)	$	18.39
Expired	(329,795	)	$	27.17	—		—
Outstanding at December 31, 2013	1,343,666		$	20.63	315,305		17.87

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Included as restricted stock granted and exercised above are 100,593 shares that were based upon achieving performance or market targets for the 2011 through 2012 performance period. The Board approved these shares in February 2013, including shares with market targets at near maximum levels.

As of December 31, 2013, PNMR’s stock-based compensation program provides for performance and market targets through 2015. Excluded from the above table are 112,864 shares approved by the Board in February 2014 (based upon achieving market targets, weighted at 60%, at maximum levels and performance targets, weighted at 40%, at below threshold levels for the 2011 through 2013 performance period), as well as maximums of 198,369 and 179,811 shares for the three-year performance periods ending in 2014 and 2015 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if the Company meets specific market targets at the end of 2016 and she remains an employee of the Company. If the Company achieves specific market targets at the end of 2014 and she remains an employee of the Company, she would receive 35,000 of the total shares at that time. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include any restricted stock shares under the retention award agreement.

At December 31, 2013, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $7.3 million with a weighted-average remaining contract life of 3.43 years. At December 31, 2013, the exercise price of 509,916 outstanding stock options is greater than the closing price of PNMR common stock on that date so those options have no intrinsic value.

The following table provides additional information concerning stock options, and restricted stock activity including performance-based and market-based shares:



	Year Ended December 31,
Stock Options	2013		2012		2011
Weighted-average grant date fair value of options granted	$	—	$	—	$	—
Total fair value of options that vested (in thousands)	$	625	$	1,054	$	1,189
Total intrinsic value of options exercised (in thousands)	$	2,721	$	6,356	$	2,616

Restricted Stock
Weighted-average grant date fair value	$	20.03	$	16.75	$	13.79
Total fair value of restricted shares that vested (in thousands)	$	4,395	$	5,099	$	1,240

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(14)	Construction Program and Jointly-Owned Electric Generating Plants

PNM’s expenditures for additions to utility plant were $239.9 million in 2013, including expenditures on jointly-owned projects. TNMP does not participate in the ownership or operation of any generating plants, but incurred expenditures for additions to utility plant of $89.1 million during 2013. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $348.0 million in 2013.

Joint Projects

Under the agreements for the jointly-owned projects, PNM has an undivided interest in each asset and liability of the project and records its pro-rata share of each item in the corresponding asset and liability account on PNM’s Consolidated Balance Sheets. Likewise, PNM records its pro-rata share of each item of operating and maintenance expenses for its jointly-owned plants within the corresponding operating expense account in its Consolidated Statements of Earnings. PNM is responsible for financing its share of the capital and operating costs of the joint projects.

At December 31, 2013, PNM’s interests and investments in jointly-owned generating facilities are:



Station (Fuel Type)	Plant in Service		Accumulated Depreciation			Construction Work in Progress		Composite Interest
	(In thousands)
SJGS (Coal)	$	1,004,138	$	(414,054	)	$	13,860	46.30	%
PVNGS (Nuclear) ⁽¹⁾	$	508,426	$	(141,347	)	$	43,627	10.20	%
Four Corners Units 4 and 5 (Coal)	$	159,016	$	(100,462	)	$	3,236	13.00	%
Luna (Gas)	$	62,873	$	(17,743	)	$	169	33.33	%


⁽¹⁾	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2.

San Juan Generating Station

PNM operates and jointly owns SJGS. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. SJGS Unit 3 is owned 50% by PNM, 41.8% by SCPPA, and 8.2% by Tri-State. SJGS Unit 4 is owned 38.457% by PNM, 28.8% by M-S-R Public Power Agency, 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, New Mexico, 7.2% by the County of Los Alamos, New Mexico, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the potential restructuring of SJGS ownership.

Palo Verde Nuclear Generating Station

PNM is a participant in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA, and The Department of Water and Power of the City of Los Angeles. PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. See Note 7 for additional information concerning the PVNGS leases, including PNM’s notices that it will exercise its option to purchase the assets underlying certain of the leases at the expiration of the leases on January 15, 2016.

Operation of each of the three PVNGS units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986, and Unit 3 in November 1987. The full power operating licenses were originally for a period of 40 years and authorize APS, as operating agent for PVNGS, to operate the three PVNGS units. On April 21, 2011, the NRC approved extensions in the operating licenses for the plants for 20 years through June 2045 for Unit 1, April 2046 for Unit 2, and November 2047 for Unit 3. In April 2010, APS entered into a Municipal Effluent Purchase and Sale Agreement that provides effluent water rights necessary for cooling purposes at PVNGS through 2050.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

Four Corners Power Plant

PNM is a participant in two units of Four Corners with APS (the operating agent), EPE, SRP, and Tucson. PNM has a 13.0% undivided interest in Units 4 and 5 of Four Corners. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a PSD permit from EPA to install SCR technology at Four Corners. PNM cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to PNM and the other Four Corners owners. See Note 16 for additional information about Four Corners.

Luna Energy Facility

Luna is a combined-cycle power plant near Deming, New Mexico. Luna is owned equally by PNM, Tucson, and Freeport McMoRan. The operation and maintenance of the facility has been contracted to North American Energy Services.

Construction Program

The Company anticipates making substantial capital expenditures for the construction and acquisition of utility plant and other property and equipment. An unaudited summary of the budgeted construction expenditures, including expenditures for jointly-owned projects, and nuclear fuel, is as follows:



	2014		2015		2016		2017		2018		Total
					(In millions)
PNM	$	360.8	$	433.7	$	387.3	$	335.4	$	181.7	$	1,698.9
TNMP	129.9		76.0		87.8		93.9		106.4		494.0
Corporate and Other	18.3		14.3		14.2		13.8		13.7		74.3
Total PNMR	$	509.0	$	524.0	$	489.3	$	443.1	$	301.8	$	2,267.2

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(15)	Asset Retirement Obligations

AROs are recorded based on the determination of underlying assumptions, such as discount rates, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Any changes in these assumptions underlying the required calculations may require revisions to the estimated AROs when identified. A reconciliation of the ARO liability is as follows:



	PNMR			PNM			TNMP
	(In thousands)
Liability at December 31, 2010	$	76,637		$	75,888		$	648
Liabilities incurred	60			60			—
Liabilities settled	(4		)	—			(4		)
Accretion expense	6,114			6,051			55
Revisions to estimated cash flows ⁽¹⁾	(3,574		)	(3,574		)	—
Liability at December 31, 2011	79,233			78,425			699
Liabilities incurred	—			—			—
Liabilities settled	(25		)	—			(25		)
Accretion expense	6,685			6,617			58
Liability at December 31, 2012	85,893			85,042			732
Liabilities incurred	—			—			—
Liabilities settled	(79		)	(67		)	(12		)
Accretion expense	7,245			7,174			62
Revisions to estimated cash flows⁽¹⁾	3,076			3,076			—
Liability at December 31, 2013	$	96,135		$	95,225		$	782

⁽¹⁾

Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for PVNGS that includes the obligations for nuclear decommissioning of that facility. In 2011 and 2013, new decommissioning studies for PVNGS were implemented reflecting updated cash flow estimates, including the extended operating licenses. The new studies resulted in a $4.2 million decrease to the ARO in 2011 and an increase of $0.5 million to the ARO in 2013. In addition, a new decommissioning study for SJGS was implemented in 2013, resulting in a $2.5 million increase to the ARO.


(16)	Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company occasionally enters into financial commitments in connection with its business operations. The Company is also involved in various legal and regulatory (Note 17) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable.

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The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. The Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Commitments and Contingencies Related to the Environment

PVNGS Decommissioning Funding

PNM has a program for funding its share of decommissioning costs for PVNGS, including portions held under leases. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. PNM funded $4.9 million, $2.6 million, and $2.6 million for the years ended December 31, 2013, 2012, and 2011 into the qualified and non-qualified trust funds. The estimated market value of the trusts at December 31, 2013 and 2012 was $222.5 million and $189.0 million.

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. As part of the 2010 Electric Rate Case, the NMPRC ordered PNM to refund $1.3 million of the DOE settlement to customers, which was recorded as a regulatory disallowance in 2011. See Note 17. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleges that from January 1, 2007, through June 30, 2011, APS, as a co-owner of PVNGS, incurred additional damages due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. PNM is unable to predict the outcome of this matter.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At December 31, 2013 and 2012, PNM had a liability for interim storage costs of $11.9 million and $13.9 million included in other deferred credits.

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high-level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision. The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action. In September 2012, the NRC issued a directive to its staff to proceed with development of a generic environmental impact statement to support an updated Waste Confidence Decision within 24 months. In September 2013, the NRC issued its draft environmental impact statement to support an updated Waste Confidence Decision. In late 2013, the NRC held a series of nationwide public meetings to receive stakeholder input on the draft environmental impact statement. NRC Commissioners have instructed the staff to issue the final generic environmental impact statement and rule by no later than September 2014. Untimely resolution by the NRC of the remand from the D.C. Circuit could have an adverse impact on certain NRC licensing actions. Currently, PVNGS does not have any licensing actions pending with the NRC. The petitioners had also sought a writ requiring the NRC to comply with the law and resume processing DOE’s pending license application for a nuclear waste site at Yucca Mountain in Nevada. In August 2013, the D.C. Circuit ordered the NRC to resume reviewing the license application. PNM is unable to predict the impact of these decisions.

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In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. This fee is recovered by PNM in its retail rates. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of the intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of the intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. PNM anticipates challenges to this action and is unable to predict its ultimate outcome, but is continuing to accrue the one-mill fee.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Determination Process - SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that requires installation of selective catalytic reduction technology (“SCR”) with stringent NOx emission limits on all four units by September 21, 2016.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule on March 1, 2012. These parties have also formally asked EPA to stay the effective date of the rule. Several environmental groups have intervened in support of EPA. WEG also filed an action to challenge EPA’s rule in the Tenth Circuit, seeking to shorten the rule’s compliance period from five years to three years and PNM has intervened in this action. Oral arguments on the merits of the FIP challenges were held in October 2012 in the Tenth Circuit. In accordance with the court’s order, the parties have filed supplemental information.

In litigation involving several environmental groups, the United States District Court for the District of Columbia entered a consent decree, which, as amended, required EPA to issue a final rulemaking on New Mexico’s regional haze SIP by November 15, 2012. EPA approved all components of the SIP, except for the NOx BART determination for SJGS. With respect to that element of the SIP, EPA determined that with the FIP in place, it had met its obligation under the consent decree.

Because the unchanged compliance deadline of the FIP required PNM to continue to take steps to commence installation of SCRs at SJGS, 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. At that time, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, which amounts include costs for construction management, gross receipts taxes, AFUDC, and other PNM costs, although final costs would be

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refined through an “open book” subcontractor bidding process. The costs for the project to install SCRs would also encompass installation of technology to comply with the NAAQS requirements described below.

Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. The estimates for SNCRs and the NAAQS requirements include gross receipts taxes, AFUDC, and other PNM costs.

Based upon its current SJGS ownership interest, PNM’s share under either SCRs or SNCRs would be about 46.3%.

During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS, subject to approval by EIB and EPA. 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. Certain aspects of this alternative are subject to approval by the NMPRC. At December 31, 2013, PNM’s net book value of its ownership share of SJGS Units 2 and 3 was approximately $287 million.

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

This revised plan primarily focuses on how SJGS would meet the regional haze rule and also indicates that PNM would build a natural gas-fired generating plant to be sited at SJGS to partially replace the capacity from the retired coal units. 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.

In connection with the implementation of the revised plan, retirement of SJGS Units 2 and 3 could result in shifts in ownership among SJGS owners or other changes in the contractual cost sharing arrangements, as may be agreed upon by the owners. See SJGS Ownership Restructuring Matters below. Owners of the affected units also may seek approvals of their utility commissions or governing boards.

The parties file periodic 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 Tenth Circuit. 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. On October 17, 2013, the court ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously filed motion to stay the EPA rule. The court placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the agreement in principle fails or is not implemented as was indicated in the term sheet and timeline, any party to the litigation may file a motion seeking to lift the abatement. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

Due to the long lead times on certain equipment purchases, PNM began taking steps to prepare for the potential installation of SNCRs on Units 1 and 4. In April 2013, PNM issued an RFP for SNCR system design and technology. In May 2013, PNM entered into an SNCR equipment and related services contract with an SNCR technology provider, but has not yet entered into a construction and procurement contract.

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On July 10, 2013, the NMPRC issued an order initiating a proceeding regarding the possible retirement of SJGS Units 2 and 3 and impacts on service reliability, and other items. The order required PNM to make monthly presentations to the NMPRC on this matter. The NMPRC closed this docket on January 22, 2014.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013, reflecting the terms of the non-binding agreement, including the installation of SNCRs on Units 1 and 4 and the retirement of Units 2 and 3. NMED developed a revised SIP and submitted it to the EIB for approval in May 2013. After a public hearing, the EIB approved the revised SIP in September 2013 and the revised SIP was submitted to EPA for approval on October 18, 2013. EPA deemed the SIP application complete on December 17, 2013. It is anticipated that EPA will publish its proposed action on the revised SIP within 135 days of determining it was complete. Final EPA action on the revised SIP is expected within 150 days of publishing the proposed action, which would be about the end of September 2014.

On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the revised SIP. In this filing, PNM requests:


•	Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date, currently estimated to be approximately $205 million, along with a regulated return on those costs


•	A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018


•	An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million


•	A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM. The expected net impact of this transaction and the retirement of Units 2 and 3 will be a reduction of 340 MW in PNM’s ownership of SJGS.

In its filing, PNM requested the NMPRC to issue its final ruling on the application no later than December 2014. On January 22, 2014, the NMPRC directed PNM to file supplemental testimony in support of its application, determined that the application was incomplete, and that the statutory time clock for a decision on the CCNs has not started. PNM filed the supplemental testimony on February 5, 2014. On February 11, 2014, the Hearing Examiner issued an order finding that PNM’s application is now complete. The order also stated that there was not a statutory time clock for the request to retire SJGS Units 2 and 3 and the statutory time clock on the CCN requests has not yet begun. The Hearing Examiner indicated the NMPRC should proceed with the review of PNM’s application and establish a schedule that would allow NMPRC action on the application by the end of 2014. The Hearing Examiner indicated that he will schedule a public hearing to begin on August 19, 2014.

The above estimate of PNM’s share of the costs to install SNCRs and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4 includes gross receipts taxes, AFUDC, and other PNM costs. This amount and the above estimate of net book value of SJGS Units 2 and 3 at December 31, 2017 reflect the requested exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4 resulting in PNM’s ownership share of SJGS Units 1 and 4 aggregating approximately 52%. The December 20, 2013 filing identifies a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. Specific approvals to acquire these facilities and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $276.3 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of either SCRs or SNCRs. See Note 17 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.

PNM can provide no assurance that the requirements of the plan agreed to on February 15, 2013 will be accomplished within the required timeframes or at all. If the February 15, 2013 plan is not implemented, PNM would seek to work with NMED and EPA to develop a revised timetable for implementation of the FIP. If an agreement on a revised timetable cannot be reached, PNM will likely be unable to complete the installation of SCRs on all four units at SJGS by the FIP deadline of September 21, 2016. In such event, PNM would need to rely on EPA’s pledge to work with PNM and the State of New Mexico to develop a reasonable FIP compliance plan or otherwise negotiate a solution with EPA or seek relief from the Tenth Circuit in order to continue

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to be able to operate the plant, including during the installation process for any alternate solution. If relief is not granted, PNM could be forced to temporarily cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire temporary replacement power through short-term or open-market purchases in order to serve the needs of its customers. There can be no assurance that sufficient replacement power will be available to serve PNM’s needs or, if available, what costs would be incurred.

PNM is unable to predict the ultimate outcome of these matters or what additional pollution control equipment will be required at SJGS. PNM will seek recovery from its ratepayers for all costs that may be incurred as a result of the CAA requirements. Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

SJGS Ownership Restructuring Matters - SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. Accordingly, they have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS. Therefore, the California participants have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant has also expressed a similar intent to exit ownership in the plant. PNM is unable to predict the actions of the SJGS participants. Likewise, PNM cannot predict the impact of those actions on the ownership of SJGS or the operations of SJGS and PNM.

The SJGS participants have engaged in negotiations concerning the implementation of the revised SIP to address BART at SJGS. The negotiations have included potential shifts in ownership among participants and between units in order to facilitate the shutdown of SJGS Units 2 and 3 to comply with the revised SIP and to accommodate the intent of the participants desiring to exit ownership in SJGS. This could result in certain of the continuing participants, including PNM, acquiring additional ownership interests in Unit 4. In this regard, PNM’s December 20, 2013 filing requested NMPRC approval to exchange 78 MW of its capacity in SJGS Unit 3 for an equal amount of capacity in SJGS Unit 4. In addition to shifts in ownership, the discussions among the SJGS participants regarding restructuring have included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs. These discussions could result in PNM acquiring more than 78 MW of SJGS Unit 4. The SJGS participants have engaged a mediator to assist in facilitating resolution of a number of outstanding matters among the owners. Although discussions are continuing, no agreements have been reached. PNM is unable to predict the outcome of the negotiations.

The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or common property. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including NAAQS compliance requirements, to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. The SJPPA provides that PNM, in its capacity as operating agent of SJGS, is authorized and obligated to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM is evaluating its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and will take reasonable and prudent actions as it deems necessary. PNM cannot predict the outcome of this matter, its impact on SJGS’ compliance with the CAA, or the impact on PNM’s financial position and results of operations.

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Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to close permanently Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but has no ownership interest in Units 1, 2, and 3, which were shutdown by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

SCE, a participant in Four Corners, indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. A principal condition to closing was the execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below.

On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners, was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to approximately $80.3 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

Four Corners BART FIP Challenge

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP. In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA. APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS’ motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. Oral argument was presented before the Tenth Circuit on January 23, 2014. A decision is expected before the end of 2014. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Regional Haze Challenges

On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO₂ and particulate matter emissions elements of EPA’s approval of New Mexico’s Regional Haze SIP. On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA’s final approval of the remaining elements of New Mexico’s Regional Haze SIP, as well as EPA’s approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. This matter is now proceeding in the Tenth Circuit. All briefing has been completed and filed with the court. Oral argument is scheduled before the Tenth Circuit on March 20, 2014. PNM is continuing to evaluate the impacts of these matters, but is unable to predict their ultimate outcomes.

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SJGS Operating Permit Challenge

On February 16, 2012, EPA issued its response to a WEG petition objecting to SJGS’s operating permit granted by the NMED in January 2011. In its order, EPA required NMED to provide clarification on several of the matters raised by WEG. EPA’s order in this matter does not constitute a finding that the plant has violated any provision of the CAA or that it has exceded any emission limits.

In August 2012, NMED issued a response to the EPA order stating that SJGS’s operating permit would be reopened to make certain modifications to the permit. NMED issued a public notice regarding proposed modifications to the SJGS operating permit on September 19, 2012 and issued a revised operating permit on November 26, 2012. The revised permit includes changes to the SO₂ and particulate matter emission limits that were previously incorporated into the SJGS NSR permit. In addition, the revised permit requires PNM to submit a compliance plan to address carbon monoxide (“CO”) emissions increases at SJGS Unit 2. PNM submitted a compliance plan in May 2013 and considers this matter resolved.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. EPA has issued draft guidance on how to determine whether areas in a state comply with the new 1-hour SO₂ NAAQS. On May 21, 2013, EPA released draft guidance on characterizing air quality in areas with limited or no monitoring data near existing SO₂ sources. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS. Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On June 4, 2013, Sierra Club and National Resource Defense Council issued a NOI to sue EPA for failure to issue non-attainment designations for areas they claim to be in violation of the 2010 1-hour SO₂ standard. On April 6, 2012, PNM filed an application for an amendment to its air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. In addition, this application included a proposal by PNM to install equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These modifications would help SJGS meet the NAAQS. It is anticipated that this technology would be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART at SJGS. See Regional Haze - SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 0.060-0.070 parts per million. EPA is reviewing its 2008 standard and has stated it intends to propose a new standard. Although EPA has not announced a timeline for its review, it may release new proposed standards in the second half of 2014. Depending upon where the standard for ozone is set, San Juan County, where SJGS is situated, could be designated as not attaining the standard for ozone. If that were to occur, NMED would have responsibility for bringing the county into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further NOx controls to meet a new ozone NAAQS. In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional NOx controls would be required as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree.

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Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs seek to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. The court appointed a special master to evaluate the technical arguments in the case and to address the detection and determination limits of the mercury monitors at SJGS and the appropriate brominated activated carbon injection rate that maximizes the reduction of mercury emissions from SJGS. The special master issued a report indicating he was unable to make a determination on either of these issues. In September 2012, PNM submitted objections to certain portions of the special master report and requested an evidentiary hearing. Also in September 2012, NMED and plaintiffs filed a motion asking the court to affirm certain findings in the special master report and order PNM to conduct additional mercury testing. The parties filed a joint status update on January 23, 2014, advising the court that the parties had reached an agreement, subject to final approval by each party’s respective managing body. If approved, the parties would file a stipulated order with the court. PNM cannot predict if the agreement will be approved, the court will approve a stipulated order, or the ultimate outcome of this matter.

Section 114 Request

In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA’s request. PNM is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required NSR permits and complies with the NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, the Four Corners owners may reinstate their motions to dismiss without risk of default. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various National Environmental Policy Act violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines, and enjoining operations at the seven mines. SJCC intervened in this matter and seeks to sever SJCC’s claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Endangered Species Act

In January 2011, the Center for Biological Diversity, Diné Citizens Against Ruining Our Environment, and San Juan Citizens Alliance filed a lawsuit in the United States District Court for the District of Colorado against the OSM and the DOI, alleging that OSM failed to engage in mandatory ESA consultation with the United States Fish and Wildlife Service prior to authorizing the renewal of an operating permit for the mine that serves Four Corners. The lawsuit alleges that activities at the mine, including mining and the disposal of coal combustion residue, will adversely affect several endangered species and their critical habitats. The lawsuit requested the court to vacate and remand the mining permit and enjoin all activities carried out under the permit until OSM has complied with the ESA. Neither PNM nor APS was a party to the lawsuit. The court dismissed the lawsuit without prejudice and this matter is concluded.

Cooling Water Intake Structures

EPA issued its proposed cooling water intake structures rule in April 2011, which would provide national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The proposed rule would require facilities such as Four Corners and SJGS to either demonstrate that impingement mortality at its cooling water intakes does not exceed a specified rate or reduce the flow at those structures to less than a specified velocity and to take certain protective measures with respect to impinged fish. The proposed rule would also require these facilities to either meet the definition of a closed cycle recirculating cooling system or conduct a “structured site-specific analysis” to determine what site-specific controls, if any, should be required.

The proposed rule would require existing facilities to comply with the impingement mortality requirements as soon as possible, but no later than eight years after the effective date of the rule, and to comply with the entrainment requirements as soon as possible under a schedule of compliance established by the permitting authority. EPA was required to issue a final rule by June 27, 2013; however, that date was extended to January 14, 2014. On January 10, 2014, EPA announced it would not meet that deadline. On February 10, 2014, EPA indicated it would issue the final rule by April 17, 2014 and did not intend to seek any more extensions. PNM and APS continue to follow the rulemaking and are performing analyses to determine the potential costs of compliance with the proposed rule. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants. EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative

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EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. EPA is currently subject to a consent decree deadline to finalize the revised guidelines by May 2014, although it is in negotiations to obtain an extension of time. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of the former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM is unable to predict the outcome of this matter and does not believe the former generating station is the source of the nitrates or the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made.

Coal Combustion Byproducts Waste Disposal

Regulation

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

In June 2010, EPA published a proposed rule that includes two options for waste designation of coal ash. One option is to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team has been formed to develop a proposed rule.

On April 5, 2012, several environmental groups, including Sierra Club, filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review and revise RCRA’s regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary and that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members subsequently filed separate lawsuits in the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. On January 29, 2014, EPA entered into

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a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.

PNM advocates for the non-hazardous regulation of CCBs. If CCBs are ultimately regulated as a hazardous waste, costs could increase significantly. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of EPA’s or OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material impact on its operations, financial position, or cash flows.

Sierra Club Allegations

In April 2010, the Sierra Club filed suit against PNMR, PNM, SJCC, and BHP in the United States District Court for the District of New Mexico. In the complaint, as amended, Sierra Club alleged that activities at SJGS and SJCC’s San Juan mine were causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan mine constituted “open dumping” in violation of RCRA. The suit also includes claims against SJCC and BHP under the Surface Mine Control and Reclamation Act. The complaint requested judgment for injunctive relief, payment of civil penalties, and an award of plaintiffs’ attorney’s fees and costs.

On March 28, 2012, the parties filed an executed consent decree with the court, which was approved by the court on April 12, 2012, settling the litigation. Under the terms of the consent decree, the SJGS owners and SJCC will construct and operate a slurry wall and recovery trench, fund other environmental projects, and pay Sierra Club’s attorneys’ and experts’ fees. The total estimated cost of the settlement is $10.2 million, of which about $4.5 million is PNM’s share. Substantially all of the income statement impact related to this settlement was recorded in 2011. The consent decree also includes a release of claims and a covenant not to sue by Sierra Club. PNM is complying with the requirements of the consent decree.

Hazardous Air Pollutants (“HAPs”) Rulemaking

In December 2011, the EPA issued its final Mercury and Air Toxics Standards (“MATS”) to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities will generally have up to four years to demonstrate compliance with the new rule. PNM’s assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule although the plant may be required to install additional monitoring equipment. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At December 31, 2013 and 2012, prepayments for coal, which are included in other current assets, amounted to $12.3 million and $9.9 million. These amounts reflect delivery of a portion of the prepaid coal and its utilization due to the mine fire incident described below. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

APS purchases all of Four Corners’ coal requirements from a supplier that is also a subsidiary of BHP and has a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. In December 2012, BHP announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which the coal mine would be sold to the Navajo Nation. As discussed under The Clean Air Act - Regional Haze - Four Corners above, on December 30, 2013, ownership of the mine was transferred to an entity

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owned by the Navajo Nation and a new coal supply contract for Four Corners, expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until July 2016. Coal costs are anticipated to increase approximately 26% beginning in July 2016 under the terms of the new contract. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2013 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $55.7 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of December 31, 2013. At December 31, 2013 and 2012, liabilities, in current dollars, of $23.8 million and $26.8 million for surface mine reclamation and $7.8 million and $4.2 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the coal sales agreement. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $0.3 million in 2013 and $3.5 million in 2012. Future funding requirements are currently expected to approximate $0.6 million annually.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million (See Note 4) and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act - Regional Haze - SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. It has not been decided how costs would be divided among the owners of SJGS. Regulatory determinations made by the NMPRC may also affect the impact on PNM. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

San Juan Underground Mine Fire Incident

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC has completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembed it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. If further difficulties occur in the longwall mining operation, PNM and the other owners of SJGS would need to consider alternatives for operating SJGS, including running at less than full capacity or shutting down one or more units, the impacts of which cannot be determined at the current time.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM anticipates that it will recover through its FPPAC the portion of such costs allocable to its customers subject to New Mexico regulation. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between $17.4 million and $21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and has informed PNM that it has settled with its insurance carrier. PNM believes the settlement proceeds obtained by SJCC through its insurance carrier are reimbursable (in whole or in part) to the owners of SJGS through the

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coal sales agreement. PNM’s portion of the insurance recovery is estimated to be $18.7 million. PNM has credited its FPPAC balancing account for the amount of its estimated insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 17.

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”). Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS. In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM. In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal. The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed. PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

SJCC Arbitration

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues have been submitted to a panel for binding arbitration. In October 2013, the arbitration panel ruled on one issue and set other issues for hearing. The panel ruled that the SJGS participants owe SJCC $1.5 million for disputed mining costs. PNM’s share of this amount is $0.7 million of which $0.5 million was passed through PNM’s FPPAC. The remaining issues are: 1) whether the SJGS participants owe SJCC unbilled mining costs of $5.2 million or whether SJCC owes the SJGS participants overbilled mining costs of $1.1 million, and 2) whether SJCC billed the SJGS participants $13.9 million as mining costs that SJCC should have considered to be capital costs, which are not billable under the mining contract. PNM’s share of any amounts resulting from the arbitration would be approximately 46.3%. Of PNM’s share of the costs, approximately 33% of the first remaining issue as well as approximately 25% of the second remaining issue would be passed through PNM’s FPPAC and the rest would impact earnings. A hearing before the arbitration panel on the remaining issues is scheduled to be held in May 2014. PNM is unable to predict the outcome of the arbitration hearing.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 8%, all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM believes the assessment and the refund claim denial are without merit, but cannot predict the outcome of this matter.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry wide retrospective assessment program. If losses at any nuclear power plant covered by the program

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exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential assessment per incident for all three units is $38.9 million, with an annual payment limitation of $5.7 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2013, a sublimit of $1.5 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective assessments of $4.3 million for each retrospective assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Natural Gas Supply

PNM procures gas supplies for its power plants from third-party sources and contracts with third party transportation providers.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Delta, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a Federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.

PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a long-term supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees. The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding, and on November 1, 2013 issued a Partial Final Judgment and Decree of the Water Rights of the

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Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM is in the process of entering its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Conflicts at San Juan Mine Involving Oil and Gas Leaseholders

SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has prevailed in court in defeating the claims of other claimants. Several other claims and potential claimants remain. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders or the range of potential outcomes.

Rights-of-Way Matter

On January 28, 2014, the the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. If the challenge to the ordinance is unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ. FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated. PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not

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grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice. The allottees have not refiled their appeals. PNM continues to participate in this matter in order to preserve its interests regarding any PNM-acquired rights-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.

In a separate matter, in September 2012, forty-three landowners claiming to be Navajo allottees, filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. Although this matter is currently stayed, PNM continues to participate in this matter in order to preserve its interests regarding the right-of-way implicated in the appeal. PNM cannot predict the outcome of the proceeding or the range of potential outcomes at this time.


(17)	Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 16.

PNM

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” Prior to December 2012, the diversity requirements were 20% from wind energy, 20% from solar energy, 10% from other renewable technologies, and 1.5% from distributed generation with the distributed generation component increasing to 3% in 2015. In December 2012, the NMPRC issued an order that amended the diversity requirements to 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, and adopted other changes to its renewable energy rule, including the increase in the RCT discussed below. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. This weighting applies to future procurement approved and brought into service after December 18, 2013. The NMPRC has granted motions for rehearing of amendments in order to address the merits of the motions.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. The NMPRC established a RCT for 2011 of 2% of all customers’ aggregated overall annual electric charges that increased by 0.25% annually until reaching 3% in 2015. In December 2012, the NMPRC approved an amended RCT set at 3% of customers’ annual electric charges beginning in 2013 and continuing thereafter.

In August 2010, the NMPRC partially approved PNM’s revised 2010 procurement plan, including PNM’s investment in 22 MW of solar PV facilities at various PNM sites and the construction of a solar-storage demonstration project. Construction of these facilities was completed in 2011 at a total cost of approximately $95 million.

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In July 2010, PNM filed its renewable energy procurement plan for 2011. The NMPRC rejected PNM’s proposed REC-only purchase and ordered PNM to acquire actual renewable energy and the associated RECs. An appeal of the order was dismissed by the New Mexico Supreme Court. PNM made the required renewable energy procurement and is recovering those costs through the renewable rider discussed below.

In July 2011, PNM filed its renewable energy procurement plan for 2012. The plan requested a variance from the RPS due to RCT limitations. The plan was diversity-compliant based on the reduced RPS, except for non-wind/non-solar resources, which were not available. In December 2011, the NMPRC approved PNM’s 2012 plan, but ordered PNM to spend an additional $0.9 million on renewable procurements in 2012. PNM is recovering the costs of the supplemental procurements through the renewable rider discussed below. The NMPRC also required PNM to file its 2013 renewable energy procurement plan by April 30, 2012. The 2013 plan proposed procurements for 2013 and 2014 of 20 MW of PNM-owned solar PV facilities, at an estimated cost of $45.5 million, wind and solar REC purchases in 2013, and a PPA for the output of the new 10 MW Lightning Dock Geothermal facility. The plan also included an additional procurement of 2 MW of PNM-owned solar PV facilities at an estimated cost of $4.5 million to supply the energy sold under PNM’s voluntary renewable energy tariff. The plan would enable PNM to comply with the statutory RPS in 2013, but required a variance from the NMPRC’s diversity requirements in 2013 while the proposed geothermal facilities were being constructed. The NMPRC approved the plan in December 2012, but reduced the additional solar PV procurement from 2 MW to 1.5 MW. In 2013, PNM made renewable procurements consistent with the 2013 plan approved by the NMPRC. Construction of the solar PV facilities was completed in 2013 at a cost of $48.9 million. The geothermal facility began providing power to PNM in January 2014. The current output of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. PNM does not believe this delay will affect its ability to comply with its 2014 non-wind/non-solar diversity requirements, as amended in December 2012.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s proposed procurements include 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind facility having an aggregate capacity of 102 MW beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013.

PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

Renewable Energy Rider

On August 14, 2012, the NMPRC authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The approved rates were $0.0022335 per KWh in 2012 and $0.0028371 per KWh in 2013. The order disapproved the recovery of the cost of a supplemental REC procurement ordered by the NMPRC in the 2012 procurement plan case because the NMPRC had not yet acted on the specific $0.9 million procurement proposed by PNM. The NMPRC subsequently approved the supplemental REC procurement, but ordered that a hearing be held prior to inclusion of the costs in the rider. Upon NMPRC approval, PNM implemented the rider on August 20, 2012. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. Amounts collected under the rider were capped at $18.0 million in 2012 and $24.6 million in 2013, which amounts were not exceeded. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in 2013, adjusted for weather and other items not representative of normal operations, exceeded 10.5%, which did not occur, PNM would have been required to refund the amount over 10.5% to customers during May through December 2014.

In compliance with the NMPRC’s rate rider order, PNM filed a notice to implement an increase in the current rider rate effective with May 2013 bills. On May 15, 2013, the NMPRC approved the requested increase. PNM implemented the new rate of $0.0030468 per KWh on May 28, 2013.

In its 2014 renewable energy procurement plan described above, PNM proposed to increase the rider rate to $0.0044391 effective January 1, 2014. This increase was approved by the NMPRC on December 18, 2013.

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Energy Efficiency and Load Management

Program Costs

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue.

In September 2010, PNM filed an energy efficiency program application for programs to be offered beginning July 1, 2011. The NMPRC issued an order in June 2011 that approved a rider recovery amount of $17.1 million in program costs. The new rider rate was effective with bills rendered July 27, 2011.

In April 2011, PNM filed a reconciliation of energy efficiency program costs and collections as of December 31, 2010. Included in this filing was an adjustment of the adder amount to reflect the measured and verified savings for 2010 program participation. After a hearing, the NMPRC issued an order in November 2011 that authorized recovery of substantially all of the $2.6 million in under-collected program costs.

In October 2012, PNM filed an energy efficiency program application for programs to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive of $4.2 million. PNM subsequently revised its proposed profit incentive to $2.9 million. The NMPRC approved PNM’s program application and an annual profit incentive of $1.7 million on November 6, 2013.

Disincentives/Incentives

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010 PNM began implementing a NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In July 2011, the New Mexico Supreme Court annulled and vacated the order adopting the rule and remanded the matter to the NMPRC. As a result of the Supreme Court decision, PNM filed revised tariffs and ceased collecting this adder for 2010 program savings on August 21, 2011. Of the $4.2 million authorized for recovery, $2.6 million was collected through August 20, 2011.

In June 2011, prior to the Supreme Court decision, the NMPRC approved PNM-specific incentives for savings due to programs implemented in 2011. PNM collected approximately $1.3 million, on an annual basis, in incentive revenues through November 2013 consistent with this order. After the Supreme Court decision vacating the rule, the NMPRC initiated a proceeding to determine whether PNM should be required to cease collecting the PNM-specific incentives and to refund such revenues collected since December 2010. In November 2011, the NMPRC issued orders that PNM was not required to refund any incentive revenues and is authorized to continue collecting the incentives. However, in an order on rehearing, which it subsequently rescinded, the NMPRC reduced the amount of the PNM-specific incentives. In March 2012, the Supreme Court granted PNM’s motion to vacate the rehearing order and dismissed PNM’s appeal. In a separate appeal and writ proceeding in the Supreme Court, NMIEC and the NMAG sought to overturn the NMPRC order allowing PNM to continue to collect incentives in light of the 2011 Supreme Court decision. On May 21, 2012, the Supreme Court dismissed the writ proceeding. On September 20, 2013, the Supreme Court affirmed the NMPRC’s decision authorizing the PNM-specific incentives and remanded the case to the NMPRC. On October 2, 2013, the NMPRC closed the docket.

On March 27, 2013, PNM filed its reconciliation for actual energy efficiency program costs, associated incentives, and actual collections for calendar year 2012. The reconciliation filing showed a net over-recovery of $0.2 million, composed of an over-recovery of $1.0 million of program costs and an under-recovery of incentives of $0.8 million. PNM subsequently revised the estimated incentive under-recovery to $0.5 million. PNM and the NMPRC staff filed a motion seeking to substitute the new reconciliation filing with a proposed effective date of May 28, 2013. On April 24, 2013, the NMPRC issued an order granting the motion. PNM implemented the new rate on May 28, 2013.

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Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. Included in the proposed rule is a provision that would limit incentive awards to an amount equal to the product (expressed in dollars) of the utility’s WACC (expressed as a percent) and its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013.

2010 Electric Rate Case

PNM filed its 2010 Electric Rate Case application with the NMPRC in June 2010 for rate increases totaling $165.2 million for all PNM retail customers to be effective April 1, 2011. The application proposed separate rate increases for customers served by TNMP prior to its acquisition by PNMR (“PNM South”) and other customers of PNM (“PNM North”). PNM also proposed to implement a FPPAC for PNM South. The filed revenue requirements were based on a future test period ending December 31, 2011.

On August 21, 2011, PNM implemented a $72.1 million annual increase in rates as authorized by an order of the NMPRC, which modified a stipulation agreed to by PNM and several other parties. The amended stipulation limits the amount that can be recovered on an annual basis for fuel costs, renewable energy costs, and energy efficiency costs during certain years. Costs in excess of the limits are deferred, without carrying costs, for recovery in future periods. The fuel cost caps are $38.8 million for the FPPAC year beginning July 1, 2012, which PNM began collecting at that time, and $36.2 million for the FPPAC year beginning July 1, 2013. PNM estimates that the caps will result in approximately $48.6 million of FPPAC costs being deferred for future collection at June 30, 2014. This amount reflects the pending settlement in the FPPAC Continuation Application case discussed below. The portion of the costs and insurance recovery attributable to customers covered by the FPPAC resulting from the mine fire incident discussed in Note 16 are included in the FPPAC amounts.

As a result of the modified stipulation, PNM recorded pre-tax losses for the $10.0 million of fuel costs that will not be recovered through the FPPAC and $7.5 million for other costs that will not be recovered in rates. These amounts were recorded as of June 30, 2011 and are reflected as regulatory disallowances on PNM’s Consolidated Statement of Earnings.

FPPAC Continuation Application

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain 10% of its off-system sales margin, and to apply the same carrying charge rate to both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed that would resolve this case. The settlement would allow PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, would resolve all costs related to the San Juan Coal mine fire discussed in Note 16, resolve the ratemaking treatment for the coal pre-treatment at SJGS until the next rate case, require PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and require PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the $10.5 million write-off as a regulatory disallowance in 2013. A public hearing on the stipulation was held on February 25, 2014. The hearing examiner stated at the hearing’s conclusion that he would recommend approval of the settlement in its entirety to the NMPRC. PNM is unable to predict the outcome of this proceeding.

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Integrated Resource Plan

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. In its most recent IRP, which was filed in July 2011, PNM indicated that it planned to meet its anticipated load growth through a combination of new natural gas-fired generating plants, renewable energy resources, load management, and energy efficiency programs. As required by NMPRC rules, PNM utilized a public advisory group process during the development of the 2011 IRP. Two protests were filed to the IRP requesting rejection of the plan. On September 18, 2013, the NMPRC issued an order that closed the docket on the 2011 IRP.

PNM has initiated the process to prepare its 2014 IRP. Public participation meetings have been held. The 2014 IRP is scheduled to be filed at the NMPRC by June 30, 2014.

Emergency FPPAC

In 2008, the NMPRC authorized PNM to implement an Emergency FPPAC from June 2, 2008 through June 30, 2009. The NMPRC order approving the Emergency FPPAC also provided that if PNM’s base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM’s motion and recommended that PNM be required to refund the amount collected. Auditors selected by the NMPRC found that PNM was prudent in operating its base load units and in securing replacement power but had not obtained prior NMPRC approval in the manner required by the NMPRC order. PNM continues to assert that its recovery of replacement power costs was proper and did not violate the NMPRC’s order. The NMPRC has not ruled on this matter. Under the terms of the approved stipulation in the 2010 Electric Rate Case, the parties to the stipulation, including the NMPRC staff, jointly requested that the NMPRC take no further action in this matter and close the docket. No party opposed that request. Although the NMPRC has not acted on the joint request, the NMPRC electronic docket shows the docket closed.

Applications for Approvals to Purchase Delta

As discussed in Note 9, PNM has entered in to an agreement to purchase Delta, a 132 MW natural gas peaking unit from which PNM currently acquires energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. Closing on the purchase will occur once certain environmental issues are resolved.

Application for Approval of La Luz Generating Station

On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a 40 MW gas-fired generating facility near Belen, New Mexico. The application also requested a determination of related ratemaking principles and treatment. The facility is expected to cost approximately $63.2 million and go into service in the first quarter of 2016. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. Both contracts allow PNM to cancel if NMPRC approval is not obtained. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a rate base value of up to $56 million for the facility. PNM is unable to predict the outcome of this matter.

San Juan Generating Station Units 2 and 3 Retirement

As discussed in Note 16, on December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2016. In that application, PNM also seeks approval to recover the net book value of SJGS Units 2 and 3 at the date of retirement, for a CCN to include PNM’s share of PVNGS Unit 3 as a resource to serve New Mexico consumers, authority to install SNCRs on SJGS Units 1 and 4, and a CCN to exchange 78 MW in SJGS for the same amount of capacity in SJGS Unit 4. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM requested the NMPRC issue its final ruling on the application no later than December 2014. A public hearing on the application has been scheduled to commence on August 19, 2014. PNM is unable to predict the outcome of this matter.

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Transmission Rate Case

In October 2010, PNM filed a notice with FERC to increase its wholesale electric transmission revenues by $11.1 million annually, based on a return on equity of 12.25%. The filing also sought to revise certain Open Access Transmission Tariff provisions and bi-lateral contractual terms. In December 2010, FERC issued an order accepting PNM’s filing and suspending the proposed tariff revisions for five months. The proposed rates were implemented on June 1, 2011, subject to refund. The rate increase applied to all of PNM’s wholesale electric transmission service customers, which include other utilities, electric cooperatives, and entities that use PNM’s transmission system to transmit power at the wholesale level. The rate increase did not impact PNM’s retail customers. On January 2, 2013, FERC approved an unopposed settlement agreement, which increases transmission service revenues by $2.9 million annually. In addition, the parties agreed that if PNM files for a formula based rate change within one year from FERC’s approval of the settlement agreement, no party will oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM refunded amounts collected in excess of the settled rates in January 2013 concluding this matter.

Formula Transmission Rate Case

On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. The rates resulting from PNM’s application are intended to replace the rates approved by the FERC on January 2, 2013 in the transmission rate case discussed above. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity, and authority to adjust transmission rates annually based on an approved formula. The proposed $3.2 million rate increase would be in addition to the $2.9 million rate increase approved by the FERC on January 2, 2013.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its return-on-equity (“ROE”) using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003 ; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC on January 2, 2013. The new rates will apply to all of PNM’s wholesale electric transmission service customers. The new rates will not apply to PNM’s retail customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. Settlement negotiations are ongoing concerning issues in this proceeding. PNM is unable to predict the outcome of this proceeding.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc. Rate Case

In September 2011, PNM filed an unexecuted amended sales agreement between PNM and NEC with FERC. The agreement proposed a cost of service based rate for the electric service and ancillary services PNM provides to NEC, which would result in an annual increase of $8.7 million or a 39.8% increase over existing rates. PNM also requested a FPPAC and full recovery of certain third-party transmission charges PNM incurs to serve NEC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and PNM filed for the necessary FERC approval on December 6, 2012. The settlement agreement provided for an annual increase of $5.3 million, an extension of the contract for 10 years, and an agreement that PNM will be able to file an application for formula based rates to be effective in 2015. On April

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December 31, 2013, 2012 and 2011

5, 2013, FERC approved the settlement agreement. PNM has refunded the amounts collected in excess of the settled rates concluding this matter.

City of Gallup, New Mexico Contract

PNM provides both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement. Revenue from Gallup will have increased by $3.1 million during the term of the amended agreement.

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On January 13, 2014, PNM was notified that its proposal was not the highest ranked. Gallup has stated that a contract is being negotiated with the top-ranked bidder. If those negotiations do not result in the execution of a contract, Gallup could enter into negotiations with PNM or others. If a contract is executed with the top-ranked bidder, PNM’s contract with Gallup would expire on June 30, 2014. PNM’s 2013 revenues for power sold under the Gallup contract were $11.7 million. PNM is unable to predict the outcome of this matter.

TNMP

Interest Rate Compliance Tariff

Following a revision of the interest rate on TNMP’s CTC, TNMP filed a compliance tariff to implement the new lower 8.31% rate. Intervenors asserted objections and, after regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. Ultimately, the Texas 3^rd Court of Appeals reaffirmed the PUCT’s decision. Due to the new retroactive ratemaking theory contained in the Texas 3^rd Court of Appeals opinion, TNMP recorded a pre-tax regulatory disallowance of $3.9 million in 2011 to reflect the impact of applying the 8.31% rate retroactively. In June 2012, the Texas Supreme Court denied TNMP’s petition for review. TNMP filed a motion for rehearing, which was denied in August 2012 concluding this matter.

2010 Rate Case

In August 2010, TNMP filed with the PUCT for a $20.1 million increase in revenues. In January 2011, the PUCT approved a settlement that provided for a revenue increase of $10.25 million, a return on equity of 10.125%, and a target 55%/45% debt-equity capital structure. The PUCT approved the settlement in January 2011. TNMP implemented the new rates on February 1, 2011.

2010 Rate Case Expense Proceeding

The determination of the amount of reasonable rate case expenses incurred by TNMP and other parties in TNMP’s 2010 Rate Case was severed into a separate proceeding. The parties agreed to a settlement of the case, which was approved by the PUCT in May 2011. TNMP began collecting $2.8 million over three years on July 1, 2011.

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.3 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.

In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT has requested comments and convened a public meeting to hear various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.

On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment. The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service will be borne by opt-out customers

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT are required to initiate proceedings to establish these charges.

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP’s filing seeks recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48. An additional $0.5 million in ongoing expenses would be recovered via a proposed monthly charge of $38.99. A hearing on this matter is scheduled for April 8, 2014. TNMP cannot predict the outcome of this proceeding although TNMP does not expect it to have a material impact on its financial position, results of operations, or cash flows.

Remand of ERCOT Transmission Rates for 1999 and 2000

Following a variety of appeals, the ERCOT transmission rates approved in 1999 and 2000 were remanded back to the PUCT. These dockets concern the recalculation of rates for the fourth quarter of 1999 and all of 2000. In October 2011, TNMP joined in a non-unanimous settlement of the issues relating to resettlement of the last four months of 1999. In January 2012, the PUCT approved the non-unanimous settlement. TNMP received $1.6 million under the settlement. In June 2012, TNMP filed its transmission cost recovery factor filing (“TCRF”) seeking $3.2 million in additional transmission costs. The PUCT staff requested a hearing asserting the settlement proceeds from the 1999 remand settlement need to be credited against the costs TNMP requested in its TCRF. TNMP maintains that the settlement proceeds should not be passed on to customers since TNMP was unable to recover those costs in 1999. Subsequently, the PUCT staff agreed to interim rate relief permitting TNMP to add $1.6 million in uncontested costs to its existing TCRF and add $1.6 million in costs in a subsequent TCRF if TNMP is successful in the contested case. The ALJ approved the interim relief on July 16, 2012. TNMP implemented the interim rates on September 1, 2012. On September 26, 2012, the contested portion of the case was remanded to the PUCT pursuant to an agreed resolution that permits the $1.6 million in interim rates to become final and authorizes TNMP to institute a surcharge in March 2013 to collect the additional $1.6 million in initially disputed costs plus interest at the PUCT under-billing rate. The PUCT approved the joint resolution on November 19, 2012.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor. The PUCT approved TNMP’s collection of its 2010 energy efficiency program costs of $2.6 million over 11 months beginning February 1, 2010. Recovery of the 2011 program costs of $2.7 million were approved for collection beginning January 1, 2011. In September 2011, the PUCT approved a settlement that allows TNMP to collect the estimated 2012 energy efficiency program costs of $3.4 million and a $0.3 million bonus for 2010. TNMP’s new rates were effective January 1, 2012. On August 28, 2012, the PUCT approved a settlement that permits TNMP to collect estimated 2013 program costs of $4.8 million, plus recovery of an aggregate of $0.4 million in under-collected costs from prior years, case expenses, and a performance bonus for 2011. TNMP’s new rates were effective January 1, 2013. On May 15, 2013, TNMP filed its 2014 energy efficiency cost recovery factor application with the PUCT. The application seeks approval to collect $5.6 million, which includes $4.7 million in estimated program expenses for 2014, a $0.7 million performance bonus for 2012, a refund of $0.1 million over collection of energy savings expenses for the 2012 program year, and case expenses. In July 2013, the parties filed a settlement to permit TNMP to collect the substantially all of the requested $5.6 million beginning March 1, 2014. The settlement was approved by the PUCT on October 25, 2013.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.

On August 23, 2012, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The application reflected an increase in total rate base of $26.4 million and requested an increase in revenues of $2.5 million annually. The PUCT approved the interim adjustment and TNMP implemented it on September 27, 2012.

On January 31, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $21.9 million, which will increase revenues $2.9 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 20, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $18.1 million, which would increase revenues by $2.8 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.

On January 21, 2014, TNMP filed an application to further update its transmission rates resulting from changes in its invested capital. The requested increase in total rate base is $18.2 million, which would increase revenues by $2.9 million annually. TNMP has requested approval by March 23, 2014.

Periodic Distribution Rate Adjustment

In September 2011, the PUCT approved a new rule permitting interim rate adjustments to reflect changes in investments in distribution assets. The rule permits distribution utilities to file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data.

Consolidated Tax Savings Adjustment

On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment (“CTSA”) from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011


(18)	Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. TNMP provides transmission and distribution services to First Choice. On November 1, 2011, PNMR sold First Choice (Note 3). TNMP revenues from First Choice through October 31, 2011 are considered related party revenues and included in the table below. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. These services are billed at cost on a monthly basis to the business units. Optim Energy was a related party prior to September 23, 2011 (Note 20). PNMR Services Company provided corporate services to Optim Energy under a services agreement. There was also a services agreement for Optim Energy to provide services to PNMR.

PNMR files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PNMR and each of its affiliated companies. These agreements provide that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PNMR. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PNMR to the extent that PNMR is able to utilize those benefits.

See Note 6 for information on intercompany borrowing arrangements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:



	Year Ended December 31,
	2013		2012		2011
			(In thousands)
Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	—	$	—	$	33,813
Services billings:
PNMR to PNM	92,597		99,986		98,914
PNMR to TNMP	28,937		29,110		29,353
PNM to TNMP	562		595		550
TNMP to PNMR	7		15		164
PNMR to Optim Energy	—		—		4,083
Optim Energy to PNMR	—		—		23
Income tax sharing payments:
PNMR to TNMP	—		1,951		—
PNMR to PNM	77,433		63,114		—
TNMP to PNMR	3,643		—		—
Interest payments:
PNM to PNMR	4		1		54
TNMP to PNMR	481		137		40

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December 31, 2013, 2012 and 2011


(19)	Accumulated Other Comprehensive Income (Loss)

AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:



	Accumulated Other Comprehensive Income (Loss)
	Unrealized Gain on Available-for-Sale Securities			Pension Liability Adjustment			Fair Value Adjustment for Cash Flow Hedges			Total
				(In thousands)
PNMR
Balance at December 31, 2010	$	16,211		$	(83,254	)	$	(1,623	)	$	(68,666	)
Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,292			3,448			(27,511		)
Income tax impact of amounts reclassified	13,956			(1,699		)	(1,230		)	11,027
Other OCI changes (pre-tax)	34,295			(2,958		)	(1,002		)	30,335
Income tax impact of other OCI changes	(13,577		)	1,187			349			(12,041		)
Net change after income taxes	(577		)	822			1,565			1,810
Balance at December 31, 2011	15,634			(82,432		)	(58		)	(66,856		)
Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			182			(32,476		)
Income tax impact of amounts reclassified	14,755			(1,825		)	(65		)	12,865
Other OCI changes (pre-tax)	38,548			(30,084		)	(428		)	8,036
Income tax impact of other OCI changes	(15,262		)	11,910			153			(3,199		)
Net change after income taxes	772			(15,388		)	(158		)	(14,774		)
Balance at December 31, 2012	16,406			(97,820		)	(216		)	(81,630		)
Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			207			(5,385		)
Income tax impact of amounts reclassified	4,734			(2,524		)	(73		)	2,137
Other OCI changes (pre-tax)	27,419			17,136			(279		)	44,276
Income tax impact of other OCI changes	(10,855		)	(6,781		)	98			(17,538		)
Net change after income taxes	9,342			14,195			(47		)	23,490
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



	Accumulated Other Comprehensive Income (Loss)
	Unrealized Gain on Available-for-Sale Securities			Pension Liability Adjustment			Fair Value Adjustment for Cash Flow Hedges			Total
				(In thousands)
PNM
Balance at December 31, 2010	$	16,211		$	(82,981	)	$	(16	)	$	(66,786	)
Amounts reclassified from AOCI (pre-tax)	(35,251		)	4,278			27			(30,946		)
Income tax impact of amounts reclassified	13,956			(1,694		)	(11		)	12,251
Other OCI changes (pre-tax)	34,295			(3,369		)	—			30,926
Income tax impact of other OCI changes	(13,577		)	1,334			—			(12,243		)
Net change after income taxes	(577		)	549			16			(12		)
Balance at December 31, 2011	15,634			(82,432		)	—			(66,798		)
Amounts reclassified from AOCI (pre-tax)	(37,269		)	4,611			—			(32,658		)
Income tax impact of amounts reclassified	14,755			(1,825		)	—			12,930
Other OCI changes (pre-tax)	38,548			(30,084		)	—			8,464
Income tax impact of other OCI changes	(15,262		)	11,910			—			(3,352		)
Net change after income taxes	772			(15,388		)	—			(14,616		)
Balance at December 31, 2012	16,406			(97,820		)	—			(81,414		)
Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			—			(5,592		)
Income tax impact of amounts reclassified	4,734			(2,524		)	—			2,210
Other OCI changes (pre-tax)	27,419			17,136			—			44,555
Income tax impact of other OCI changes	(10,855		)	(6,781		)	—			(17,636		)
Net change after income taxes	9,342			14,195			—			23,537
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	—		$	(57,877	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



	Accumulated Other Comprehensive Income (Loss)
	Unrealized Gain on Available-for-Sale Securities		Pension Liability Adjustment			Fair Value Adjustment for Cash Flow Hedges			Total
			(In thousands)
TNMP
Balance at December 31, 2010	$	—	$	(275	)	$	(1,210	)	$	(1,485	)
Amounts reclassified from AOCI (pre-tax)	—		13			2,997			3,010
Income tax impact of amounts reclassified	—		(5		)	(1,068		)	(1,073		)
Other OCI changes (pre-tax)	—		414			(1,207		)	(793		)
Income tax impact of other OCI changes	—		(147		)	430			283
Net change after income taxes	—		275			1,152			1,427
Balance at December 31, 2011	—		—			(58		)	(58		)
Amounts reclassified from AOCI (pre-tax)	—		—			182			182
Income tax impact of amounts reclassified	—		—			(65		)	(65		)
Other OCI changes (pre-tax)	—		—			(428		)	(428		)
Income tax impact of other OCI changes	—		—			153			153
Net change after income taxes	—		—			(158		)	(158		)
Balance at December 31, 2012	—		—			(216		)	(216		)
Amounts reclassified from AOCI (pre-tax)	—		—			207			207
Income tax impact of amounts reclassified	—		—			(73		)	(73		)
Other OCI changes (pre-tax)	—		—			(279		)	(279		)
Income tax impact of other OCI changes	—		—			98			98
Net change after income taxes	—		—			(47		)	(47		)
Balance at December 31, 2013	$	—	$	—		$	(263	)	$	(263	)

Pre-tax amounts reclassified from AOCI related to Unrealized Gain on Available-for-Sale Securities are included in Gains on available-for-sale securities in the Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to Pension Liability Adjustment are reclassified to Operating Expenses - Administrative and general in the Consolidated Statements of Earnings. For the year ended December 31, 2013, approximately 18.7% of the amount reclassified was capitalized into construction work in process and approximately 3.0%was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to Fair Value Adjustment for Cash Flow Hedges are reclassified to Interest Charges in the Consolidated Statements of Earnings. An insignificant amount is then capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in Income Taxes in the Consolidated Statements of Earnings.

(20) Optim Energy

In January 2007, Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding energy markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each had a 50 percent ownership interest in Optim Energy, a limited liability company. Optim Energy had a bank financing arrangement that provided for a revolving line of credit, the issuance of bank letters of credit support certain contractual arrangements, and a maturity of May 31, 2012. Cascade and ECJV guaranteed Optim Energy’s obligations on this facility. Optim Energy’s debt was non-recourse to PNMR.

Beginning in 2009, Optim Energy was affected by adverse market conditions, primarily low natural gas and power prices. Under GAAP, there were indicators of impairment that required PNMR to perform an impairment analyses of its investment in Optim Energy as of December 31, 2010. PNMR’s analysis indicated that its entire investment in Optim Energy was impaired at December 31, 2010. Accordingly, PNMR reduced the carrying value of its investment in Optim Energy to zero at December 31,

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December 31, 2013, 2012 and 2011

2010. 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.

As a result of the adverse market conditions described above, PNMR (in collaboration with Optim Energy and ECJV) assessed various strategic alternatives relating to Optim Energy. On September 23, 2011, PNMR, ECJV, and Cascade agreed to restructure Optim Energy and ECJV made an equity contribution to Optim Energy in exchange for an increased ownership interest, which resulted in PNMR’s ownership in Optim Energy being reduced from 50% to 1%. As part of this transaction, PNMR did not make any equity contribution to Optim Energy nor was it required to make any future contribution. PNMR Services Company provided certain corporate services to Optim Energy through December 31, 2011 and thereafter with respect to certain open tax matters. 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.

As discussed above, PNMR fully impaired its investment in Optim Energy at December 31, 2010 and did not recognize losses of Optim Energy from January 1, 2011 through September 23, 2011 when PNMR ceased to account for its investment using the equity method of accounting. Accordingly, Optim Energy has no impact on PNMR’s 2011 statement of earnings and statement of cash flows. For the nine months ended September 30, 2011, Optim Energy reported operating revenues of $256.8 million, margin of $84.7 million, and a net loss of $21.4 million.

(21) Goodwill and Other Intangible Assets; Impairments

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its June 6, 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM. Additionally, the trade name “First Choice” and the First Choice customer list were acquired in the TNP acquisition. The trade name was considered to have an indefinite useful life; therefore, no amortization was recorded. The useful life of the customer list was estimated to be approximately eight years. As discussed in Note 3, PNMR completed the sale of First Choice on November 1, 2011. As a result, the goodwill and other intangible assets of First Choice are no longer included in PNMR’s Consolidated Balance Sheet and PNMR no longer has any other intangible assets.

GAAP requires the Company to evaluate its goodwill and non-amortizing intangible assets for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill or intangible assets may be impaired. The Company evaluates goodwill impairment as of April 1st of each year. PNMR’s current reporting units that have goodwill are PNM and TNMP. 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.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment, an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit’s fair value with its carrying amount. An entity places more weight on the events and circumstances that most affect a reporting unit’s fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise requires the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011

two, an impairment loss would be reflected in results of operations. Prior to 2012, the Company also compared the fair value of non-amortizing intangibles other than goodwill to the recorded value.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units, but a quantitative analysis for others. Prior to 2013, the Company performed qualitative analyses for all reporting units having goodwill. For the annual evaluation performed as of April 1, 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit.

The 2013 qualitative analysis for the TNMP reporting unit, which has goodwill of $226.7 million, included the consideration of various reporting unit specific factors as well as industry and macroeconomic factors to determine whether these factors were reasonably likely to have a material impact on the fair value of the reporting unit. Factors considered included the results of the April 1, 2012 quantitative analysis, which indicated that fair value exceeded carrying value of the reporting unit by approximately 26%, current and long-term forecasted financial results, regulatory environment, credit rating, interest rate environment, absolute and relative price of PNMR’s common stock, and operating strategy. TNMP believes it is operating within a generally favorable regulatory environment, its historical and forecasted financial results are positive, and its credit is perceived positively. Based on the analysis of the relevant factors, PNMR concluded that it is more likely than not that the fair value of the TNMP reporting unit exceeds its carrying value.

For the PNM reporting unit, a discounted cash flow methodology was primarily used as the quantitative analysis to estimate the fair value of the 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 weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2013 and 2012 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 27% and 15%. An increase of 0.5% in the expected return on equity capital utilized in discounting the forecasted cash flows, would have reduced the excess of PNM’s fair value over carrying value to approximately 20% at April 1, 2013.

The annual evaluations performed as of April 1, 2013 and 2012 did not indicate impairments of the goodwill of any of PNMR's reporting units. Since the April 1, 2013 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values.

Prior annual evaluations have not indicated impairments of any of PNMR’s reporting units, except in 2008. During 2008, the market capitalization of PNMR’s common stock was significantly below book value. In addition, changes in the ERCOT market significantly impacted the results of operations of First Choice. The financial challenges facing First Choice were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in significant increases in the levels of uncollectible accounts. As a result, the Company recorded goodwill impairments of $51.1 million for PNM, $34.5 million for TNMP, and $88.8 million for First Choice in 2008. Pre-tax impairment losses of $42.6 million for the First Choice trade name and $4.8 million for the First Choice customer list were also recorded in 2008. Since 2008, the price of PNMR’s common stock has increased, improving the relationship between PNMR’s market capitalization and book value. In addition, improved regulatory treatment has been experienced by PNM in New Mexico and by TNMP in Texas. Furthermore, First Choice’s business became more stable, primarily due to more predictable power and fuel price patterns in the ERCOT market. These factors resulted in more predictable earnings and increased fair values of the reporting units. Since 2008, the annual evaluations have not indicated that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

(22) Quarterly Operating Results (Unaudited)

Unaudited operating results by quarters for 2013 and 2012 are presented below. In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2013, 2012 and 2011



	Quarter Ended
	March 31		June 30		September 30		December 31
	(In thousands, except per share amounts)
PNMR
2013
Operating revenues	$	317,665	$	347,599	$	399,730	$	322,929
Operating income	50,704		77,867		117,739		40,532
Net earnings	13,962		31,383		58,814		11,397
Net earnings attributable to PNMR	10,626		27,678		54,555		7,648
Net Earnings Attributable to PNMR per Common Share:
Basic	0.13		0.35		0.68		0.10
Diluted	0.13		0.34		0.68		0.10
2012
Operating revenues	$	305,374	$	323,860	$	390,411	$	322,758
Operating income	53,729		65,106		118,150		36,736
Net earnings	20,477		25,099		61,976		12,573
Net earnings attributable to PNMR	17,080		21,512		57,864		9,091
Net Earnings Attributable to PNMR per Common Share:
Basic	0.21		0.27		0.73		0.11
Diluted	0.21		0.27		0.72		0.11
PNM
2013
Operating revenues	$	257,894	$	279,690	$	326,026	$	252,702
Operating income	37,239		58,302		95,217		18,427
Net earnings	14,773		29,697		51,950		6,256
Net earnings attributable to PNM	11,569		26,124		47,823		2,639
2012
Operating revenues	$	250,416	$	260,094	$	321,731	$	260,023
Operating income	42,105		46,669		96,973		20,135
Net earnings	21,077		20,340		54,891		9,293
Net earnings attributable to PNM	17,812		16,885		50,911		5,943
TNMP
2013
Operating revenues	$	59,771	$	67,909	$	73,704	$	70,227
Operating income	13,054		19,667		22,254		17,210
Net earnings	3,726		8,339		10,106		6,919
2012
Operating revenues	$	54,958	$	63,766	$	68,680	$	62,736
Operating income	11,791		18,897		20,970		15,862
Net earnings	3,011		8,018		9,084		6,634

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

PNM Resources, Inc.:

We have audited and reported separately herein on the consolidated balance sheet of PNM Resources, Inc and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended. In connection with our audit of the aforementioned consolidated financial statements, we also audited the related financial statement schedules as listed within Item 15. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audit.

In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Public Service Company of New Mexico:

We have audited and reported separately herein on the consolidated balance sheet of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended. In connection with our audit of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed within Item 15. The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement schedule based on our audit.

In our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Texas-New Mexico Power Company:

We have audited and reported separately herein on the consolidated balance sheet of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2013, and the related consolidated statement of earnings, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year then ended. In connection with our audit of the aforementioned consolidated financial statements, we also audited the related financial statement schedule as listed within Item 15. The financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statement schedule based on our audit.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

PNM Resources, Inc.

Albuquerque, New Mexico

We have audited the consolidated financial statements of PNM Resources, Inc. and subsidiaries (the "Company") as of December 31, 2012, and for each of the two years in the period ended December 31, 2012, and have issued our reports thereon dated March 1, 2013; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Company listed in Item 15 as of December 31, 2012 and for each of the two years in the period ended December 31, 2012. These consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth herein.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Public Service Company of New Mexico

Albuquerque, New Mexico

and

Texas-New Mexico Power Company

Lewisville, Texas

We have audited the consolidated financial statements of Public Service Company of New Mexico and subsidiaries and Texas-New Mexico Power Company and subsidiaries (the "Companies") as of December 31, 2012, and for each of the two years in the period ended December 31, 2012, and have issued our report thereon dated March 1, 2013; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Companies listed in Item 15 as of December 31, 2012 and for each of the two years in the period ended December 31, 2012. These consolidated financial statement schedules are the responsibility of the Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth herein.

/s/ DELOITTE & TOUCHE LLP

Phoenix, Arizona

March 1, 2013

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF EARNINGS



	Year ended December 31,
	2013			2012			2011
	(In thousands)
Operating Revenues	$	—		$	—		$	—
Operating Expenses	941			3,287			20,547
Operating income (loss)	(941		)	(3,287		)	(20,547		)
Other Income and Deductions:
Equity in earnings of subsidiaries	116,634			117,900			205,215
Other income	769			670			59
Other deductions	(22,825		)	(20,904		)	(34,124		)
Net other income (deductions)	94,578			97,666			171,150
Earnings Before Income Taxes	93,637			94,379			150,603
Income Tax Expense (Benefit)	(6,870		)	(11,168		)	(25,756		)
Net Earnings	$	100,507		$	105,547		$	176,359

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2013			2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	100,507		$	105,547		$	176,359
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	4,192			5,000			7,654
Deferred income tax expense	(51,820		)	(46,632		)	(34,396		)
Equity in (earnings) of subsidiaries	(116,634		)	(117,900		)	(205,215		)
Loss on reacquired debt	3,253			—			9,209
Stock based compensation expense	5,320			3,585			6,556
Changes in certain assets and liabilities:
Other current assets	28,460			(43,638		)	42,687
Other assets	46,558			34,096			59,975
Accounts payable	620			8			(1		)
Accrued interest and taxes	(9,266		)	(28,855		)	27,348
Other current liabilities	(146		)	3,876			4,765
Other liabilities	(27,756		)	(29,601		)	(12,854		)
Net cash flows from operating activities	(16,712		)	(114,514		)	82,087
Cash Flows From Investing Activities:
Utility plant additions	(960		)	(7,524		)	—
Investments in subsidiaries	(13,800		)	—			(43,000		)
Cash dividends from subsidiaries	158,772			61,406			285,757
Net cash flows from investing activities	144,012			53,882			242,757
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(37,600		)	120,900			(15,300		)
Short-term borrowings (repayments) – affiliate, net	—			—			300
Repayment of long-term debt	(29,468		)	(2,387		)	(60,391		)
Purchase of preferred stock	—			—			(73,475		)
Purchase of common stock	—			—			(125,683		)
Proceeds from stock option exercise	4,618			11,684			5,622
Purchases to satisfy awards of common stock	(13,807		)	(25,168		)	(10,104		)
Dividends paid	(50,980		)	(44,609		)	(45,128		)
Other, net	—			—			(747		)
Net cash flows from financing activities	(127,237		)	60,420			(324,906		)
Change in Cash and Cash Equivalents	63			(212		)	(62		)
Cash and Cash Equivalents at Beginning of Period	29			241			303
Cash and Cash Equivalents at End of Period	$	92		$	29		$	241
Supplemental Cash Flow Disclosures:
Interest paid	$	14,510		$	15,007		$	19,215
Income taxes paid (refunded), net	$	22,378		$	1,501		$	5,454

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

BALANCE SHEETS



	December 31,
	2013			2012
	(In thousands)
Assets
Cash and cash equivalents	$	92		$	29
Intercompany receivables	136,387			108,875
Income taxes receivable	14,989			41,434
Other, net	8,544			2,204
Total current assets	160,012			152,542
Property, plant and equipment, net of accumulated depreciation of $9,167 and $8,262	26,601			25,642
Long-term investments	—			3,651
Investment in subsidiaries	1,683,321			1,688,168
Other long-term assets	53,892			49,302
Total long-term assets	1,763,814			1,766,763
	$	1,923,826		$	1,919,305
Liabilities and Stockholders’ Equity
Short-term debt	$	100,000		$	137,600
Short-term debt-affiliate	8,819			8,819
Current maturities of long-term debt	—			2,530
Accrued interest and taxes	2,797			3,127
Other current liabilities	16,876			13,218
Total current liabilities	128,492			165,294
Long-term debt	118,766			142,592
Other long-term liabilities	2,999			3,232
Total liabilities	250,257			311,118
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,178,369			1,182,819
Accumulated other comprehensive income (loss), net of tax	(58,140		)	(81,630		)
Retained earnings	553,340			506,998
Total common stockholders’ equity	1,673,569			1,608,187
	$	1,923,826		$	1,919,305

See Notes 6, 7, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

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SCHEDULE II

PNM RESOURCES, INC. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS



			Additions				Deductions
Description	Balance at beginning of year		Charged to costs and expenses		Charged to other accounts		Write-offs and other			Balance at end of year
			(In thousands)
Allowance for doubtful accounts, year ended December 31:
2011	$	11,178	$	24,116	$	—	$	33,516	⁽¹⁾	$	1,778
2012	$	1,778	$	3,367	$	—	$	3,394		$	1,751
2013	$	1,751	$	2,849	$	—	$	3,177		$	1,423

⁽¹⁾ Includes reduction of $11,818 due to the sale of First Choice on November 1, 2011.

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SCHEDULE II

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

VALUATION AND QUALIFYING ACCOUNTS



			Additions				Deductions
Description	Balance at beginning of year		Charged to costs and expenses		Charged to other accounts		Write-offs		Balance at end of year
			(In thousands)
Allowance for doubtful accounts, year ended December 31:
2011	$	1,483	$	3,736	$	—	$	3,441	$	1,778
2012	$	1,778	$	3,384	$	—	$	3,411	$	1,751
2013	$	1,751	$	2,864	$	—	$	3,192	$	1,423

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SCHEDULE II

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

VALUATION AND QUALIFYING ACCOUNTS



			Additions					Deductions
Description	Balance at beginning of year		Charged to costs and expenses			Charged to other accounts		Write-offs			Balance at end of year
			(In thousands)
Allowance for doubtful accounts, year ended December 31:
2011	$	—	$	33		$	—	$	33		$	—
2012	$	—	$	(17	)	$	—	$	(17	)	$	—
2013	$	—	$	(15	)	$	—	$	(15	)	$	—

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


ITEM 9A.	CONTROLS AND PROCEDURES

PNMR

(a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this annual report, PNMR conducted an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

(b) Management’s report on internal control over financial reporting.

“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-2. This report is incorporated by reference herein. PNMR’s internal control over financial reporting as of December 31, 2013 has been audited by KPMG LLP, as an independent registered public accounting firm, as stated in their report which is included herein.

There have been no changes in PNMR’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, PNMR’s internal control over financial reporting.

PNM

(a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this annual report, PNM conducted an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

(b) Management’s report on internal control over financial reporting.

“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-3. This report is incorporated by reference herein.

There have been no changes in PNM’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, PNM’s internal control over financial reporting.

TNMP

(a) Evaluation of disclosure controls and procedures.

As of the end of the period covered by this annual report, TNMP conducted an evaluation under the supervision and with the participation of its management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures are effective.

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(b) Management’s report on internal control over financial reporting.

“Management’s Annual Report on Internal Control Over Financial Reporting” appears on page B-4. This report is incorporated by reference herein.

There have been no changes in TNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Reference is hereby made to “Proposal 1: Elect Nine Directors” in PNMR’s Proxy Statement relating to the annual meeting of stockholders to be held on May 15, 2014 (the “2014 Proxy Statement”), to PART I, SUPPLEMENTAL ITEM – “EXECUTIVE OFFICERS OF THE COMPANY” in this Form 10-K, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Code of Ethics,” and “Board Committees and Their Functions”-“Audit and Ethics Committee” in the 2014 Proxy Statement. The Company intends to satisfy the disclosure requirements of Form 8-K relating to amendments to the Company’s code of ethics applicable to its senior executive and financial officers by posting such information on its Internet website. Information about the Company’s website is included under Part I, Item 1 - “Websites.”

PNMR’s common stock is listed on the New York Stock Exchange. As a result, PNMR’s Chief Executive Officer is required to make an annual certification to the New York Stock Exchange stating that she was not aware of any violations by PNMR of the New York Stock Exchange corporate governance listing standards. PNMR’s Chief Executive Officer made the most recent certification to the New York Stock Exchange on May 16, 2013.


ITEM 11.	EXECUTIVE COMPENSATION

Reference is hereby made to “Executive Compensation”, and all subheadings thereunder from “Compensation Discussion and Analysis” to “Change in Control, Termination, Retirement, or Impaction”, “Director Compensation,” and “Board Committees and Their Functions - Compensation and Human Resources Committee - Interlocks and Insider Participation” in the 2014 Proxy Statement.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Reference is hereby made to “Ownership of Our Common Stock - Five Percent Shareholders” and “ - Executive Officers and Directors” and “Equity Compensation Plan Information” in the 2014 Proxy Statement.


ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Reference is hereby made to “Information About Our Corporate Governance - Related Person Transaction Policy” and “ - Director Independence” in the 2014 Proxy Statement.


ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

Reference is hereby made to “Audit and Ethics Committee Report” and “Independent Auditor Fees” in the 2014 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2014 Proxy Statement for PNMR. All such fees are fees of PNMR. PNMR charges a management fee to PNM and TNMP that includes an allocation of independent auditor fees.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a) - 1.	See Index to Financial Statements under Part II, Item 8.

(a) - 2.	Financial Statement Schedules for the years 2013, 2012, and 2011 are omitted for the reason that they are not required or the information is otherwise supplied under Part II, Item 8.

(a) - 3-A.	Exhibits Filed:

Exhibit No		Description

10.1	PNMR	Amended and Restated Term Loan Agreement dated as of December 27, 2013 among PNMR, the lender parties (JPMorgan Chase Bank, N.A. and Union Bank, N.A.) and JPMorgan Chase Bank, N.A., as administrative agent

10.2	PNMR	Second Amendment to Credit Agreement dated October 31, 2013 among PNMR, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent

10.3*	PNM	Amendment No. 4 dated as of December 11, 2013 to Facility Lease dated as of December 16, 1985, as heretofore amended, between U.S. Bank National Association (ultimate successor to The First National Bank of Boston), as Owner Trustee, and PNM (Unit 1 transaction)

10.4**	PNMR	Second Amendment effective January 1, 2014 to the PNM Resources, Inc. Executive Savings Plan II

10.5**	PNMR	Second, Third and Fourth Amendments, each effective January 1, 2014, to the PNM Resources, Inc. After-Tax Retirement Plan

10.6**	PNMR	Acknowledgement Forms for restricted stock and performance share awards granted under the Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009, as amended

10.7**	PNMR	PNM Resources, Inc. Annual Executive Physical Exam Program Wraparound Plan Document effective as of January 1, 2014

12.1	PNMR	Ratio of Earnings to Fixed Charges

12.2	PNM	Ratio of Earnings to Fixed Charges

12.3	TNMP	Ratio of Earnings to Fixed Charges

21	PNMR	Certain subsidiaries of PNM Resources, Inc.

23.1	PNMR	Consent of KPMG LLP for PNM Resources, Inc.

23.2	PNM	Consent of KPMG LLP for Public Service Company of New Mexico

23.3	PNMR	Consent of Deloitte & Touche LLP for PNM Resources, Inc.

23.4	PNM	Consent of Deloitte & Touche LLP for Public Service Company of New Mexico

31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	PNM	Chief Financial Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.19	PNM	Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000 between the City of Tolleson, APS and Salt River Project Agricultural Improvement and Power District

101.INS	PNMR	XBRL Instance Document

D- 1

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101.SCH	PNMR	XBRL Taxonomy Extension Schema Document

101.CAL	PNMR	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	PNMR	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	PNMR	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	PNMR	XBRL Taxonomy Extension Presentation Linkbase Document



(a) -3- B.		Exhibits Incorporated By Reference:

The documents listed below are being filed (as shown above) or have been previously filed on behalf of PNM Resources, PNM or TNMP and are incorporated by reference to the filings set forth below pursuant to Exchange Act Rule 12b-32 and Regulation S-K section 10, paragraph (d).



Exhibit No.	Description of Exhibit	Filed as Exhibit:	Registrant(s) File No:
Plan of Acquisition
2.1	Stock Purchase Agreement dated as of September 23, 2011 among PNMR, TNP Enterprises, Inc. and Direct LP, Inc.	2.1 to PNMR’s Current Report on Form 8K filed September 23, 2011	1-32464 PNMR

Articles of Incorporation and By-laws
3.1	Articles of Incorporation of PNM Resources, as amended to date (Certificate of Amendment dated October 27, 2008 and Restated Articles of Incorporation dated August 3, 2006)	3.1 to the Company’s Current Report on Form 8-K filed November 21, 2008	1-32462 PNMR

3.2	Restated Articles of Incorporation of PNM, as amended through May 31, 2002	3.1.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002	1-6986 PNM

3.3	Articles of Incorporation of TNMP, as amended through July 7, 2005	3.1.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005	2-97230 TNMP

3.4	Bylaws of PNM Resources, Inc. with all amendments to and including December 8, 2009	3.1 to the Company’s Current Report on Form 8-K filed December 11, 2009	1-32462 PNMR

3.5	Bylaws of PNM with all amendments to and including May 31, 2002	3.1.2 to the Company’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002	1-6986 PNM

3.6	Bylaws of TNMP with all amendments to and including June 18, 2013	3.6 to TNMP’s Current Report on Form 8-K filed June 20, 2013	2-97230 TNMP

Indentures‡
PNMR
4.1	Indenture, dated as of March 15, 2005, between PNMR and JPMorgan Chase Bank, N.A., as Trustee	10.2 to PNMR’s Current Report on Form 8-K filed March 31, 2005	1-32462 PNMR

4.2	Supplemental Indenture No. 1, dated as of March 30, 2005, between the Company and JPMorgan Chase Bank, N.A. as Trustee, with Form of Senior Note included as Exhibit A thereto	10.3 to PNMR’s Current Report on Form 8-K filed March 31, 2005	333-32170 PNMR

4.3	Supplemental Indenture No. 2, dated as of May 16, 2008 between PNMR and The Bank of New York Trust Company, N.A. (successor to JPMorgan Chase Bank, N.A.), as trustee	4.3 to PNMR’s Current Report on Form 8-K filed May 21, 2008	1-32462 PNMR

4.4	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNMR, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 15, 2005 PNMR Indenture)	4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011	1-32462 PNMR

PNM

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4.5	Indenture (for Senior Notes), dated as of March 11, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.4 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998	1-6986 PNM

4.6	First Supplemental Indenture, dated as of March 11, 1998, supplemental to Indenture, dated as of March 11, 1998, Between PNM and The Chase Manhattan Bank, as Trustee	4.5 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998	1-6986 PNM

4.7	Second Supplemental Indenture, dated as of March 11, 1998, supplemental to Indenture, dated as of March 11, 1998, Between PNM and The Chase Manhattan Bank, as Trustee	4.6 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998	1-6986 PNM

4.8	Third Supplemental Indenture, dated as of October 1, 1999 to Indenture dated as of March 11, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.6.1 to PNM’s Annual Report on Form 10-K for the fiscal year ended December 31, 1999	1-6986 PNM

4.9	Fourth Supplemental Indenture, dated as of May 1, 2003 to Indenture dated as of March 11, 1998, between PNM and JPMorgan Chase Bank (formerly The Chase Manhattan Bank), as Trustee	4.6.2 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003	1-6986 PNM

4.10	Fifth Supplemental Indenture, dated as of May 1, 2003 to Indenture dated as of March 11, 1998, between PNM and JPMorgan Chase Bank, as Trustee	4.6.3 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003	1-6986 PNM

4.11	Sixth Supplemental Indenture, dated as of May 1, 2003 to Indenture dated as of March 11, 1998, between PNM and JPMorgan Chase Bank, as Trustee	4.6.4 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003	1-6986 PNM

4.12	Seventh Supplemental Indenture, dated as of June 1, 2007 to Indenture dated as of March 11, 1998, between PNM and The Bank of New York Trust Company, N.A. (successor to JPMorgan Chase Bank), as Trustee	4.23 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007	1-6986 PNM

4.13	Eighth Supplemental Indenture, dated as of June 1, 2010 to Indenture dated as of March 11, 1988, between PNM and The Bank of New York Mellon Trust Company (successor to JPMorgan Chase Bank), as Trustee	10.1 to PNM’s Current Report on Form 8-K/A filed July 29, 2010	1-6986 PNM

4.14	Ninth Supplemental Indenture, dated as of June 1, 2010 to Indenture dated as of March 11, 1988, between PNM and The Bank of New York Mellon Trust Company (successor to JPMorgan Chase Bank), as Trustee	10.2 to PNM’s Current Report on Form 8-K/A filed July 29, 2010	1-6986 PNM

4.15	Agreement of Resignation, Appointment and Acceptance effective as of May 1, 2011, among PNM, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 11, 1998 PNM Indenture)	4.2 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-6986 PNM

4.16	Tenth Supplemental Indenture, dated as of September 1, 2012, between PNM and Union Bank, N.A.(ultimate successor as trustee to The Chase Manhattan Bank), as Trustee	4.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012	1-6986 PNM

4.17	Indenture (for Senior Notes), dated as of August 1, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.1 to PNM’s Registration Statement No. 333-53367	333-53367 PNM

4.18	First Supplemental Indenture, dated August 1, 1998, supplemental to Indenture, dated as of August 1, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.3 to PNM’s Current Report on Form 8-K Dated August 7, 1998	1-6986 PNM

4.19	Second Supplemental Indenture, dated September 1, 2003, supplemental to Indenture, dated as of August 1, 1998, between PNM and JPMorgan Chase Bank (formerly, The Chase Manhattan Bank), as Trustee	4.7.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003	1-6986 PNM

4.20	Third Supplemental Indenture, dated as of May 13, 2008 between PNM and The Bank of New York Trust Company, N.A. as trustee	4.1 to PNM’s Current Report on Form 8-K filed May 15, 2008	1-6986 PNM

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4.21	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among PNM, The Bank of New York Mellon Trust Company and Union Bank, N.A. (for August 1, 1998 PNM Indenture)	4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011	1-6986 PNM

4.22	Fourth Supplemental Indenture, dated as of October 12, 2011, to the Indenture, dated as of August 1, 1998, between PNM and Union Bank, N.A. (ultimate successor as trustee to The Chase Manhattan Bank), as trustee	4.1 to PNM’s Current Report on Form 8-K filed October 12, 2011	1-6986 PNM

TNMP
4.23	The First Mortgage Indenture dated as of March 23, 2009, between TNMP and The Bank of New York Mellon Trust Company, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed March 27, 2009	2-97230 TNMP

4.24	The First Supplemental Indenture dated as of March 23, 2009, between TNMP and The Bank of New York Mellon Trust Company, N.A., as Trustee	4.2 to TNMP’s Current Report on Form 8-K filed March 27, 2009	2-97230 TNMP

4.25	The Second Supplemental Indenture dated as of March 25, 2009, between TNMP and The Bank of New York Mellon Trust Company, N.A., as Trustee	4.3 to TNMP’s Current Report on Form 8-K filed March 27, 2009	2-97230 TNMP

4.26	The Third Supplemental Indenture dated as of April 30, 2009 between TNMP and The Bank of New York Mellon Trust Company, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed May 6, 2009	2-97230 TNMP

4.27	First Amendment dated as of December 16, 2010 between TNMP and The Bank of New York Mellon Trust Company, N.A., as Trustee to The Third Supplemental Indenture dated as of April 30, 2009	4.1 to TNMP’s Current Report on Form 8-K filed December 17, 2010	2-97230 TNMP

4.28	Agreement of Resignation, Appointment and Acceptance, effective as of June 1, 2011, among TNMP, The Bank of New York Mellon Trust Company, N.A. and Union Bank, N.A. (for March 23, 2009 TNMP Indenture)	4.4 to TNMP’s Quarterly Report Form 10-Q for the quarter ended June 30, 2011	2-97230 TNMP

4.29	Fourth Supplemental Indenture dated as of September 30, 2011 between TNMP and Union Bank, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed October 6, 2011	2-97230 TNMP
4.30	Fifth Supplemental Indenture dated as of April 13, 2013 between TNMP and Union Bank, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed April 3, 2013	2-97230 TNMP

Material Contracts
10.8	Credit Agreement, dated as of October 31, 2011, among PNM Resources, Inc., the lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and Union Bank, N.A., as Syndication Agent	10.1 to the Company’s Current Report on Form 8-K filed October 31, 2011	1-32462 PNMR

10.9	First Amendment to Credit Agreement dated January 18, 2012 among PNMR, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent	10.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011	1-32462 PNMR
10.10	Second Amendment to Credit Agreement dated October 31, 2013 among PNMR, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent	10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.11	Amended and Restated Term Loan Agreement dated as of December 27, 2013 among PNMR, the lender parties (JPMorgan Chase Bank, N.A. and Union Bank, N.A.) and JPMorgan Chase Bank, N.A., as administrative agent	10.1 to PNMR’s to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.12	Credit Agreement, dated as of October 31, 2011, among PNM, the lenders party thereto, Wells Fargo Bank, National Association, as Administrative Agent and Union Bank, N.A., as Syndication Agent	10.2 to PNM’s Current Report on Form 8-K filed October 31, 2011	1-6986 PNM

10.13	First Amendment to Credit Agreement dated January 18, 2012 among PNM, the lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent	10.2 to PNM’s Annual Report on Form 10-K for the year ended December 31, 2011	1-6986 PNM

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10.14	Credit Agreement, dated as of January 8, 2014, among PNM, the lenders identified therein, and U.S. Bank National Association, as Administrative Agent and BOKF, N.A. d/b/a Bank of Albuquerque, as Syndication Agent	10.1 to PNM’s Current Report on Form 8-K filed January 8, 2014	1-6986 PNM
10.15	Term Loan Agreement dated as of April 22, 2013, among PNM, the lenders identified therein and Union Bank, N.A. as administrative agent	10.1 to PNM’s Current Report on Form 8-K filed April 23, 2013	1-6986 PNM
10.16	Second Amended and Restated Credit Agreement, dated as of September 18, 2013, among TNMP, the lenders identified therein and Key Bank National Association, as administrative agent	10.1 to TNMP’s Current Report on Form 8-K filed September 18, 2013	2-97230 TNMP
10.17	Term Loan Credit Agreement dated as of September 30, 2011, among TNMP, as borrower, the lenders identified therein, and JPMorgan Chase Bank, N.A., as administrative agent	10.1 to TNMP’s Current Report on Form 8-K filed October 6, 2011	2-97230 TNMP


10.18	Bond Purchase Agreement dated December 9, 2013 between TNMP and the purchasers named therein (for $80,000,000 4.03% First Mortgage Bonds, due 2024, Series 2014A)	10.1 to TNMP’s Current Report on Form 8-K filed December 10, 2013	2-97230 TNMP

10.19**	PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009 (“PEP”)	4.1 to PNM Resources’ Form S-8 Registration Statement filed May 20, 2009	333-159361 PNMR

10.20**	Amendment dated May 17, 2011 to PNMR’s Second Amended and Restated Omnibus Performance Equity Plan	10.1 to PNMR’s Current Report Form 8-K filed May 20, 2011	1-32462 PNMR

10.21**	Second Amendment executed March 28, 2012 to the PNMR Second Amended and Restated Omnibus Performance Equity Plan	10.6 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.22**	Third Amendment (approved by PNMR shareholders on May 15, 2012) to the PNMR Second Amended and Restated Omnibus Performance Equity Plan	10.1 to PNMR’s Current Report on Form 8-K filed May 17, 2012	1-32462 PNMR

10.23**	PNM Resources, Inc. 2013 Officer Annual Incentive Plan dated March 29, 2013	10.1 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013	1-32462 PNMR

10.24**	PNM Resources, Inc. 2012 Officer Annual Incentive Plan dated March 28, 2012	10.1 to PNMR’s Quarterly Report on form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR
10.25**	PNM Resources, Inc. 2013 Long-Term Incentive Plan dated March 29, 2012	10.2 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013	1-32464 PNMR

10.26**	PNM Resources, Inc. 2012 Long-Term Incentive Plan dated March 28, 2012	10.2 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.27**	PNM Resources, Inc. 2011 Long-Term Incentive Transition Plan, dated April 29, 2011	10.5 to the Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-32462 PNMR

10.28**	PNM Resources, Inc. 2011 Long-Term Incentive Plan Terms and Conditions, dated March 22, 2011	10.6 to the Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-32462 PNMR

10.29**	Form of Stock Option Award Agreement for non-qualified stock options granted under PEP in 2010	10.3 to PNMR’s Current Report on Form 8-K filed May 26, 2009	1-32462 PNMR

10.30**	Form of the award agreement for non- qualified stock options granted under the PEP in 2007-2009	10.2 to the Company’s Current Report on Form 8-K filed February 16, 2007	1-32462 PNMR
10.31**	Special Performance-Based Retention Award Agreement between PNMR and Patricia K. Collawn dated March 29, 2012	10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

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10.32**	2013 Director Compensation Summary (2014 annual retainer is the same as the 2013 annual retainer)	10.1 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2012	1-32462 PNMR

10.33**	Acknowledgement Forms for restricted stock and stock option awards granted to directors under the PEP	10.3 to the Company’s Current Report on Form 8-K filed March 1, 2011	1-32462 PNMR
10.34**	Acknowledgement Forms for restricted stock and performance share awards granted under the Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009, as amended	10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.35**	PNM Resources, Inc. Executive Spending Account Plan (amended and restated effective January 1, 2011)	10.4 to the Company’s Current Report on Form 8-K filed March 1, 2011	333-32170 PNMR

10.36**	PNM Resources, Inc. Executive Savings Plan II (amended and restated effective January 1, 2009)	4.1 to PNMR’s Registration Statement on Form S-8 (333-156243) filed December 17, 2008	333-156243 PNMR

10.37**	First Amendment executed March 28, 2012 to the PNMR Executive Savings Plan II	10.4 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR
10.38**	Second Amendment effective January 1, 2014 to the PNMR Executive Savings Plan II	10.4 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.39**	PNM Resources, Inc. After-Tax Retirement Plan effective January 1, 2009	10.5 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008	1-32462 PNMR

10.40**	First Amendment executed March 28, 2012 to the PNMR After-Tax Retirement Plan	10.5 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR
10.41**	Second, Third and Fourth Amendments, each effective January 1, 2014, to the PNM Resources, Inc. After-Tax Retirement Plan	10.5 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.42**	Summary of Executive Time Off Policy Effective January 1, 2006	10.31 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2005	1-32462 PNMR

10.43**	Amendment to Corporate Policy Absence from Work Policy 125 executed December 16, 2011	10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011	1-32462 PNMR

10.44**	PNM Resources, Inc. Non-Union Severance Pay Plan effective August 1, 2007 (amended and restated)	10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007	1-32462 PNMR

10.45**	First Amendment to the PNM Resources Non-Union Severance Pay Plan executed November 20, 2008	10.3 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008	1-32462 PNMR

10.46**	Second Amendment (executed March 27, 2012) to PNMR Non-Union Severance Pay Plan	10.8 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.47**	PNM Resources, Inc. Officer Retention Plan executed March 28, 2012 as amended and restated effective as of January 1, 2012	10.7 to the Company’s Quarterly Report in Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.48**	PNM Resources, Inc. Director Retainer Plan, dated December 31, 2001	4.3 to PNM Resources, Inc. Post-Effective Amendment No. 1 to Form S-8 Registration Statement filed December 31, 2001	333-03289 PNMR

10.49**	First Amendment dated February 17, 2003 to PNM Resources, Inc. Director Retainer Plan	10.40.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003	333-32170 PNMR

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10.50**	PNM Resources Officer Life Insurance Plan dated April 28, 2004	10.24.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004	333-32170 PNMR

10.51**	First Amendment to PNM Resources Officer Life Insurance Plan dated December 16, 2004	10.27 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004.	333-32170 PNMR

10.52**	Second Amendment to PNM Resources Officer Life Insurance Plan executed April 15, 2007	10.5 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007	1-32462 PNMR

10.53**	Third Amendment to the PNMR Officer Life Insurance Plan effective January 1, 2009	10.10 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008	1-32462 PNMR

10.54**	Fourth Amendment to the PNMR Officer Life Insurance Plan effective January 1, 2009	10.15 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008	1-32462 PNMR

10.55**	Fifth Amendment to the PNM Resources, Inc. Officer Life Insurance Plan executed December 16, 2011	10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011	1-32462 PNMR

10.56**	Executive Long Term Disability Plan effective January 1, 2003	10.88 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002	333-32170 PNMR

10.57	Supplemental Indenture of Lease dated as of July 19, 1966 between PNM and other participants in the Four Corners Project and the Navajo Indian Tribal Council	4-D to PNM’s Registration Statement No. 2-26116	2-26116 PNM

10.58	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease dated April 25, 1985 between the Navajo Tribe of Indians and Arizona Public Service Company, El Paso Electric Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, and Tucson Electric Power Company (refiled)	10.1.1 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1995	1-6986 PNM

10.59	Amendment and Supplement No. 2 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011	10.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-6986 PNM

10.60	Amendment and Supplement No. 3 to Supplemental and Additional Indenture of Lease with the Navajo Nation dated March 7, 2011	10.2 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011	1-6986 PNM

10.61	Water Supply Agreement between the Jicarilla Apache Tribe and Public Service Company of New Mexico, dated July 20, 2000	10.5 to PNM’s Quarterly Report of Form 10-Q for the quarter ended September 30, 2001	1-6986 PNM

10.62	Arizona Nuclear Power Project Participation Agreement among PNM and Arizona Public Service Company, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and El Paso Electric Company, dated August 23, 1973	5-T to PNM’s Registration Statement No. 2-50338	2-50338 PNM

10.63	Amendments No. 1 through No. 6 to Arizona Nuclear Power Project Participation Agreement	10.8.1 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1991	1-6986 PNM

10.64	Amendment No. 7 effective April 1, 1982, to the Arizona Nuclear Power Project Participation Agreement (refiled)	10.8.2 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1991	1-6986 PNM

10.65	Amendment No. 8 effective September 12, 1983, to the Arizona Nuclear Power Project Participation Agreement (refiled)	10.58 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1993	1-6986 PNM

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10.66	Amendment No. 9 to Arizona Nuclear Power Project Participation Agreement dated as of June 12, 1984 (refiled)	10.8.4 to PNM’s Annual Report of the Registrant on Form 10-K for fiscal year ended December 31, 1994	1-6986 PNM

10.67	Amendment No. 10 dated as of November 21, 1985 and Amendment No. 11 dated as of June 13, 1986 and effective January 10, 1987 to Arizona Nuclear Power Project Participation Agreement (refiled)	10.8.5 to PNM’s Annual Report of the Registrant on Form 10-K for fiscal year ended December 31, 1995	1-6986 PNM

10.68	Amendment No. 12 to Arizona Nuclear Power Project Participation Agreement dated June 14, 1988, and effective August 5, 1988	19.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1990	1-6986 PNM

10.69	Amendment No. 13 to the Arizona Nuclear Power Project Participation Agreement dated April 4, 1990, and effective June 15, 1991	10.8.10 to PNM’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990	1-6986 PNM

10.70	Amendment No. 14 to the Arizona Nuclear Power Project Participation Agreement effective June 20, 2000	10.8.9 to PNM’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000	1-6986 PNM

10.71	Amendment No. 15 to the Arizona Nuclear Power Project Participation Agreement dated November 29, 2010 and effective January 13, 2011	10.1 to PNM’s Current Report on Form 8-K filed March 1, 2011	1-6986 PNM

10.72	Underground Coal Sales Agreement, dated August 31, 2001 among San Juan Coal Company, PNM and Tucson Electric Power Company	10.85 to PNM’s Quarterly Report on Form 10-Q for the quarter ending September 30, 2001 (Confidential treatment was requested for portions of this exhibit, and such portions were omitted from this exhibit filed and were filed separately with the Securities and Exchange Commission)	1-6986 PNM

10.73	Amendment One to Underground Coal Sales Agreement dated December 15, 2003 among San Juan Coal Company, PNM and Tucson Electric Coal Company	10.9.1 to PNM’s Amended Report on Form 10-K for fiscal year ended December 31, 2003 (Confidential treatment was requested for portions of this exhibit, and such portions were omitted from this exhibit filed and were filed separately with the Securities and Exchange Commission)	1-6986 PNM

10.74	Amendment Two to Underground Coal Sales Agreement effective September 15, 2004 among San Juan Coal Company, PNM and Tucson Electric Coal Company	10.9.2 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004	1-6986 PNM

10.75	Amendment Three to Underground Coal Sales Agreement executed April 29, 2005 among San Juan Coal Company, PNM and Tucson Electric Coal Company (Confidential treatment was requested for portions of this exhibit, and such portions were omitted from this exhibit filed and were filed separately with the Securities and Exchange Commission)	10.86.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005	1-6986 PNM

10.76	Amendment Four to Underground Coal Sales Agreement effective March 7, 2007 among San Juan Coal Company, PNM and Tucson Electric Coal Company	10.89 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007	1-6986 PNM

10.77	Amendment Five to Underground Coal Sales Agreement executed December 21, 2007 among San Juan Coal Company, PNM and Tucson Electric Power Company (Confidential treatment was requested for portions of this exhibit, and such portions were omitted from this exhibit filed and were filed separately with the Securities and Exchange Commission)	10.95 to PNM’s Annual Report on Form 10-K for the year ended December 31, 2007	1-6986 PNM

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10.78	Participation Agreement among PNM, Tucson Electric Power Company and certain financial institutions relating to the San Juan Coal Trust dated as of December 31, 1981 (refiled)	10.14 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1992	1-6986 PNM

10.79	Participation Agreement dated as of June 30, 1983 among Security Trust Company, as Trustee, PNM, Tucson Electric Power Company and certain financial institutions relating to the San Juan Coal Trust (refiled)	10.61 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1993	1-6986 PNM

10.80	Amended and Restated San Juan Project Participation Agreement dated as of March 23, 2006, among Public Service Company of New Mexico, Tucson Electric Power Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power System and Tri-State Generation and Transmission Association, Inc.	10.119 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 30, 2006	1-6986 PNM

10.81*	Facility Lease dated as of December 16, 1985 between The First National Bank of Boston, as Owner Trustee, and PNM (Unit 1 transaction) together with Amendments No. 1, 2 and 3 thereto (refiled)	10.18 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1995	1-6986 PNM

10.82*	Amendment No. 4 dated as of December 11, 2013 to Facility Lease dated as of December 16, 1985 as heretofore amended, between U.S. Bank National Association (ultimate successor to The First National Bank of Boston), as Owner Trustee, and PNM (Unit 1 transaction)	10.3 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 2013	1-6986 PNM


10.83	Facility Lease dated as of July 31, 1986, between the First National Bank of Boston, as Owner Trustee, and PNM (Unit 1 transaction) together with Amendments No. 1, 2 and 3 thereto (refiled)	10.19 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

10.84*	Facility Lease dated as of August 12, 1986, between The First National Bank of Boston, as Owner Trustee, and PNM (Unit 2 transaction) together with Amendments No. 1 and 2 thereto (refiled)	10.20 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

10.85	Amendment No. 2 dated as of April 10, 1987 to Facility Lease dated as of August 12, 1986 (Unit 2 transaction), as amended, between The First National Bank of Boston, not in its individual capacity, but solely as Owner Trustee under a Trust Agreement, dated as of August 12, 1986, with MFS Leasing Corp., Lessor and Public Service Company of New Mexico, Lessee (refiled)	10.20.2 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1998	1-6986 PNM

10.86	Facility Lease dated as of December 15, 1986, between The First National Bank of Boston, as Owner Trustee, and PNM (Unit 1 Transaction) together with Amendment No. 1 thereto (refiled)	10.21 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

10.87	Facility Lease dated as of December 15, 1986, between The First National Bank of Boston, as Owner Trustee, and PNM (Unit 2 Transaction) together with Amendment No. 1 thereto (refiled)	10.22 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

10.88	Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station dated March 15, 1996, between Public Service Company of New Mexico and Mellon Bank, N.A.	10.68 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1996	1-6986 PNM

10.89	Amendment Number One to the Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station dated January 27, 1997, between Public Service Company of New Mexico and Mellon Bank, N.A.	10.68.1 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1997	1-6986 PNM

10.90	Amendment Number Two to the Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station between Public Service Company of New Mexico and Mellon Bank, N.A.	10.68.2 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 2003	1-6986 PNM

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10.91	PVNGS Capital Trust-Variable Rate Trust Notes-PVNGS Note Agreement dated as of July 31, 1998	10.76 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1998	1-6986 PNM
10.92	Stipulation in the matter of PNM’s transition plan Utility Case No. 3137, dated October 10, 2002 as amended by Amendment to Stipulated Agreement dated October 18, 2002	10.86 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002	1-6986 PNM

10.93	Stipulation dated February 28, 2005 in NMPRC Case No. 04-00315-UT regarding the application of PNM Resources and TNMP for approval of the TNP acquisition	10.134 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005	1-32462 PNMR/ TNMP

10.94	Consent Decree entered into by PNM on March 9, 2005 relating to the citizen suit under the Clean Air Act and the excess emissions report matter for SJGS	10.135 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005	1-6986 PNM


Subsidiaries
21	Certain subsidiaries of PNM Resources	21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

Additional Exhibits
99.1*	Participation Agreement dated as of December 16, 1985, among the Owner Participant named therein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 16, 1985 with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 16, 1985 with the Owner Trustee), and PNM (Unit 1 transaction), including Appendix A definitions, together with Amendment No. 1 dated July 15, 1986 and Amendment No. 2 dated November 18, 1986 (refiled)	99.2 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1995	1-6986 PNM

99.2*	Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 16, 1985, between the First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indentures Nos. 1 and 2 (Unit 1 transaction) (refiled)	99.3 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1996	1-6986 PNM

99.3*	1996 Supplemental Indenture dated as of September 27, 1996 to Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 16, 1985 between State Street Bank and Trust Company, as Owner Trustee, and The Chase Manhattan Bank, as Indenture Trustee (Unit 1 transaction)	99.21 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1996	1-6986 PNM
99.4*	Assignment, Assumption and Further Agreement dated as of December 16, 1985, between Public Service Company of New Mexico and The First National Bank of Boston, as Owner Trustee (Unit 1 transaction)	28(c) to PNM’s Current Report on Form 8-K dated December 31, 1985	1-6986 PNM

99.5	Participation Agreement dated as of July 31, 1986, among the Owner Participant named herein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of July 31, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of July 31, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions together with Amendment No. 1 thereto (refiled)	99.5 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

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99.6	Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of July 31, 1986, between The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indenture No. 1 thereto (refiled)	99.6 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

99.7	Assignment, Assumption, and Further Agreement dated as of July 31, 1986, between Public Service Company of New Mexico and The First National Bank of Boston, as Owner Trustee (refiled)	99.7 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

99.8*	Participation Agreement dated as of August 12, 1986, among the Owner Participant named therein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of August 12, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of August 12, 1986, with the Owner Trustee), and PNM, including Appendix A definitions (Unit 2 transaction) (refiled)	99.8 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.9*	Amendment No. 1 dated as of November 18, 1986, to Participation Agreement dated as of August 12, 1986 (Unit 2 transaction) (refiled)	99.8.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.10*	Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of August 12, 1986, between the First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indenture No. 1 thereto (refiled) (Unit 2 transaction)	99.9 to PNM’s Annual Report of the Registrant on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM
99.11	1997 Supplemental Indenture, dated as of December 23, 1997, to Trust Indenture, Mortgage, Security Agreement and Assignment of Rents, dated as of August 12, 1986, between State Street Bank and Trust, as Owner Trustee, and The Chase Manhattan Bank, as Indenture Trustee	99.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006	1-6986 PNM

99.12*	Assignment, Assumption, and Further Agreement dated as of August 12, 1986, between Public Service Company of New Mexico and The First National Bank of Boston, as Owner Trustee (Unit 2 transaction) (refiled)	99.10 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM


99.13	Participation Agreement dated as of December 15, 1986, among the Owner Participant named therein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 15, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 15, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions (Unit 1 Transaction) (refiled)	99.11 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.14	Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 15, 1986, between The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee (Unit 1 Transaction) (refiled)	99.12 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.15	Assignment, Assumption and Further Agreement dated as of December 15, 1986, between Public Service Company of New Mexico and The First National Bank of Boston, as Owner Trustee (Unit 1 Transaction) (refiled)	99.13 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

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99.16	Participation Agreement dated as of December 15, 1986, among the Owner Participant named therein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 15, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 15, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions (Unit 2 Transaction) (refiled)	99.14 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.17	Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 31, 1986, between the First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee (Unit 2 Transaction) (refiled)	99.15 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

99.18	Assignment, Assumption, and Further Agreement dated as of December 15, 1986, between Public Service Company of New Mexico and The First National Bank of Boston, as Owner Trustee (Unit 2 Transaction) (refiled)	99.16 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997	1-6986 PNM

99.19	Agreement for the Sale and Purchase of Wastewater Effluent, dated November 13, 2000, among the City of Tolleson, Arizona Public Service Company and Salt River Project Agricultural Improvement and Power District	99.19 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 2013	1-6986 PNM

99.20	Municipal Effluent Purchase and Sale Agreement dated April 23, 2010 between Cities of Phoenix, Mesa, Tempe, Scottsdale and Glendale, Arizona municipal corporations; and APS, SRP, acting on behalf of themselves and EPE, SCE, PNM, SCPPA, and Los Angeles Department of Water and Power	10.6 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010	1-6986 PNM

* One or more additional documents, substantially identical in all material respects to this exhibit, have been entered into, relating to one or more additional sale and leaseback transactions. Although such additional documents may differ in other respects (such as dollar amounts and percentages), there are no material details in which such additional documents differ from this exhibit.

** Designates each management contract or compensatory plan or arrangement required to be identified pursuant to paragraph 3 of Item 15(a) of Form 10-K.

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



			PNM RESOURCES, INC.
			(Registrant)

Date:	February 28, 2014	By	/s/ P. K. Collawn
			P. K. Collawn
			Chairman, President, and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date

/s/ P. K. Collawn	Principal Executive Officer and Director	February 28, 2014
P. K. Collawn
Chairman, President, and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer	February 28, 2014
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ T. G. Sategna	Principal Accounting Officer	February 28, 2014
T. G. Sategna
Vice President and
Corporate Controller

/s/ A. E. Archuleta	Director	February 28, 2014
A. E. Archuleta

/s/ J. A. Dobson	Director	February 28, 2014
J. A. Dobson

/s/ A. J. Fohrer	Director	February 28, 2014
A. J. Fohrer

/s/ R. R. Nordhaus	Director	February 28, 2014
R. R. Nordhaus

/s/ B. S. Reitz	Director	February 28, 2014
B. S. Reitz

/s/ D. K. Schwanz	Director	February 28, 2014
D. K. Schwanz

/s/ B. W. Wilkinson	Director	February 28, 2014
B. W. Wilkinson

/s/ J. B. Woodard	Director	February 28, 2014
J. B. Woodard

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SIGNATURES



			PUBLIC SERVICE COMPANY OF NEW MEXICO
			(Registrant)

Date:	February 28, 2014	By	/s/ P. K. Collawn
			P. K. Collawn
			President and Chief Executive Officer



Signature	Capacity	Date

/s/ P. K. Collawn	Principal Executive Officer and Chairman of the Board	February 28, 2014
P. K. Collawn
President and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 28, 2014
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ T. G. Sategna	Principal Accounting Officer	February 28, 2014
T. G. Sategna
Vice President and
Corporate Controller

/s/ R. N. Darnell	Director	February 28, 2014
R. N. Darnell

/s/ R. E. Talbot	Director	February 28, 2014
R. E. Talbot

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SIGNATURES



			TEXAS-NEW MEXICO POWER COMPANY
			(Registrant)

Date:	February 28, 2014	By	/s/ P. K. Collawn
			P. K. Collawn
			Chief Executive Officer



Signature	Capacity	Date

/s/ P. K. Collawn	Principal Executive Officer and Chairman of the Board	February 28, 2014
P. K. Collawn
Chief Executive Officer

/s/ T. G. Sategna	Principal Financial Officer and Principal Accounting Officer	February 28, 2014
T. G. Sategna
Vice President and
Controller

/s/ R. N. Darnell	Director	February 28, 2014
R. N. Darnell

/s/ C. N. Eldred	Director	February 28, 2014
C. N. Eldred

/s/ R. E. Talbot	Director	February 28, 2014
R. E. Talbot

/s/ J. N. Walker	Director	February 28, 2014
J. N. Walker

E-3