PNM RESOURCES INC - Annual Report: 2014 (Form 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, 2014



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. ü

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 20, 2015, shares of common stock outstanding were:



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

On June 30, 2014, 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 $29.33 per share reported by The Wall Street Journal, was $2,336,240,792. 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 12, 2015.

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
CORPORATE AND OTHER			A- 5
SOURCES OF POWER			A- 5
FUEL AND WATER SUPPLY			A- 8
ENVIRONMENTAL MATTERS			A- 10
COMPETITION			A- 10
EMPLOYEES			A- 10
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS			A- 11
SECURITIES ACT DISCLAIMER			A- 12
ITEM 1A. RISK FACTORS			A- 12
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- 58
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- 1
SIGNATURES			E-1

iii

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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, the operator and a co-owner of PVNGS and Four Corners
ARO		Asset Retirement Obligation
ASU		Accounting Standards Update
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
BDT		Balanced Draft Technology
BHP		BHP Billiton, Ltd, the parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
CAA		Clean Air Act
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
EGU		Electric Generating Unit
EIB		New Mexico Environmental Improvement Board
EIP		Eastern Interconnection Project
EIS		Environmental Impact Study
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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ISFSI		Independent Spent Fuel Storage Installation
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.
NEPA		National Environmental Policy Act
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
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 2013 Term Loan Agreement		PNM’s $75.0 Million Unsecured Term Loan
PNM 2014 Term Loan Agreement		PNM’s $175.0 Million Unsecured Term Loan
PNM Multi-draw Term Loan		PNM’s $125.0 Million Unsecured Multi-draw Term Loan Facility
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
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR Development		PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR

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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
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
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
Rio Bravo		Rio Bravo Generating Station, formerly know as Delta
RMC		Risk Management Committee
ROE		Return on Equity
RPS		Renewable Energy Portfolio Standard
RSIP		Revised State Implementation Plan
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 with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP. PNMR is focused on achieving the following strategic goals:


•	Earning authorized returns on its regulated businesses


•	Continuing to improve credit ratings


•	Providing a top quartile total return to investors

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. PNM filed a general rate case with the NMPRC in December 2014. 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 are so indicated. 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 corporate Internet addresses are:


•	PNMR: www.pnmresources.com


•	PNM: www.pnm.com


•	TNMP: www.tnmp.com

In addition to the corporate websites, PNM established a website, www.PowerforProgress.com, dedicated to showing how it balances delivering reliable power at affordable prices and protecting the environment. This website is designed to be a resource for the facts about PNM's operations and support efforts, including plans for building a sustainable energy future for New Mexico. 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 http://www.pnmresources.com/corporate-governance.aspx 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. PNM 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 3.4% of the utility’s revenues for the year ended December 31, 2014. PNM was incorporated in the State of New Mexico in 1917.

NMPRC Regulated Retail Rate Proceedings

Customer rates for retail electric service are set by the NMPRC. PNM filed a general rate case with the NMPRC in December 2014. PNM’s application proposes a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future year test and a ROE of 10.5%. PNM requested this increase to account for infrastructure investments made since its last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect declining sales growth in PNM’s service territory. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation, including an access charge to customers installing photovoltaic systems after December 31, 2015. See Note 17 for additional information concerning this filing.

PNM’s previous general rate case filing was made in June 2010. In August 2011, the NMPRC issued a final order that included, among other things, a $72.1 million increase in annual non-fuel revenues for New Mexico retail customers. As permitted by that 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. The rider will terminate upon a final order in PNM’s next general rate case unless that order authorizes a continuation of the rider. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operation, exceeded 10.5%, it would refund to customers during May through December of the following year the amount over 10.5%. PNM’s earned return on jurisdictional equity did not exceed 10.5% in 2013 or 2014.

FERC Regulated Wholesale Operations

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 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

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above. The proposed increase of $1.3 million, as updated, went into effect, subject to refund, on August 2, 2013. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. The updated rate request went into effect on May 30, 2014, subject to refund. The parties have engaged in settlement negotiations and PNM anticipates that a settlement will be filed with FERC in the near future. There is no required time frame for FERC to act upon a settlement. PNM is unable to predict the outcome of this proceeding.

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. The average billing demands for PNM’s firm-requirements wholesale customers aggregate approximately 62 MW, excluding the contract with Gallup that expired in 2014. No firm-requirements customer of PNM accounted for more than 2.5% of PNM’s revenues for the year ended December 31, 2014.

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 and an extension of the contract for 10 years through December 31, 2035. FERC approved the settlement in April 2013. PNM provided both energy and power services to Gallup, which was its second largest firm-requirements wholesale customer, under an electric service agreement that expired on June 30, 2014. PNM’s recently filed general rate case discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. See Results of Operations in MD&A and Note 17.

PNM also provides electricity at wholesale to the City of Aztec, New Mexico under a contract that expires on June 30, 2016. In 2014, PNM entered into a contract with the Jicarilla Apache Nation to provide electricity at wholesale through May 8, 2016, which date can be extended through May 8, 2019, if approved by the NMPRC.

PNM’s current authorization under FERC regulation requires that revenue requirements for sales of electricity at wholesale are to be based on PNM’s costs of providing such service. In August 2014, PNM filed an application with FERC to allow PNM to enter into arrangements to sell electricity at wholesale prices within PNM’s balancing authority area using rates that are based on market conditions. There is no statutory requirement for FERC to act upon this application within a specified period of time. PNM cannot predict if FERC will grant the request to sell at market-based rates.

Operational Information

Weather-normalized retail electric KWh sales decreased by 1.7% in 2014 and 1.8% in 2013. The system peak demands for retail and firm-requirements customers decreased in 2014 and increased in 2013. The system peak demands were as follows:

System Peak Demands



	2014	2013	2012
	(Megawatts)
Summer	1,878	2,008	1,948
Winter	1,471	1,576	1,523

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 48.0%, 10.5%, and 9.6% of PNM’s 2014 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 and other utilities 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 complaints in federal and state courts challenging the validity of the ordinance. If the challenge to the ordinance is unsuccessful, PNM believes

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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.

PNM owns or leases 3,197 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 and any earnings or losses are realized by shareholders. PNM has contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates for substantially all of these sales. 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 beginning in 2018 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 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. Ninety percent of the margins from these optimization sales 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.

As discussed above, in December 2014, PNM filed a request for a general rate increase with the NMPRC, which is 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 increases in weather-normalized retail KWh sales of 3.2% in 2014 and 2.6% in 2013. As of December 31, 2014, 94 active REPs receive transmission and distribution services from TNMP. The acquirer of First Choice, including the former First Choice operations, accounted for 15% of TNMP’s revenues in 2014. Two other unaffiliated customers of TNMP accounted for operating revenues of 15% and 11% in 2014. No other customer accounted for more than 10% of revenues.

Regulatory Activities

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 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, $2.8 million on September 17, 2013, $2.9 million on March13, 2014, and $4.2 million on September 8, 2014. On January16, 2015, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.4 million annually. The application is pending before the PUCT.

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.

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.

SOURCES OF POWER

PNM

Generation Capacity

As of December 31, 2014, the total net generation capacity of facilities owned or leased by PNM was 2,397 MW. PNM also obtains power under a long-term PPA for the power produced by New Mexico Wind, which has a capacity of 204 MW, and the output of the Lightning Dock Geothermal facility, which currently has a capacity of 4 MW. On January 1, 2015, PNM began obtaining the power output of Red Mesa Wind, which has a capacity of 102 MW.

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PNM’s capacity in electric generating facilities, which are owned, leased, or under PPAs, in commercial service as of January 1, 2015 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	Rio Bravo, formerly known as Delta	Albuquerque, New Mexico	138
Gas	Valencia	Belen, New Mexico	158
Nuclear	PVNGS	Wintersburg, Arizona	402
Solar	PNM-owned solar	Eleven sites in New Mexico	67
Wind	New Mexico Wind	House, New Mexico	204
Wind	Red Mesa Wind	Seboyeta, New Mexico	102
Geothermal	Lightning Dock Geothermal	Lordsburg, New Mexico	4
			2,707

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 proposal to shut down 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 had 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. PNM cannot predict whether the 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, Rio Bravo, and Lordsburg and one-third of Luna. The remaining interests in Luna are owned equally by Tucson and Samchully Power & Utilities 1, LLC. Prior to July 17, 2014 when PNM closed on the purchase of Rio Bravo, PNM was entitled to its energy and capacity under a PPA. 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, Rio Bravo, and Valencia are used primarily for peaking power and transmission support. See Note 9 for additional information about Rio Bravo 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

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PVNGS are recovered through retail rates approved by the NMPRC. See Note 7 for additional information concerning the PVNGS leases, including agreements with the lessors of the PVNGS Unit 1 leases and one of the PVNGS Unit 2 leases for PNM to renew those leases and agreements with the lessors of the other three Unit 2 leases for PNM to exercise its fair market purchase options to purchase the assets underlying those leases. 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 number of 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, PVNGS expects to spend approximately $40 million for capital enhancements to the plant over the next two years in addition to the approximately $80 million that has already been spent on capital enhancements as of December 31, 2014. 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 2014, PNM completed construction of an additional 23 MW of PNM-owned solar PV facilities at three additional sites. PNM’s 2015 renewable energy procurement includes the construction by December 31, 2015 of an additional 40 MW of PNM-owned solar PV facilities.

Plant Operating Statistics

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



Plant	Operator	2014	2013	2012
SJGS	PNM	76.5%	77.6%	81.7%
Four Corners	APS	68.1%	72.9%	83.5%
PVNGS	APS	91.8%	89.4%	90.6%

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 have varying percentage interests in different generating units within the project. The primary operating or participation agreements for the joint projects expire in July 2016 for Four Corners, July 2022 for SJGS, December 2046 for Luna, and November 2047 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 for SJGS expires on December 31, 2017. 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 leased. See Nuclear Plant above and Note 7 regarding PNM’s actions related to options under these leases. 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 renewable 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 has 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 capacity 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 Rio Bravo and Valencia, is as follows:



	Year Ended December 31,
	2014		2013		2012
Purchased under long-term PPAs
MWh	492,906		490,539		546,321
Cost per MWh	$	27.82	$	27.25	$	27.25
Other purchased power
Total MWh	1,023,744		1,061,514		948,911
Cost per MWh	$	40.30	$	35.64	$	27.30

TNMP

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

FUEL AND WATER SUPPLY

PNM

The percentages of PNM’s generation of electricity (on the basis of KWh), including Valencia and Rio Bravo, 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
2014	56.7	%	$	3.00	32.0	%	$	0.83	10.3	%	$	4.26
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

In 2014, 2013, and 2012, 1.0%, 0.6%, and 0.5% of PNM’s generation was from utility owned solar, which has no fuel cost. The generation mix for 2015 is expected to be 56.7% coal, 30.7% nuclear, 11.0% gas and oil, and 1.6% 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.

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Coal

The coal supply contract that provides fuel for SJGS expires on December 31, 2017. Coal supply has not been arranged for periods after the existing contract expires although negotiations are ongoing. 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. Coal costs are anticipated to increase approximately 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. 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 has contracted for firm gas transmission capacity to minimize the potential for disruptions due to extreme weather events. 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 and conversion services through 2018 and 45% of its requirements in 2019-2020. The participants have also contracted for 100% of PVNGS’s enrichment services through 2020. All of PVNGS’s fuel assembly fabrication services are contracted through 2022.

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) has pursued legal actions. See Note 16 for information concerning these actions.

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.

On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and its issuance is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in NRC’s regulations. On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights. Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository.

All spent nuclear fuel from PVNGS is being stored on-site. PVNGS has sufficient capacity at its on-site 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 NEPA. 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 $72.1 million in 2015 and $78.6 million in 2016 through 2019, 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


•	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, 2014:



	PNMR	PNM	TNMP
Corporate ⁽¹⁾	433	—	—
PNM	1,093	1,093	—
TNMP	355	—	355
Total	1,881	1,093	355

(1)Represents employees of PNMR Services Company.

As of December 31, 2014, PNM had 593 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. Negotiations for a new agreement with the IBEW began in January 2015. While the Company is optimistic that a timely agreement will be reached, PNM cannot, at this time, predict the outcome of the negotiations. PNM is currently working on contingency planning for certain scenarios that may occur as a result of negotiations. The wages and benefits for all PNM employees who are members of the IBEW are typically included in the rates charged to electric customers, subject to approval of the NMPRC.

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.

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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 began. 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. As of December 31, 2014, TNMP had 195 employees represented by IBEW Local 66. In January 2015, a decertification election was held for those employees covered by the original petition. The employees voted to retain union representation. The parties have reached a tentative agreement on a collective bargaining agreement. A vote of the union members on whether to ratify the agreement is in process.

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 treatment of SJGS Units 2 and 3 at the date of their proposed early retirement


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


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


•	State and federal regulation or legislation relating to environmental matters, including the RSIP 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 ability of the Company to successfully forecast and manage its operating and capital expenditures


•	Physical and operational risks related to climate change and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG


•	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, fuel quality, unplanned outages, extreme weather conditions, terrorism, cybersecurity breaches, and other catastrophic events


•	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


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


•	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 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 risk that FERC rulemakings may negatively impact the operation of PNM’s transmission system


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


•	Employee workforce factors, including issues arising out of collective bargaining agreements and labor negotiations with union employees


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

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


•	Changes in applicable accounting principles or policies

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.”

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 in 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 2015-2019 to be $2,207.3 million. See Note 14. PNM and TNMP anticipate 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 treatment 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 costs are increasing, there are factors placing downward pressures on the demand for power, thereby reducing load growth and customer usage. 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 2014 and 2013, PNM experienced decreases in weather-normalized retail sales of 1.7% and 1.8%. 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. After several years of being relatively flat, New Mexico’s employment showed modest growth in 2014 and

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only modest growth is anticipated in the near future. Also, low population growth will result in low growth in the number of customers. In Texas, the drop in oil prices has impacted the economy although it remains relatively strong.

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 to recover 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 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 rate requests based on a future test year cannot be successfully supported, 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 currently provides fuel for SJGS expires on December 31, 2017. Negotiations for a new coal supply contract, which are in process, 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. Coal costs are anticipated to increase approximately 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM currently recovers the cost of fuel for its generation facilities through its FPPAC. Although PNM believes costs under new coal supply arrangements 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. The Company 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, 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 has proposed its GHG NSPS rules for new sources, as well as modified and existing EGU’s. 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 mine use of CCBs being classified as hazardous waste by EPA, could significantly increase the costs of the disposal of CCBs and the costs of mine reclamation. See Note 16.

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.

BART determinations have been made 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 will be required for the installation of control technology at both generating stations and operating costs would increase.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. Timely regulatory recovery of

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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.

PNM has a case pending before the NMPRC requesting regulatory approvals necessary for PNM to comply with the regional haze requirements of the CAA pertaining to SJGS. Failure to obtain the approval of the NMPRC in this matter could impact PNM’s ability to efficiently operate SJGS, which could have a negative impact on PNM’s business, financial condition, results of operations, and cash flows.

SJGS, which currently comprises 28.9% of PNM’s owned and leased generation capacity and is its largest generation resource, is subject to the CAA. In February 2013, PNM, NMED, and EPA agreed to pursue a revised plan regarding SJGS. In October 2014, EPA published its approval of NMED’s RSIP, which requires the installation of SNCRs on SJGS Units 1 and 4 combined with the shutdown of SJGS Units 2 and 3. PNM believes significant progress is being made towards implementation of the RSIP. In order to retire San Juan Units 2 and 3, final binding agreements must be reached among the SJGS owners on a revised ownership structure of SJGS, as well as addressing continuing liabilities for reclamation, decommissioning, environmental, and other matters. The participants are attempting to agree on these items and are engaged in ongoing mediated negotiations, but binding agreements have not been reached.

The coal supply contract that currently provides fuel for SJGS expires on December 31, 2017. Coal supply has not been arranged for periods after the existing contract expires. In order for the participants to approve the restructuring of ownership in SJGS, they have indicated they need to obtain greater certainty regarding fuel supply for SJGS for the period after December 31, 2017. The remaining participants in SJGS are in the process of negotiating agreements concerning future fuel supply for SJGS. The date for negotiation of a transaction has been extended until May 1, 2015. However, it is possible that the participants may not be able to negotiate a new contract for coal supply or that a new contract for coal could result in higher prices, either of which could impact the restructuring process.

PNM has a filing pending before the NMPRC that requests the regulatory approvals required to effectuate the RSIP. A public hearing on PNM’s requests was held in January 2015 and PNM believes it justified that its requests provide the best alternative for New Mexico retail ratepayers in order to comply with the requirements of the CAA. Final approvals from the NMPRC are necessary to implement the RSIP. PNM believes that for the NMPRC to approve PNM’s requests, the SJGS participants will have to reach binding agreements regarding restructuring ownership in SJGS. In the NMPRC proceeding, PNM has committed to reaching binding agreements on restructuring by May 1, 2015. For the participants to reach such agreements, it is likely that the remaining participants in SJGS will need to have completed negotiations regarding the coal supply for SJGS for periods after December 31, 2017.

Additional information regarding the RSIP, the restructuring negotiations, the request for NMPRC approvals, and coal supply is discussed in Note 16.

PNM can provide no assurance that these requirements will be accomplished or that the NMPRC will approve PNM’s requests. If NMPRC approval is not obtained, PNM may not be able to implement the RSIP. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA. In such circumstances, PNM could be forced to temporarily or permanently cease operation of some or all of the SJGS units. If a shutdown was required, PNM would then have to acquire 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. To the extent any additional costs incurred are not allowed to be recovered from customers through the ratemaking process, PNM’s financial condition, results of operation, and cash flows could be negatively impacted.

It is also possible that failure to reach a satisfactory agreement to restructure SJGS ownership, requirements to comply with the final BART determinations, 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 economic viability of the plant or the ability of individual participants to continue participation in SJGS.

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,

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FERC, NRC, EPA, and NERC. Oversight by these agencies covers 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.

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 PNM’s and TNMP’s facilities through self-generation, renewable or other energy resources, technological change, or other measures, 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 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 proposals are periodically advanced in various localities to municipalize, or otherwise take over PNM’s facilities, which PNM believes would require state legislative action to implement, or to establish new municipal utilities in areas currently served by PNM. For example, officials in the City of Santa Fe, New Mexico have indicated a desire to reduce the carbon footprint of the city, which could include exploring renewable resources dedicated to serve the city, a partnership with existing utilities, or the feasibility of a city-owned municipal electric utility. PNM is monitoring that situation. If any such initiative is successful, the result could be a material reduction in the usage of the facilities, a reduction in rate base, and reduced earnings.

Should any of the above factors result in 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

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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 could 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, quality, 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 two of 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.

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 16.8% 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

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•	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. However, PVNGS expects to spend approximately $40 million for capital enhancements to the plant over the next two years in addition to the approximately $80 million that has already been spent on capital enhancements as of December 31, 2014. 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. Although PNM has no reason to anticipate a serious nuclear incident at PVNGS, if an incident did occur, it could materially and adversely affect PNM’s results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.

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 forces, competitive forces, or adverse regulatory actions 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 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.

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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 Company.

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


•	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

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Disruption in the credit and capital markets may impact the Company’s 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 2015-2019 to be $2,207.3 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, or 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 or cybersecurity 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.

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

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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, 2014, PNM owned, jointly owned, or leased, 3,197 circuit miles of electric transmission lines (including the EIP), 5,851 miles of distribution overhead lines, 5,715 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, 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 Valencia, including the potential purchase of 50% of Valencia.

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, 2014, TNMP owned 966 circuit miles of overhead electric transmission lines, 7,085 pole miles of overhead distribution lines, 1,152 circuit miles of underground distribution lines, and 109 substations. Substantially all of TNMP’s property is pledged to secure its first mortgage bonds. See Note 6.

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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 – 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


•	Santa Fe Generating Station


•	Coal Combustion Byproducts Waste Disposal – Sierra Club Consent Decree


•	Continuous Highwall Mining Royalty Rate


•	SJCC Arbitration


•	Four Corners Severance Tax Assessment


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication


•	Rights-of-Way Matter


•	Complaint Against Southwestern Public Service Company


•	Navajo Nations Allottee Matters

Note 17


•	PNM – 2014 Electric Rate Case


•	PNM – Renewable Portfolio Standard


•	PNM – Renewable Energy Rider


•	PNM – Energy Efficiency and Load Management


•	PNM – FPPAC Continuation Application


•	PNM – Integrated Resource Plan


•	PNM – San Juan Generating Station Units 2 and 3 Retirement


•	PNM – Transmission Rate Case


•	PNM – Formula Transmission Rate Case


•	TNMP – Advanced Meter System Deployment


•	TNMP – Remand of ERCOT Transmission Rates for 1999 and 2000


•	TNMP – Energy Efficiency


•	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 20, 2015 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	56	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	61	Executive Vice President and Chief Financial Officer	July 2007

P. V. Apodaca	63	Senior Vice President, General Counsel and Secretary	January 2010
		University Counsel, University of New Mexico	May 2006

R. E. Talbot	54	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	57	Senior Vice President, Public Policy	January 2012
		Vice President, Regulatory Affairs	April 2008

T. G. Sategna ⁽¹⁾	61	Vice President and Corporate Controller	October 2003

⁽¹⁾On December 9, 2014, T. G. Sategna notified the Company that he intends to retire as the Company’s principal accounting officer effective as of March 31, 2015. Mr. Sategna has agreed to continue employment with PNMR Services Company through December 31, 2015 to (among other things) assist the Company and his successor in the transition process. On December 11, 2014, the Company appointed J. D. Tarry as its Vice President and Controller (and principal accounting officer), effective as of April 1, 2015. His appointment was approved by the Board on February 26, 2015. Mr. Tarry, 44, joined the Company in 1996 and has served as Vice President, Customer Service and Chief Information Officer since May 2012. From January 1, 2010 through May 2012, he served as Executive Director of Financial Planning and Business Analysis.

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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 2014 and 2013, by quarters, are as follows:



Quarter Ended	Range of Sales Prices				Dividends Declared Per Share
	High		Low		Dividends Declared Per Share
2014
March 31	$	27.15	$	23.53	$	0.185
June 30	29.33		26.28		0.185
September 30	29.80		24.27		0.185
December 31	31.39		25.18		0.200
Fiscal Year	31.39		23.53		0.755
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

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 $0.165 per share in July 2013 and $0.185 per share in July 2014, 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 $0.165 per share in September 2013 and $0.185 per share in September 2014, which are reflected as being in the third quarter above. On February 26, 2015, the Board declared a quarterly dividend of $0.20 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 20, 2015, there were 10,283 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 2014 and 2013. PNMR and TNMP do 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. 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
	2014			2013			2012			2011			2010
	(In thousands except per share amounts and ratios)
Total Operating Revenues	$	1,435,853		$	1,387,923		$	1,342,403		$	1,700,619		$	1,673,517
Net Earnings (Loss)	$	130,909		$	115,556		$	120,125		$	190,934		$	(31,124	)
Net Earnings (Loss) Attributable to PNMR	$	116,254		$	100,507		$	105,547		$	176,359		$	(45,215	)
Net Earnings (Loss) Attributable to PNMR per Common Share
Basic	$	1.46		$	1.26		$	1.32		$	1.98		$	(0.49	)
Diluted	$	1.45		$	1.25		$	1.31		$	1.96		$	(0.49	)
Cash Flow Data
Net cash flows from operating activities	$	414,876		$	386,587		$	281,349		$	292,240		$	287,352
Net cash flows from investing activities	$	(485,329	)	$	(331,446	)	$	(285,895	)	$	19,778		$	(275,906	)
Net cash flows from financing activities	$	96,194		$	(61,593	)	$	(1,560	)	$	(312,331	)	$	(10,683	)
Total Assets	$	5,829,325		$	5,500,210		$	5,372,583		$	5,204,613		$	5,225,083
Long-Term Debt, including current installments	$	1,975,090		$	1,745,420		$	1,672,290		$	1,674,013		$	1,565,847
Common Stock Data
Market price per common share at year end	$	29.63		$	24.12		$	20.51		$	18.23		$	13.02
Book value per common share at year end	$	21.61		$	21.01		$	20.19		$	19.76		$	17.90
Tangible book value per share at year end	$	18.12		$	17.52		$	16.70		$	16.27		$	14.10
Average number of common shares outstanding – diluted	80,279			80,431			80,417			89,757			91,557
Dividends declared per common share	$	0.755		$	0.680		$	0.580		$	0.500		$	0.500
Capitalization
PNMR common stockholders’ equity	46.4		%	48.8		%	48.9		%	48.3		%	47.8		%
Convertible preferred stock	—			—			—			—			3.1
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.3			0.3			0.3			0.4
Long-term debt	53.3			50.9			50.8			51.4			48.7
	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 477,800 shares of PNMR Series A convertible preferred stock as if it was converted into common stock through September 23, 2011, when it was retired by PNMR.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2014		2013		2012		2011		2010
	(In thousands)
PNM Revenues
Residential	$	411,412	$	411,579	$	409,005	$	390,380	$	355,905
Commercial	428,085		415,621		413,332		386,383		355,699
Industrial	73,002		74,552		78,637		73,742		65,358
Public authority	25,278		25,745		25,495		23,970		21,302
Economy service	39,123		32,909		25,354		21,141		20,218
Transmission	38,284		38,228		39,373		43,637		38,667
Firm-requirements wholesale	38,313		42,370		39,390		34,127		31,870
Other sales for resale	82,508		67,538		47,321		69,318		121,729
Mark-to-market activity	5,996		293		892		4,214		(3,599		)
Other	5,913		7,477		13,465		10,377		9,979
Total PNM Revenues	$	1,147,914	$	1,116,312	$	1,092,264	$	1,057,289	$	1,017,128
TNMP Revenues
Residential	$	114,826	$	111,373	$	103,255	$	100,290	$	83,645
Commercial	99,701		95,098		88,258		84,896		77,474
Industrial	15,049		13,084		13,405		13,065		12,342
Other	58,362		52,056		45,222		39,607		39,127
Total TNMP Revenues	$	287,938	$	271,611	$	250,140	$	237,858	$	212,588
First Choice Revenues
Residential	$	—	$	—	$	—	$	260,161	$	305,834
Commercial	—		—		—		166,498		159,785
Trading gains (losses)	—		—		—		—		(4		)
Other	—		—		—		12,791		17,588
Total First Choice Revenues	$	—	$	—	$	—	$	439,450	$	483,203

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 and $39.1 million received from First Choice in 2011 and 2010.

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
	2014	2013	2012	2011	2010
PNM MWh Sales
Residential	3,169,071	3,304,350	3,323,544	3,402,842	3,361,472
Commercial	3,874,292	3,954,774	4,022,184	4,043,796	4,015,999
Industrial	984,130	1,041,160	1,136,011	1,132,110	1,073,475
Public authority	251,187	266,368	279,169	282,062	263,424
Economy service	758,629	719,342	635,305	428,757	376,458
Firm-requirements wholesale	527,597	654,135	651,972	650,356	677,508
Other sales for resale	2,271,480	2,061,851	1,652,225	2,076,869	2,203,787
Total PNM MWh Sales	11,836,386	12,001,980	11,700,410	12,016,792	11,972,123
TNMP MWh Sales
Residential	2,802,768	2,796,661	2,714,511	2,862,337	2,699,601
Commercial	2,564,751	2,451,299	2,353,135	2,360,998	2,260,505
Industrial	2,727,064	2,598,442	2,727,126	2,578,877	2,241,452
Other	102,118	104,516	103,856	108,664	103,341
Total TNMP MWh Sales	8,196,701	7,950,918	7,898,628	7,910,876	7,304,899
First Choice MWh Sales
Residential	—	—	—	2,006,437	2,267,836
Commercial	—	—	—	1,538,203	1,363,746
Total First Choice MWh Sales	—	—	—	3,544,640	3,631,582


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

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
	2014		2013		2012		2011		2010
PNM Customers
Residential	455,907		453,218		450,507		448,979		447,789
Commercial	55,853		55,447		54,953		54,468		54,005
Industrial	249		251		250		251		259
Economy service	1		1		1		1		1
Other sales for resale	39		34		36		28		46
Other	911		928		952		983		1,003
Total PNM Customers	512,960		509,879		506,699		504,710		503,103
TNMP Consumers
Residential	199,963		196,799		193,550		192,356		190,809
Commercial	38,033		37,460		36,819		37,208		37,356
Industrial	70		70		70		73		72
Other	2,044		2,070		2,037		2,092		2,099
Total TNMP Consumers	240,110		236,399		232,476		231,729		230,336
First Choice Customers
Residential	—		—		—		176,577		172,506
Commercial	—		—		—		44,485		41,695
Total First Choice Customers	—		—		—		221,062		214,201
PNMR Generation Statistics
Net Capability – MW, including PPAs	2,707		2,572		2,537		2,547		2,631
Coincidental Peak Demand – MW	1,878		2,008		1,948		1,938		1,973
Average Fuel Cost per MMBTU	$	2.415	$	2.237	$	2.308	$	2.267	$	2.064
BTU per KWh of Net Generation	10,422		10,308		10,289		10,441		10,237


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

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 753,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving the following strategic goals:


•	Earning authorized returns on its regulated businesses


•	Continuing to improve credit ratings


•	Providing a top-quartile total return to investors

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


•	Achieving industry-leading safety performance


•	Maintaining strong plant performance and system reliability


•	Delivering a superior customer experience


•	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. PNM filed a general rate case with the NMPRC in December 2014. PNM’s application proposes a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future year test and a ROE of 10.5%. PNM requested this increase to account for infrastructure investments made since its last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect declining sales growth in PNM’s service territory. The infrastructure investments account for approximately 92% of the rate increase. PNM’s success with energy efficiency programs is a contributing factor to the decline in sales growth and accounts for the balance of the rate increase after offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation, including an access charge to customers installing photovoltaic systems after December 31, 2015.

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 completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest generation services customer, which improved PNM’s returns for providing those services. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services, ended on June 29, 2014. PNM’s recently filed general rate case discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. 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. The parties have engaged in settlement negotiations and

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PNM anticipates that a settlement will be filed with FERC in near future. There is no required time frame for FERC to act upon a settlement. Additional information about rate filings is provided in Note 17.

Fair and timely rate treatment from regulators is crucial to PNM and TNMP earning their allowed returns, which is critical for PNMR’s ability to achieve its strategic goals. 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.

Currently, PNM's 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is currently sold into the wholesale market and any earnings or losses are realized by shareholders. 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. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Continuing to Improve Credit Ratings

PNM is committed to improving its credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. On January 30, 2014, Moody’s raised the credit ratings for PNMR, PNM and TNMP by one notch, while maintaining the positive outlook. On April 30, 2014, S&P changed the outlook for PNMR, PNM, and TNMP to positive from stable. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade.

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% to 13%. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, 12% in December 2013, and 8% in December 2014. 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, communities, and stockholders. 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 aware of the important 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 reliable electric service.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through the end of 2014, TNMP had completed installation of more than 184,000 smart meters, which is approximately 80% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

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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. TNMP is currently installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the 2012 to 2014 period, PNM and TNMP together invested $1,062.8 million in utility plant, including substations, power plants, nuclear fuel, 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. The facility is expected to go into service in late 2015. On July 17, 2014, PNM completed the purchase of Rio Bravo, formerly known as Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000.

Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. PNM’s 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 that also demonstrate progress in addressing proposed new federal regulations for CO₂ emissions from existing power plants


•	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 25% 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. As discussed below, PNM has requested approval to shut down SJGS Units 2 and 3, which would reduce water consumption at that plant by about 50%. In addition to the above areas of focus, the Company is 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 expects to continue to do so in the future.

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 capacity 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 included 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 beginning in 2015, and the purchase of RECs in 2014 and 2015 to meet the RPS. PNM’s 2015 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements include the construction of 40 MW of PNM-owned solar PV facilities in 2015, which are contemplated in PNM’s application to retire SJGS Units 2 and 3 discussed below.

In addition to PNM’s utility-owned PV solar facilities, PNM 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 has a PPA for the output from a 204 MW wind facility and purchases power from a customer-owned distributed solar generation program that had an installed capacity of 39 MW at the end of 2014. 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.

PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM believes its currently planned resources will enable it to comply with the NMPRC’s diversity requirements. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico’s escalating RPS requirements.

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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 have required 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 RSIP from the State of New Mexico. The RSIP has been approved by the EIB and EPA.

The RSIP would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS at a lower cost to PNM customers. It has the added advantage of reducing other emissions beyond NOx, including SO₂, particulate matter, CO₂, and mercury, as well as reducing water usage.

In December 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. On October 1, 2014, PNM filed a stipulation with the NMPRC that, if approved, would settle this case. The stipulation is supported to by the staff of the NMPRC, the NMAG, and NMIEC. The stipulation is opposed by other intervenors.

Under the terms of the stipulation, PNM would:


•	Retire SJGS Units 2 and 3 at December 31, 2017 and recover over 20 years 50% of their undepreciated net book value at that date, after transferring $26 million to SJGS Unit 4, and earn a regulated return on those costs


•	Acquire an additional 132 MW of SJGS Unit 4


•	Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018 at a value of $221.1 million ($1,650 per KW)


•	File for recovery of up to $90.6 million of costs for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4


•	Not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance

There would be no initial cost for PNM to acquire the additional 132 MW of SJGS Unit 4 although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership.

A public hearing in the NMPRC case was held in January 2015. PNM expects a decision from the NMPRC in the second quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates that upon approval it would incur a regulatory disallowance, which would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. PNM currently estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million. See Note 16.

The December 20, 2013 filing also identified 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. The additional solar capacity is included in PNM’s 2015 renewable procurement strategy (Note 17). Specific approval for the additional gas facility and the treatment of associated costs will be addressed 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 non-binding resolution, approved by the SJGS Coordination Committee on June 26, 2014, identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The non-binding resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. The non-binding resolution and term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty

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in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 16, for additional information. In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the above resolution. The Fuel and Capital Funding Agreement was approved by FERC on November 13, 2014. On January 7, 2015, one of the participants in SJGS Unit 4 notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs unsubscribed in that unit. PNM has indicated that it will not acquire any of the unsubscribed MWs. However, a scenario is being evaluated in which PNMR Development would acquire the 65 MWs. The participant’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS and mediated discussions regarding remaining issues have continued. Other definitive agreements among the participants are being negotiated. PNM cannot predict if final agreements will be executed.

A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained.

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. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. In March 2014, June 2014, and January 2015, PNM requested that the owners of Unit 4 approve expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve the requests. On March 10, 2014 and July 14, 2014, PNM issued “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

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, including recently proposed rules regarding GHG under Section 111(d) of the CAA. 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 42%, SO₂ by 67%, particulate matter by 71%, and mercury by 95%.

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 2014, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 70 GWh. This is equivalent to the annual consumption of approximately 9,700 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 2014 resulted in energy savings totaling an estimated 17 GWh. This is equivalent to the annual consumption of approximately 1,600 homes in TNMP’s service territory.

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. Beginning 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, including billing and payment options, and strategic customer and stakeholder engagement. As part of this effort, in February 2014, PNM launched an updated website that provides an increase in self-service options for customers, as well as a mobile platform.

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.

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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 gas-fired La Luz 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 avoided.

PNM expanded its integrated communication efforts with the launch of a new customer information website focused on PNM’s major regulatory filings, including the stipulated settlement agreement regarding BART at SJGS and PNM’s general rate case. The website, www.PowerforProgress.com, provides the details of current requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. The website is designed to be a resource for the facts about PNM's operations and community support efforts, including plans for building a sustainable energy future for New Mexico.

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 2014, PNM hosted 31 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 3,153 families in 2014. In 2014, PNM committed funding of $0.4 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 2014, the foundation awarded $0.2 million to support 54 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 $1.6 million of support. In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities. Power Up Grants in the aggregate amount of $0.5 million were awarded to 24 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

In Texas, community outreach is centered first on local relationships, specifically with community leaders, nonprofit organizations and key customers in areas served by TNMP. Community liaisons serve in each of TNMP's three geographic business areas, reaching out and ensuring productive lines of communication between TNMP and its customer base.

TNMP maintains long-standing relationships with several key nonprofit organizations, including agencies that support children and families in crisis, food banks, environmental organizations, and educational nonprofits, through employee volunteerism and corporate support. TNMP also actively participates in safety fairs and demonstrations in addition to supporting local chambers of commerce in efforts to build their local economies.

TNMP's energy efficiency program provides unique offers to multiple customer groups, including residential, commercial, government, education, and nonprofit customers. These programs not only enable peak load and consumption reductions, particularly important when extreme weather affects Texas' electric system, but they also demonstrate TNMP's commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In 2014 and 2013, PNM experienced decreases in weather-normalized retail load of 1.7% and 1.8%. New Mexico’s economy still lags the nation in post-recession recovery. TNMP experienced increases in weather-normalized retail load of 3.2% in 2014 and 2.6% in 2013. In recent years, New Mexico and Texas have fared better than the national average in unemployment although the unemployment rate in New Mexico exceeded the national average in the latter part of 2014. Employment growth is a stronger predictor of load. Texas’ employment growth rates are well above the national rate, while New Mexico’s employment showed modest growth in 2014 after several years of being 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
	2014		2013		2012		2014/2013			2013/2012
	(In millions, except per share amounts)

Net earnings	$	116.3	$	100.5	$	105.5	$	15.8		$	(5.0	)
Average diluted common and common equivalent shares	80.3		80.4		80.4		(0.1		)	—
Net earnings per diluted share	$	1.45	$	1.25	$	1.31	$	0.20		$	(0.06	)

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



	Change
	2014/2013			2013/2012
	(In millions)
PNM	$	(0.8	)	$	(3.4	)
TNMP	8.7			2.4
Corporate and Other	7.8			(4.0		)
Net change	$	15.8		$	(5.0	)

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


•	Higher prices for sales of power from PVNGS Unit 3


•	Net unrealized gains and losses on mark-to-market economic hedges for sales and fuel costs not recoverable under PNM’s FPPAC


•	Increased income tax expense due to impairments of state tax credits and state net operating loss carryforwards, as well as a tax rate change in New Mexico Note 11


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

Liquidity and Capital Resources

PNMR has a $300.0 million revolving credit facility and PNM has a $400.0 million revolving credit facility, both of which expire in October 2019 and can be extended for one year upon approval by the lenders. Both facilities provide capacities for short-term borrowing and letters of credit. 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 $768.2 million at February 20, 2015. 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 $2,528.5 million for 2015-2019. 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, environmental upgrades at Four Corners, the purchase of the leased portion of the EIP, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases. 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 2015-2019 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
	2014			2013			2012			2014/2013			2013/2012
	(In millions)
Electric operating revenues	$	1,147.9		$	1,116.3		$	1,092.3		$	31.6		$	24.0
Cost of energy	403.6			374.7			353.6			28.9			21.1
Margin	744.3			741.6			738.6			2.7			3.0
Operating expenses	422.1			428.6			435.4			(6.5		)	(6.8		)
Depreciation and amortization	109.5			103.8			97.3			5.7			6.5
Operating income	212.7			209.2			205.9			3.5			3.3
Other income (deductions)	20.8			21.5			26.5			(0.7		)	(5.0		)
Interest charges	(79.4		)	(79.2		)	(76.1		)	(0.2		)	(3.1		)
Segment earnings before income taxes	154.1			151.5			156.3			2.6			(4.8		)
Income (taxes)	(52.6		)	(48.8		)	(50.7		)	(3.8		)	1.9
Valencia non-controlling interest	(14.1		)	(14.5		)	(14.1		)	0.4			(0.4		)
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings	$	86.8		$	87.6		$	91.0		$	(0.8	)	$	(3.4	)

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



	2014/2013 Change									2013/2012 Change
	Total Revenues			Cost of Energy			Margin			Total Revenues			Cost of Energy			Margin
	(In millions)
Customer usage/load	$	(10.9	)	$	—		$	(10.9	)	$	(8.6	)	$	—		$	(8.6	)
Weather	(11.0		)	—			(11.0		)	(3.3		)	—			(3.3		)
Transmission	2.0			0.9			1.1			(1.6		)	1.0			(2.6		)
FPPAC	23.0			23.0			—			6.8			6.8			—
Economy energy service	6.2			6.0			0.2			7.6			7.3			0.3
Wholesale contracts	(1.2		)	(1.6		)	0.4			2.9			—			2.9
Rio Bravo purchase	—			(3.3		)	3.3			—			—			—
Unregulated margins	5.3			(1.8		)	7.1			2.8			(2.7		)	5.5
Energy efficiency rider	3.8			—			3.8			(2.1		)	—			(2.1		)
Renewable energy rider	10.2			3.7			6.5			14.7			6.3			8.4
Net unrealized economic hedges	5.7			1.1			4.6			(0.6		)	(0.9		)	0.3
Other	(1.5		)	0.9			(2.4		)	5.4			3.3			2.2
Net change	$	31.6		$	28.9		$	2.7		$	24.0		$	21.1		$	3.0

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



	Year Ended December 31,						Change
	2014		2013		2012		2014/2013			2013/2012
	(In millions, except customers)
Residential	$	411.4	$	411.6	$	409.0	$	(0.2	)	$	2.6
Commercial	428.1		415.6		413.3		12.5			2.3
Industrial	73.0		74.6		78.6		(1.6		)	(4.0		)
Public authority	25.3		25.7		25.5		(0.4		)	0.2
Economy energy service	39.1		32.9		25.4		6.2			7.5
Transmission	38.3		38.2		39.4		0.1			(1.2		)
Firm-requirements wholesale	38.3		42.4		39.4		(4.1		)	3.0
Other sales for resale	82.5		67.5		47.4		15.0			20.1
Mark-to-market activity	6.0		0.3		0.9		5.7			(0.6		)
Other	5.9		7.5		13.4		(1.6		)	(5.9		)
	$	1,147.9	$	1,116.3	$	1,092.3	$	31.6		$	24.0
Average retail customers (thousands)	511.2		508.2		505.6		3.0			2.6

The following table shows PNM GWh sales by customer class:



	Year Ended December 31,			Change
	2014	2013	2012	2014/2013		2013/2012
	(Gigawatt hours)
Residential	3,169.1	3,304.3	3,323.5	(135.2	)	(19.2	)
Commercial	3,874.3	3,954.8	4,022.2	(80.5	)	(67.4	)
Industrial	984.1	1,041.2	1,136.0	(57.1	)	(94.8	)
Public authority	251.2	266.4	279.2	(15.2	)	(12.8	)
Economy energy service	758.6	719.3	635.3	39.3		84.0
Firm-requirements wholesale	527.6	654.1	652.0	(126.5	)	2.1
Other sales for resale	2,271.5	2,061.9	1,652.2	209.6		409.7
	11,836.4	12,002.0	11,700.4	(165.6	)	301.6

In 2014, retail sales were lower compared to 2013 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 retail KWh sales were lower in 2014 by 1.7%, which decreased revenues and margins $10.9 million compared to 2013. Milder weather in New Mexico decreased revenues and margin $11.0 million in 2014 as cooling degree days were 7.4% lower and heating degree days were 12.7% lower in 2014 compared to 2013. In spite of the economic pressures, PNM experienced growth in average retail customers of 0.6% in 2014 compared to 2013. For 2013, 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. 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 compared to 2012.

Transmission rate increases in August 2013 and May 2014 increased revenues and margin $1.3 million in 2014 compared to 2013. See Note 17. In 2013, lower transmission revenues as a result of expiration of contracts combined with higher third-party transmission expenses incurred to deliver power to retail customers reduced margins by $2.6 million.

As discussed in Note 17, the NMPRC approved the continuation of PNM’s FPPAC and authorized PNM to recover the remaining under-collected balance in its FPPAC balancing account over 18 months effective July 1, 2014. As a result PNM’s revenues increased in 2014 compared to 2013. These revenues were offset in cost of energy with no impact on margin.

PNM provides “economy energy services” to a major customer. Under this contract, PNM purchases energy on the customer’s behalf and delivers the energy to the customer’s location through PNM’s transmission system. PNM charges the

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customer for the cost of the energy as a direct pass through to the customer with no impact to PNM’s margin. Although KWh sales to this customer increased in both 2014 and 2013 compared to the previous year, there is only a minor impact in margin resulting from providing ancillary services.

Unregulated revenues and margins are primarily associated with PVNGS Unit 3. In 2014, higher market prices combined with higher available generation increased revenues by $5.3 million. In addition, gas imbalance settlements lowered cost of energy $2.1 million in 2014 compared to 2013. In 2013, higher market power prices on sales offset by lower available generation increased revenue and margin $2.8 million. In addition, PNM incurred cost of energy for gas imbalance settlements of $2.0 million in 2012 that did not recur in 2013.

PNM’s contract with Gallup, its second largest wholesale generation customer, expired on June 29, 2014. In 2014, decreases in revenues for the Gallup contract of $5.6 million were partially offset by increases in off-system sales of $3.3 million for power that would have otherwise been used to serve Gallup and lower fuel expense of $1.0 million. In addition, in May 2014, PNM entered into a new wholesale contract with the Jicarilla Apache Nation, which increased revenues and margin $1.0 million. PNM’s recently filed general rate case includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. See Note 17. PNM implemented new rates for NEC, its largest wholesale firm-requirements customer, in April 2012 and for Gallup in July 2013. These increases improved revenues and margins $2.9 million in 2013.

PNM closed on the acquisition of Rio Bravo, formerly known as Delta, on July 17, 2014. Prior to acquiring Rio Bravo, PNM had a 20 year PPA covering all of the output of the facility, which PNM accounted for as an operating lease and recorded fixed and variable costs in cost of energy. As a result of the Rio Bravo acquisition, cost of energy decreased and margin increased $3.3 million for 2014 compared to 2013. The increase in margin is partially offset by increases in operating and depreciation expenses.

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 authorized calculations. See Note 17. 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 2014, revenues and margins from the energy efficiency rider were higher by $3.8 million compared to 2013, due to an increase in the recovery rate for program costs and higher authorized incentives. In 2013, revenues and margins from the energy efficiency rider were lower by $2.1 million compared to 2012 due to lower KWh sales and a decrease in the recovery rate.

In August 2012, PNM implemented its renewable energy rider, which recovers renewable energy procurement costs to meet the RPS, including PNM-owned solar PV facilities. In January 2014, PNM increased the rate charged under the rider to include additional PNM-owned solar PV facilities completed in 2013. See Note 17. For 2014, this rider increased revenues by $10.2 million compared to 2013. These revenues include a return on investment increase of $1.9 million for 2014 compared to 2013. Cost of energy, reflecting purchase of RECs and purchase of geothermal power, increased $3.7 million for 2014 compared to 2013. Revenues under this rider increased by $14.7 million for 2013 compared to 2012. Cost of energy, reflecting the purchase cost of RECs, increased by an additional $6.3 million in 2013. Revenue increased due to the earned return component on investment of $1.8 million in 2013 compared to $1.2 million for 2012. The remaining revenues from this rider recover renewable energy operating, depreciation, and interest expenses.

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 $6.5 million in 2014 compared to unrealized gains of $1.9 million for 2013 increased margin by $4.6 million, primarily due to PVNGS Unit 3 hedge gains of $5.7 million offset by losses on purchase power contracts of $1.1 million. 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.

Changes in revenue, cost of energy, and margin shown as “other” in the table above include the following items. In 2014, PNM recorded a $1.7 million increase in cost of energy and decrease in margin related to the resolution of issues covered by the arbitration with SJCC discussed in Note 16. As part of the approval of the continuation of PNM’s FPPAC, PNM retains 10% of the revenue from off-system sales that would otherwise be passed through the FPPAC, effective as of July 1, 2013. PNM recorded revenue of $1.7 million for its 10% share of off-system sales from the effective date through December 31, 2014. Lower cost of nuclear fuel handling due to discontinuance of the DOE one-mill fees decreased cost of energy and increased margins by $1.0 million in 2014 compared to 2013. Other also includes the impacts of off-system purchases and sales that are not passed through PNM’s FPPAC. Other sales for resale revenues and KWh volumes increased in 2013 compared to 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. Lower cost of energy associated with coal mine decommissioning of $1.9 million increased margins in 2013 compared to 2012.

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In 2014, operating expenses decreased $6.5 million compared to 2013. Increases in plant maintenance costs at Four Corners, Palo Verde, and PNM’s natural gas plants of $2.4 million, $1.5 million, and $2.8 million were offset by lower maintenance costs at SJGS of $0.6 million. Higher energy efficiency rider program costs and higher renewable rider costs of $3.2 million and $0.4 million, which are offset in revenues, increased operating expenses. Higher property taxes of $2.4 million due to increased plant in service and higher assessed values, as well as higher bad debt expense of $0.4 million further increased operating expenses in 2014 compared to 2013. In 2014, PNM undertook process improvement initiatives designed to decrease future operating expenses. In connection with those initiatives, PNM incurred $1.9 million of costs, primarily related to severances, in 2014. These increases in costs were offset by lower labor and employee benefit costs of $2.4 million and $0.6 million in 2014 compared to 2013. Lower property and casualty claims reduced operating expenses by $1.0 million for 2014 compared to 2013. Capitalization of administrative and general expenses increased by $2.7 million due to higher capital spending also reduced operating expenses in 2014 compared to 2013, as did the $3.3 million allocation to contributions to the PNM Resources Foundation and additional financial support to the PNM Good Neighbor Fund in 2013, which did not occur in 2014. PNM concluded that certain costs that were being deferred as regulatory assets were no longer probable of recovery through the ratemaking process and recorded regulatory disallowances of $1.1 million in 2014 and $12.2 million in 2013, resulting in a decrease in operating expenses of $11.1 million in 2014. The 2013 disallowance includes $10.5 million of the under-collected balance of the FPPAC pursuant to a settlement in the FPPAC continuation matter discussed in Note 17.

In 2013, operating expenses decreased $6.8 million 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 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 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. Donation allocations and regulatory disallowances in 2013, discussed above, increased operating expense in 2013. In addition, PNM recorded a lease abandonment loss of $6.2 million in operating expenses in 2012, which did not recur in 2013.

Depreciation and amortization expense increased in 2014 and 2013 due to additions to utility plant in service, including PNM-owned solar PV facilities and the Rio Bravo purchase. Depreciation on the PNM-owned solar PV facilities is recovered through the renewable energy rate rider as discussed above.

For 2014, other income (deductions) decreased $0.7 million compared to 2013, primarily due to lower interest income on the PVNGS lessor notes of $1.8 million due to lower outstanding balances. In addition, gains of $0.7 million on the disposition of property in 2013 decreased other income (deductions) for 2014. These decreases were offset by income from the pre-treatment of coal of $0.5 million in 2014 and PNM’s commitments in 2013 of $1.0 million to support employment and other economic activities in the “four corners” area, including the Navajo nation. Other income (deductions) also reflects the performance of the NDT and the trust for coal mine reclamation, including investment income, gains or losses on sales of investments, management expenses, and taxes paid by the trusts. Pre-tax gains on available-for-sale securities decreased $0.1 million in 2014 compared to 2013. For 2013, other income (deductions) was $5.0 million lower than 2012, primarily related to $2.4 million lower gains on available-for-sale securities and $2.3 million lower interest income on the PVNGS lessor notes. PNM commitments of $1.0 million to support the "four corners" area further decreased earnings. These decreases were partially offset by higher equity AFUDC of $0.4 million.

Interest expense increased $0.2 million and $3.1 million in 2014 and 2013 primarily due to the regulatory deferral in2012 of interest costs associated with the construction of PNM-owned solar PV facilities, which are now being amortized as interest income and recovered through the renewable energy rate rider.

As discussed in Note 11, the Company settled an IRS examination in 2014, which resulted in PNM recording an additional income tax expense of $1.1 million. An income tax benefit of $1.3 million reflected in the Corporate and Other segment offsets this amount. In addition, income tax expense for PNM was impacted by an impairment of New Mexico net operating loss carryforwards resulting in additional income tax expense of $2.1 million in 2014.

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TNMP

The table below summarizes the operating results for TNMP:



	Year Ended December 31,									Change
	2014			2013			2012			2014/2013			2013/2012
	(In millions)
Electric operating revenues	$	287.9		$	271.6		$	250.1		$	16.3		$	21.5
Cost of energy	67.9			57.6			46.2			10.3			11.4
Margin	220.0			214.0			203.9			6.0			10.1
Operating expenses	84.4			91.6			87.1			(7.2		)	4.5
Depreciation and amortization	50.1			50.2			49.3			(0.1		)	0.9
Operating income	85.6			72.2			67.5			13.4			4.7
Other income (deductions)	2.1			1.9			2.7			0.2			(0.8		)
Interest charges	(27.4		)	(27.4		)	(28.2		)	—			0.8
Segment earnings before income taxes	60.3			46.7			42.1			13.6			4.6
Income (taxes)	(22.5		)	(17.6		)	(15.4		)	(4.9		)	(2.2		)
Segment earnings	$	37.8		$	29.1		$	26.7		$	8.7		$	2.4

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



	2014/2013 Change								2013/2012 Change
	Total Revenues			Cost of Energy		Margin			Total Revenues			Cost of Energy		Margin
	(In millions)
Rate increases	$	6.3		$	—	$	6.3		$	4.8		$	—	$	4.8
Customer usage/load	0.9			—		0.9			2.0			—		2.0
Customer growth	1.7			—		1.7			1.5			—		1.5
Demand based customers	(0.4		)	—		(0.4		)	3.6			—		3.6
Weather	(2.0		)	—		(2.0		)	(0.7		)	—		(0.7		)
Recovery of third-party transmission costs	10.3			10.3		—			11.8			11.4		0.4
AMS surcharge	4.0			—		4.0			2.7			—		2.7
CTC surcharge	0.3			—		0.3			(3.4		)	—		(3.4		)
Hurricane Ike surcharge	(4.8		)	—		(4.8		)	(0.6		)	—		(0.6		)
Energy efficiency incentive	0.8			—		0.8			0.5			—		0.5
1999 rate settlement	—			—		—			(1.6		)	—		(1.6		)
Other	(0.8		)	—		(0.8		)	0.9			—		0.9
Net change	$	16.3		$	10.3	$	6.0		$	21.5		$	11.4	$	10.1

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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
	2014		2013		2012		2014/2013		2013/2012
	(In millions, except customers)
Residential	$	114.8	$	111.3	$	103.3	$	3.5	$	8.0
Commercial	99.7		95.1		88.3		4.6		6.8
Industrial	15.0		13.1		13.4		1.9		(0.3		)
Other	58.4		52.1		45.1		6.3		7.0
	$	287.9	$	271.6	$	250.1	$	16.3	$	21.5
Average consumers (thousands) ⁽¹⁾	238.2		235.1		233.0		3.1		2.1


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



	Year Ended December 31,			Change
	2014	2013	2012	2014/2013		2013/2012
	(Gigawatt hours)
Residential	2,802.8	2,796.7	2,714.5	6.1		82.2
Commercial	2,564.8	2,451.3	2,353.1	113.5		98.2
Industrial	2,727.1	2,598.4	2,727.1	128.7		(128.7	)
Other	102.1	104.5	103.9	(2.4	)	0.6
	8,196.7	7,950.9	7,898.6	245.9		52.3

Implementation of rate increases in March 2013, September 2013, March 2014, and September 2014 increased revenues and margins by $6.3 million in 2014 compared to 2013. See Note 17. Higher weather normalized load increased revenues and margin by $0.9 million in 2014 compared to 2013. TNMP's weather normalized retail KWh sales increased 3.2% for the year ended 2014 compared to 2013. Milder weather in 2014 compared to 2013, decreased revenues and margins by $2.0 million. Cooling degree days were 2.2% lower than 2013 and heating degree days were 2.0% higher than in 2013. Due to the climate in TNMP’s service territories, variances in cooling degree days have a much larger impact than variances in heating degree days. TNMP experienced average customer growth of 1.3% in 2014, increasing revenues and margins by $1.7 million. Rate increases implemented in September 2012, March 2013, and September 2013 increased revenues and margins by $4.8 million in 2013 compared to 2012. Higher weather normalized and leap-year adjusted usage per customer increased margin $2.0 million in 2013. TNMP's weather normalized and leap-year adjusted retail KWh sales increased 2.6% in 2013. Customer growth in TNMP’s service areas increased revenues and margin $1.5 million in 2013. Milder weather in 2013 compared to 2012, decreased revenues and margins by $0.7 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 from other transmission service providers within ERCOT increased cost of energy $10.3 million in 2014 and $11.4 million in 2013. These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue $10.3 million in 2014 and $11.8 million in 2013.

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 $4.0 million in 2014 and $2.7 million in 2013, which offset increases in operating expenses and depreciation.

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Increased revenues and margins from demand based customers of $3.6 million in 2013 compared to 2012 primarily resulting from TNMP, under a PUCT approved tariff, lowering the power factor billing threshold from 700 KW to 300 KW. Such revenues and margins decreased slightly in 2014. In 2012, TNMP received a $1.6 million settlement related to ERCOT transmission rates charged from the fourth quarter of 1999, which did not recur in 2014 or 2013.

TNMP earned energy efficiency incentive bonuses for having achieved demand savings for the 2013 and 2012 program years that exceeded its goals. These incentives were approved by the PUCT on September 11, 2014 for the 2013 program year and November 4, 2013 for the 2012 program year, which increased revenues and margin by $0.8 million in 2014 and $0.5 million in 2013.

The CTC surcharge increased revenues and margin by $0.3 million in 2014 compared to 2013, but decreased $3.4 million in 2013 compared to 2012 due to a rate rider decrease implemented in January 2013. The Hurricane Ike surcharge decreased revenues and margin by $4.8 million in 2014 and $0.6 in 2013. The Hurricane Ike surcharge was terminated in November of 2013 due to full recovery of costs associated with this item. Other changes in revenue include recovery of current energy efficiency program costs collected through the energy efficiency cost recovery factor surcharge and rate case expenses collected through the rate case expense surcharge. Changes in revenues and margins from these surcharges are offset by changes in operating expenses and depreciation and amortization.

Operating expenses decreased $7.2 million in 2014 compared to 2013. Lower employee healthcare claims of $2.1 million decreased operating expense in 2014. Higher capitalization of administrative and general expenses related to higher levels of construction expenditures decreased operating expenses by $2.9 million further decrease operating expenses in 2014. Lower energy efficiency program expenses of $0.3 million and lower rate case expense amortization of $0.7 million decreased operating expense in 2014, which amounts are offset by decreases in revenue under TNMP’s energy efficiency and rate case expense surcharges. Other decreases to operating expenses include both a $0.5 million write-off of costs incurred in exploring the possibility of securitizing the remaining CTC costs and the allocation of the contributions to the PNM Resources Foundation of $0.7 million in 2013, which did not recur in 2014.

Operating expenses increased $4.5 million in 2013 compared to 2012. Higher energy efficiency program costs of $1.5 million increased operating expenses, which are 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 increased operating expenses in 2013 compared to 2012. These increases and the increases due CTC securitization and allocated contributions discussed above were offset by lower vegetation management expenses 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.

Depreciation expense associated with AMS deployment, which is recovered through the AMS surcharge, increased $2.2 million in 2014. Increases in utility plant in service and amortization expense associated with the CTC regulatory asset increased depreciation and amortization $1.6 million and $0.7 million in 2014. These increases were offset by lower amortization of Hurricane Ike costs of $4.7 million compared to 2013. In 2013, depreciation and amortization expense increased due to higher utility plant in service and AMS deployment, which was partially offset by lower amortization of the CTC regulatory asset.

Other income (deductions) increased in 2014 primarily due to an increase in contributions in aid of construction. Other income (deductions) decreased in 2013 due to higher AFUDC on equity funds of $0.6 million in 2012 and a gain on the sale of property of $0.3 million in 2012, which did not recur in 2013.

Interest charges were flat in 2014 compared to 2013. The issuance of $80.0 million of long-term debt under the TNMP 2013 Bond Purchase Agreement on June 27, 2014 increased interest charges $2.0 million, which is offset by lower interest charges due to the maturity of $50.0 million of debt under the TNMP 2011 Term Loan Agreement and the April 2013 exchange of $93.2 million of TNMP’s 9.5% First Mortgage Bonds for an equal amount of a new series of 6.95% First Mortgage Bonds. Interest charges in 2013 decreased compared to 2012 primarily due to this First Mortgage Bond exchange.

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Corporate and Other

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



	Year Ended December 31,									Change
	2014			2013			2012			2014/2013			2013/2012
				(In millions)
Electric operating revenues	$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—
Margin	—			—			—			—			—
Operating expenses	(14.5		)	(18.3		)	(17.9		)	3.8			(0.4		)
Depreciation and amortization	13.1			12.8			17.5			0.3			(4.7		)
Operating income	1.4			5.5			0.3			(4.1		)	5.2
Gain on sale of First Choice	—			—			1.0			—			(1.0		)
Other income (deductions)	(2.4		)	(13.7		)	(8.1		)	11.3			(5.6		)
Interest charges	(12.8		)	(14.9		)	(16.6		)	2.1			1.7
Segment earnings (loss) before income taxes	(13.8		)	(23.1		)	(23.4		)	9.3			0.3
Income (taxes) benefit	5.4			6.9			11.2			(1.5		)	(4.3		)
Segment earnings (loss)	$	(8.4	)	$	(16.2	)	$	(12.2	)	$	7.8		$	(4.0	)

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP under shared services agreements. 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. Such contributions did not occur in 2014 or 2012.

Depreciation expense decreased in 2013 from 2012 due to accelerated amortization of leasehold improvements for a portion of the Company’s corporate headquarters abandoned during 2012. PNM and TNMP deferred their allocations of the accelerated amortization of related leasehold improvements as regulatory assets to be recovered through rates. 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 (deductions) are primarily due to losses of $3.3 million recognized in 2013 on the repurchase of $23.8 million of PNMR’s 9.25% senior unsecured notes (Note 6), the $4.0 million in contributions discussed above, and a $3.6 million decrease in amortization related to corporate investments that became fully amortized in 2013.

Interest charges decreased year-over-year in 2014 and 2013 primarily due to the repurchase of 9.25% senior unsecured notes. In addition, interest charges decreased due to lower borrowings and lower interest rates on short-term borrowings.

In 2014 and 2013, income tax benefits were reduced by $1.9 million and $3.9 million due to impairments of net operating loss carryforwards and New Mexico wind energy production tax credit carryforwards. The impaired carryforwards 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. Additional income tax expense of $0.2 million and $1.2 million was recognized in 2014 and 2013 due to reductions in Corporate and Other’s deferred tax assets resulting from legislation, which reduced future New Mexico corporate income tax rates. The settlement of an IRS examination in 2014 resulted in an income tax benefit of $1.3 million in Corporate and Other. An additional income tax expense of $1.1 million reflected in the PNM segment offsets this amount. 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
	2014			2013			2012			2014/2013			2013/2012
	(In millions)
Net cash flows from:
Operating activities	$	414.9		$	386.6		$	281.3		$	28.3		$	105.2
Investing activities	(485.3		)	(331.4		)	(285.9		)	(153.9		)	(45.6		)
Financing activities	96.2			(61.6		)	(1.6		)	157.8			(60.0		)
Net change in cash and cash equivalents	$	25.7		$	(6.5	)	$	(6.1	)	$	32.2		$	(0.3	)

The changes in PNMR’s cash flows from operating activities primarily relate to income tax refunds received of $2.6 million in 2014 compared to refunds received of $95.3 million in 2013 and income taxes paid of $5.3 million in 2012 and rate increases at TNMP and PNM. Contributions to the PNM and TNMP pension and other postretirement benefit plans of $5.4 million in 2014 compared to $66.5 million in 2013 and $88.5 million in 2012 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 lower retail load at PNM in 2014 and 2013.

Cash flows from investing activities were driven primarily by increases in plant additions of $112.6 million in 2014 compared to 2013 and $39.1 million in 2013 compared to 2012. At PNM, total utility plant additions were $76.9 million higher in 2014 compared to 2013, including increases in generation additions of $40.0 million, transmission and distribution additions of $33.5 million and nuclear fuel purchases of $4.8 million offset by a decrease in renewable additions of $1.4 million. PNM utility plant additions were $43.1 million higher in 2013 compared to 2012, including $35.7 million related to solar projects and increases in transmission and distribution additions of $22.7 million, offset by lower generation additions of $9.5 million and lower nuclear fuel purchases of $5.8 million. TNMP utility plant additions increased by $38.1 million in 2014 compared to 2013, including increases in distribution additions of $18.7 million, transmission additions of $17.8 million, and AMS additions of $1.6 million. TNMP utility plant additions decreased $3.9 million in 2013 compared to 2012, including an increase in AMS additions of $2.5 million, offset by a decrease in other transmission and distribution additions of $6.4 million. Cash flows from investing activities were also affected by the $36.2 million acquisition of Rio Bravo in 2014 as discussed in Note 9 and proceeds from the sale of First Choice of $4.0 million in 2012.

The changes in PNMR’s cash flows from financing activities include reductions in net short-term borrowings of $34.1 million in 2014 compared to 2013 and $85.5 million in 2013 compared to 2012. Long-term borrowings in 2014 include the $175.0 million PNM 2014 Term Loan agreement and $100.0 million of the $125.0 million PNM Multi-draw Term Loan, which were used to repay amounts under the existing PNM 2013 Term Loan Agreement and other short-term borrowings. In addition, 2014 includes the issuance of $80.0 million in long-term debt at TNMP, which was used to repay amounts under the existing TNMP 2011 Term Loan Agreement and other short-term borrowings. Long-term borrowings in 2013 include the $75.0 million PNM 2013 Term Loan Agreement. In 2013, $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. Borrowings in 2012 include the $100.0 million PNMR Term Loan Agreement, which was used to repay borrowings under the PNMR Revolving Credit Facility. PNM also refinanced $20.0 million of PCRBs in 2012.

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, the $175.0 million PNM 2014 Term Loan Agreement, and the $125.0 million PNM Multi-draw Term Loan, as well as the credit facilities discussed under Liquidity below, each contain 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 leases as debt. At December 31, 2014, interest rates on outstanding borrowings were 1.02% for the PNMR Term Loan Agreement, 1.11% for the PNM 2014 Term Loan Agreement, and 0.75% for the PNM Multi-draw Term Loan.

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 2015-2019 are:



	2015		2016-2019		Total
	(In millions)
Construction expenditures	$	569.2	$	1,638.1	$	2,207.3
Dividends on PNMR common stock	63.7		254.9		318.6
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	633.4	$	1,895.1	$	2,528.5

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 $70.7 million related to environmental upgrades at SJGS to address regional haze and $268.4 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 $80.0 million, and the purchase of the leased portion of the EIP, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $72.1 million in 2015. See Note 16 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

During the year ended December 31, 2014, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and borrowings under term loans and the TNMP 2013 Bond Purchase Agreement.

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. PNMR’s 9.25% senior unsecured notes mature on May 15, 2015; $39.3 million of PNM’s senior unsecured notes, pollution control revenue bonds, are subject to mandatory tender for remarketing on June 1, 2015; and the $175.0 million PNM 2014 Term Loan Agreement matures on September 4, 2015. Note 6 contains additional information about the maturities of long-term debt. Also, the $100.0 million PNMR Term Loan Agreement matures on December 21, 2015 and the $125.0 million PNM Multi-draw Term Loan matures on June 21, 2016. PNMR and PNM anticipate that funds to repay the long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, borrowing under their revolving credit facilities, issuance of new long-term debt, or a combination of these sources. 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 currently expire in October 2019 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR

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Revolving Credit Facility and the PNM Revolving Credit Facility provide for an additional one-year extension option for each facility, subject to approval by a majority of the lenders. 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.

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 may 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 $21.1 million during the year ended December 31, 2014, zero to $84.0 million during the year ended December 31, 2013, and $14.0 million to $141.0 million during the year ended December 31, 2012. Such borrowings ranged from zero to $0.6 million during the three months ended December 31, 2014. Borrowings under the PNM Revolving Credit Facility ranged from zero to $82.0 million during the year ended December 31, 2014, zero to $130.8 million during the year ended December 31, 2013, and zero to $168.0 million during the year ended December 31, 2012. Such borrowings ranged from zero to $45.0 million during the three months ended December 31, 2014. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $25.0 million during the year ended December 31, 2014 and zero to $15.0 million during the three months ended December 31, 2014. There were no such borrowings in 2013 and 2012. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $30.0 million during the year ended December 31, 2014 and from zero to $40.0 million during the year ended December 31, 2013. There were no such borrowings in 2012. Such borrowings ranged from zero to $5.0 million during the three months ended December 31, 2014. At December 31, 2014, the interest rates on outstanding borrowings were 1.67% for the PNMR Revolving Credit Facility and 1.17% for the TNMP Revolving Credit Facility. The PNM Revolving Credit Facility and the PNM New Mexico Credit Facility had no borrowings outstanding at December 31, 2014.

The Company currently believes that its capital requirements can be met through internal cash generation, existing or new 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 could 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 2015-2019 period. This could include new debt issuances and/or new equity.

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. On April 30, 2014, S&P changed the corporate credit ratings outlook to positive from stable for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade. As of February 20, 2015, ratings on the Company’s securities were as follows:



	PNMR	PNM	TNMP
S&P
Senior secured debt	*	*	A-
Senior unsecured debt	BBB-	BBB	*
Preferred stock	*	BB+	*
Moody’s
Senior secured debt	*	*	A2
Senior unsecured debt	Baa3	Baa2	*
* 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 20, 2015 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 20, 2015:
Revolving credit facility	$	0.8	$	10.0	$	20.0	$	30.8
PNM New Mexico Credit Facility	—		15.0		—		15.0
Letters of credit	7.7		3.2		0.1		11.0
Total short term-debt and letters of credit	8.5		28.2		20.1		56.8
Remaining availability as of February 20, 2015	$	291.5	$	421.8	$	54.9	$	768.2
Invested cash as of February 20, 2015	$	1.9	$	42.5	$	—	$	44.4

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. The availability amounts do not include remaining capacity of $25.0 million available under the PNM Multi-draw Term Loan at February 20, 2015.

PNMR can offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2015. PNM has a shelf registration statement for up to $500.0 million of senior unsecured notes that expires in May 2017.

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating leases for portions of PVNGS Units 1 and 2 and the EIP transmission line.

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, contained options to renew the leases at a fixed price or to purchase the property for fair market value.

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 entered into an amendment with the lessor under one of the PVNGS Unit 2 leases that extended that lease from its original expiration on January 15, 2016 through January 15, 2024. PNM has entered into agreements with the lessors under the other three PVNGS Unit 2 leases under which PNM will exercise its option to purchase the assets underlying the leases at the agreed to fair market values aggregating $163.3 million 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. See Sources of Power in Part I, Item 1, Investments in Note 1, and Note 7 for additional information.

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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 and include the renewals described above.



	PVNGS Units 1&2
	(In thousands)
2015	$	25,319
2016	20,589
2017	18,139
2018	18,139
2019	18,139
Thereafter	65,124
Total	$	165,449

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 on April 1, 2015 and contained 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 the agreed to fair market value of $7.7 million. See Note 7.

Commitments and Contractual Obligations

The following table sets forth PNMR’s long-term contractual obligations as of December 31, 2014. See Note 7 for further details about the Company’s significant leases:



	Payments Due
Contractual Obligations	2015		2016-2017		2018-2019		2020 and Thereafter		Total
	(In thousands)
Long-term debt (a)	$	333,066	$	157,000	$	622,327	$	842,743	$	1,955,136
Interest on long-term debt (b)	107,233		200,081		124,432		637,984		1,069,730
Operating leases (c)	36,350		54,077		50,397		134,068		274,892
Transmission reservation payments	14,422		23,922		21,073		31,935		91,352
Coal contracts (d)	89,740		172,087		55,456		392,171		709,454
Coal mine decommissioning (e)	2,627		2,685		1,039		144,408		150,759
Nuclear decommissioning funding requirements (f)	2,637		5,274		5,274		—		13,185
Outsourcing	5,325		6,861		1,380		—		13,566
Pension and retiree medical (g)	35,463		23,435		20,218		—		79,116
Construction expenditures (h)	569,203		957,910		680,177		—		2,207,290
Total (i)	$	1,196,066	$	1,603,332	$	1,581,773	$	2,183,309	$	6,564,480


(a)	Represents total long-term debt, excluding unamortized discounts of $1.9 million and unamortized premiums of $21.9 million


(b)	Represents interest payments during the period


(c)	The operating lease amounts include payments under the PVNGS leases through the expiration of the leases, including renewal periods for leases for which PNM has agreed to renew; 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 (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

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(h)

Represents forecasted construction expenditures, including nuclear fuel, under which substantial commitments have been made (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; see Capital Requirements above and Note 7

(i)

PNMR is unable to reasonably estimate the timing of liability 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 $15.0 million is 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.

The PNMR Revolving Credit Facility, PNM Revolving Credit Facility, PNM New Mexico Credit Facility, and TNMP Revolving Credit Facility contain “ratings triggers,” for pricing purposes only. If PNMR, PNM, or TNMP is downgraded or upgraded by the ratings agencies, the result would be an increase or decrease in interest cost. In addition, these facilities, as well as the PNMR Term Loan Agreement, PNM 2014 Term Loan Agreement, and PNM Multi-draw Term Loan each contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%. For PNMR and PNM, the present value of payments under the PVNGS 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.

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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	2014		2013
PNMR common equity	46.4	%	48.8	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	53.3	%	50.9	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	45.7	%	48.2	%
Preferred stock	0.4	%	0.4	%
Long-term debt	53.9	%	51.4	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.9	%	59.9	%
Long-term debt	41.1	%	40.1	%
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 2014, GHG associated with PNM’s interests in its generating plants were approximately 6.8 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG. By comparison, the total GHG in the United States in 2012, the latest year for which EPA has published this data, were approximately 6.5 billion metric tons, of which approximately 5.4 billion metric tons were CO₂.

PNM has several programs underway to reduce or offset 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. In 2014, PNM added an additional 23 MW of utility-scale solar generation. PNM’s 2015 renewable energy procurement includes the construction of an additional 40 MW of PNM-owned solar PV facilities by December 31, 2015. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and began purchasing the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW, 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 capacity 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 39 MW at the end of 2014 and is expected to grow to over 45 MW by the end of 2015. Once fully subscribed, the distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 120 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2014 budget of $22.5 million and anticipated program costs of $25.8 million for the program year beginning in June 2015. PNM estimates these programs saved approximately 75 GWh of electricity in 2014. Over the next 20 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 13,000 GWh of electricity, which will avoid at least 6.5 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the high uncertainty of many of the underlying variables, including changes in demand for electricity, and complex interrelationships between those variables.

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

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considers associated issues around climate change, the Company’s GHG exposures, and financial consequences that might result from potential federal and/or state regulation of GHG.

As of December 31, 2014, approximately 71.2% 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% at SJGS. That agreement also contemplates that gas-fired generation would be built to partially replace the retired capacity. Although replacement power strategies include some gas-fired generation, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement generation. In September 2013, the EIB approved a RSIP submitted by NMED that encompassed the February 15, 2013 agreement and the RSIP was submitted to EPA for approval on October 18, 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 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 any such costs 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, forest fires, 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 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 was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered 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 would be subject to PSD permitting requirements, even if they did not significantly increase emissions of any other pollutant. As a result, PNM’s fossil-fueled generating plants were more likely to trigger PSD permitting requirements because of the magnitude of GHG. However as discussed below, a recent court case has now limited the extent of 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 the 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 would review 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 dealt with whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and

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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 June 23, 2014, the United States Supreme Court issued its opinion on the above case. The Supreme Court largely reversed the D.C. Circuit. First, the Supreme Court found the CAA does not compel or permit EPA to adopt an interpretation of the act that requires a source to obtain a PSD or Title V permit on the sole basis of its potential GHG. Second, EPA had argued that even if it was not required to regulate GHGs under the PSD and Title V programs, the Tailoring Rule was nonetheless justified on the grounds that it was a reasonable interpretation of the CAA. The Supreme Court rejected this argument. Third, the Supreme Court found EPA lacked authority to "tailor" the CAA's unambiguous numerical thresholds of 100 or 250 tons per year. Fourth, the Supreme Court found that it would be reasonable for EPA to interpret the CAA to limit the PSD program for GHGs to "anyway" sources – those sources that have to comply with the PSD program for other non-GHG pollutants. The Supreme Court said that EPA needed to establish a de minimis level below which BACT would not be required for "anyway" sources.

On March 27, 2012, EPA issued its proposed carbon pollution standards, under Section 111(b) of the CAA, for GHG from new 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. As a result of the comments, EPA reproposed the EGU NSPS as discussed below.

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 under Section 111(d) of the CAA.

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 met the President’s timeline for the reproposal of the GHG NSPS for new sources (under Section 111(b) of the CAA) 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’s reproposed GHG NSPS for new sources applies only to new fossil-fired EGUs. The reproposed standards, based on the size of the unit, would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and simple cycle turbines, and new sources meeting certain other criteria. New coal-fired facilities would only be able to meet the standard by using partial carbon capture and sequestration technology. 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.

The Presidential Memorandum directed EPA to issue the proposed GHG NSPS for modified and existing EGUs by June 1, 2014 and to issue the final rule by June 1, 2015. On June 2, 2014, EPA released the proposed rule under Section 111(d) of the CAA to establish GHG performance standards for existing EGUs. The proposed existing source rule would require state-specific CO₂ emission reduction goals based on EPA’s finding of the best system of emissions reductions (“BSER”). States would be required to meet both an interim goal from 2020 to 2029 and a final goal beginning in 2030. The proposed BSER is based on four “building blocks”: 1) a 6% heat rate improvement to coal-fired generation units; 2) a shift in electrical generation from coal-fired and oil/gas-fired EGUs to natural gas combined cycle units (“NGCCs”) such that the NGCCs are at a 70% utilization rate; 3) substitution of fossil fuel generation with renewable resources and new nuclear facilities, and extension of life of about 6% of existing nuclear plants that may be retired; and 4) increases to demand-side energy efficiency programs. States would be required to develop SIPs to reach the CO₂ emission reduction goals. The SIPs would need to include enforceable CO₂ emission limits that apply to the affected EGUs within the state. EPA is proposing to allow flexibility in how each state achieves the goal including an option to use either a rate-based or mass-based standard and to develop multi-state compliance plans. State SIPs would be due thirteen months after the date that the final rule is published in the Federal Register with the possibility of a one year extension if a state needs additional time or a two year extension if states choose to enter a multi-state approach. Comments on the proposed

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rule were originally due on or before October 16, 2014, which was extended to December 1, 2014. PNM submitted comments by the deadline.

Also on June 2, 2014, EPA proposed carbon pollution standards for modified and reconstructed EGUs. Under the proposed rule there are two alternatives for EGUs: 1) a CO₂ emission limit based on the unit’s best historic annual CO₂ emissions plus an additional 2% reduction or 2) an emission limit dependent on when the unit is modified. Sources modified before becoming subject to a section 111(d) plan would be required to meet an emission limit determined by the unit’s best historical annual CO₂ emission rate plus an additional 2% emission reduction. Units modified after becoming subject to a section 111(d) plan would be required to meet a unit-specific emission limit determined by the section 111(b) implementing authority.

On October 28, 2014, EPA issued a supplemental rule proposing CO₂ emission rates for U.S. territories and areas of Indian country with existing fossil fuel-fired EGUs, as well as guidelines for plans to achieve those rates. The supplemental proposal would apply to Four Corners, which is located on the Navajo Nation. With respect to this plant, EPA applied the four building blocks described in its June 18, 2014 CAA Section 111(d) proposal to establish interim and final goals, expressed as CO₂ emission rates. APS has indicated that if the rule is finalized as proposed, it is unlikely that additional emission reductions would be required as a result of the plant’s past and future actions to comply with the requirements for BART.

On January 7, 2015, EPA announced their intention to propose a federal plan to meet the requirements of the section 111(d) rule, to be released in the summer of 2015 and finalized in summer 2016. EPA also announced changes to the schedule for issuing the final GHG rule regulations for new, modified/reconstructed, and existing EGUs in "Summer 2015." As a result, deadlines for compliance in subsequent years for section 111(d) actions will shift from “June” to “Summer.” EPA initially proposed to issue a final rule for new EGUs by January 8, 2015 and had previously planned to finalize its modified/reconstructed and existing source rules in June 2015.

EPA regulation of GHG from large stationary sources will impact PNM’s fossil-fueled EGUs. Impacts could involve investments in additional renewables, 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. 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 NSPS requirements, are in draft form and existing power plants will be regulated by state plans that will not be finalized for several years. PNM estimates that implementation of the RSIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by the later of January 2016 or 15 months after EPA approval of the RSIP and the retirement of SJGS Units 2 and 3 by the end of 2017, should provide a significant step towards compliance with Section 111(d). PNM is currently reviewing the proposed Section 111(d) rule and is unable to predict the impact of this rule on its fossil fueled generation.

Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2015. Instead, EPA continues to be the primary venue for GHG regulation in the near future, especially for coal-fired EGUs. PNM has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business. This assessment is ongoing 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 or tax 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.

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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 1, 2014 showed that consideration of carbon emissions costs impacted the projected in-service dates of some of the identified resources.

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 28, 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 United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was produced at the United Nations Conference on Environment and Development (informally known as the Earth Summit). Since the UNFCCC entered into force in March 1994, the parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in dealing with climate change and, beginning in the mid-1990s, to negotiate the Kyoto Protocol to establish legally binding obligations for developed countries to reduce their GHG. Specifically, the objective is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” The Company monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities. At the COP meeting in 2011, participating nations, including the United States, agreed that in 2015, they would sign an international treaty requiring all nations to begin reducing carbon emissions by 2020. Known as the Durban Platform for Enhanced Action, the new treaty would supplant the Kyoto Protocol, which was adopted in 1997, that targeted only industrialized nations for mandatory climate emission reductions. The Obama administration released its goals in November of 2014 and other nations are expected to release their proposed goals in the first half of 2015. The 2015 COP will be held in December. The objective of the conference is to achieve a legally binding agreement on climate from all nations. PNM will continue to monitor the United States participation in international accords. However, the Company believes that the Obama administration’s target for the electric utility industry will be based on EPA’s current proposals to regulate carbon and that implementation of the RSIP for BART at SJGS should provide a significant step towards compliance with the requirements.

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

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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 MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. On June 19, 2014, FERC issued a NOPR to approve a new reliability standard. 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. MOD-001-2 will replace multiple existing reliability standards and will remove the risk of reduced TTC for PNM and other western 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 their regional 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 their cost allocation and inter-regional coordination plan compliance filing between WestConnect and other regions.

On September 18, 2014, PNM along with the other WestConnect FERC jurisdictional entities received a FERC order on their respective September 20, 2013 compliance filings with respect to FERC Order 1000 concerning regional planning and cost allocation. The FERC order required the West Connect entities to make another compliance filing to change certain aspects of their respective Attachment K of their respective transmission tariffs and to hold a single year “abbreviated planning process for year 2015.” The order also required the WestConnect entities to file the WestConnect “Planning Participation Agreement.” Of significant concern to the FERC jurisdictional entities in this most recent order was FERC’s ruling that the non-jurisdictional entities would not be required to participate in cost allocation on regional projects, which the jurisdictional entities believed does not comport with FERC’s Order 1000 position on the “cost causation principle” and could create a “free rider-ship” issue for certain participants in the planning process.

The jurisdictional entities filed compliance filings regarding the September 18, 2014 FERC order on November 17, 2014, making several adjustments to the language in their respective Attachment K. The jurisdictional entities also filed, as a separate document an unsigned version of the proposed final version of the Planning Participation Agreement on November 17, 2014. Several entities have intervened and some have protested aspects of these filings.

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The jurisdictional entities jointly filed a request for re-hearing or clarification of the FERC order on October 20, 2014, specifically citing the cost allocation issue. Filings to preserve rights to appeal have been made at the United States Court of Appeals for the Fifth Circuit and at the Federal District Court level on behalf of the jurisdictional entities.

On December 18, 2014, FERC issued an order conditionally accepting the WestConnect jurisdictional entities May 10, 2013 compliance filings regarding transmission coordination and cost allocation planning process at the inter-regional transmission level. The order will require some minor changes to each of the WestConnect jurisdictional entities respective Attachment K language, to comply with requirements of the December 18, 2014 FERC order.

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 record keeping 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 in compliance with the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of implementing and complying with the Dodd-Frank Reform Act and related rules, PNM’s swap activities could be subject to increased costs, including from higher margin requirements. 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.

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.

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The Company has made adjustments to regulatory assets and liabilities that 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 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 is evaluated for impairment at least annually, or more frequently if events and circumstances indicate that the goodwill 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. For 2014, 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, 2014. 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 2014 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 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.

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The Company believes that the WACC and cash flow projections utilized in the 2014 quantitative testing appropriately reflected the fair value of the PNM reporting unit. Since any cash flow projection contains uncertainty, the WACC used by the Company was adjusted 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, 2014, the fair value of the PNM reporting unit, which had goodwill of $51.6 million, exceeded its carrying value by approximately 30%. 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 23% at April 1, 2014. 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, including estimates of future decommissioning costs at current price levels, inflation rates, and discount rates. 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 estimates of the costs for removing all radioactive and other structures at PVNGS. 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 $9.4 million at December 31, 2014. 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 periodic 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 $3.4 million at December 31, 2014. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. 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 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

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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. 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.


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES 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:

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

• Approving of the types of derivatives entered into for hedging

• Reviewing and approving hedging risk activities

• Establishing policies regarding counterparty exposure and limits

• Authorizing and delegating transaction limits

• Reviewing and approving controls and procedures for derivative activities

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• Reviewing and approving 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, 2014 and 2013, 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, 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
Amount realized on contracts delivered during period	1,420
Changes in fair value	5,084
Net mark-to-market change recorded in earnings	6,504
Net change recorded as regulatory liability	(231		)
Net fair value at December 31, 2014	$	9,546

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, 2014



	Settlement Dates
	2015		2016
PNMR and PNM	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—
Prices provided by other external sources	10,023		(477		)
Prices based on models and other valuations	—		—
Total	$	10,023	$	(477	)

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

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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, 2014, the high, low, and average VaR amounts were $2.1 million, $0.6 million, and $0.9 million. 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. At December 31, 2014 and December 31, 2013, the VaR amounts for the PNM wholesale portfolio were $1.3 million and $0.6 million.

The VaR limits, which were not exceeded during 2014 or 2013, 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) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at December 31, 2014 will mature in less than two years.

Schedule of Credit Risk Exposure

December 31, 2014



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	$	6,290	2	$	5,131
Non-investment grade	—		—	—
Internal ratings:
Investment grade	1,003		—	—
Non-investment grade	781		—	—
Total	$	8,074		$	5,131


⁽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 firm-requirements wholesale 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, 2014, 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, 2014 was $7.2 million, which is due from a firm-requirements wholesale 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.

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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 1.9%, 1.4%, and 4.0%, if interest rates were to decline by 50 basis points from their levels at December 31, 2014. 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. At February 20, 2015, PNMR, PNM, and TNMP had $0.8 million, $10.0 million, and $20.0 million 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 $15.0 million under the $50.0 million PNM New Mexico Credit Facility at February 20, 2015. The revolving credit facilities, the PNM New Mexico Credit Facility, the $175.0 million PNM 2014 Term Loan, the $125.0 million PNM Multi-draw Term Loan, and the $100.0 million PNMR Term Loan Agreement bear interest at variable rates. On February 20, 2015, interest rates on borrowings averaged 1.67% for the PNMR Revolving Credit Facility, 1.02% for the PNMR 2014 Term Loan Agreement, 0.75% for the PNM Multi-draw Term Loan, 1.42% for the PNM Revolving Credit Facility, 1.42% for the PNM New Mexico Credit Facility, 1.12% for the PNM Term Loan, and 1.17% for the TNMP Revolving Credit Facility. 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 $917.3 million at December 31, 2014, of which 57.6% 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, 2014, the decrease in the fair value of the fixed-rate securities would be 5.8%, or $30.6 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $79.4 million at December 31, 2014, of which 59.6% 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, 2014, the decrease in the fair value of the fixed-rate securities would be 6.4%, or $3.0 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, 2014. These equity securities expose PNM and TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 32.8% and 25.5% of the securities held by the various PNM and TNMP trusts as of December 31, 2014. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $30.1 million for PNM and $2.0 million for TNMP.

Alternatives Investment Risk

The Company had 11.4% of its pension assets invested in the alternatives asset class as of December 31, 2014. The Company has changed the target for this class to 14%. 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 $7.5 million.

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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- 116
Schedule I - Condensed Financial Information of Parent Company		B- 121
Schedule II - Valuation and Qualifying Accounts		B- 124

B- 1

Table of Contents

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, 2014.

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

B- 2

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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, 2014.

/s/ Patricia K. Collawn

Patricia K. Collawn,

President and Chief Executive Officer

/s/ Charles Eldred

Charles Eldred

Executive Vice President and

Chief Financial Officer

B- 3

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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, 2014.

/s/ Patricia K. Collawn

Patricia K. Collawn,

Chief Executive Officer

/s/ Thomas G. Sategna

Thomas G. Sategna

Vice President and Controller

B- 4

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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, 2014, 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, 2014, 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 sheets of the Company as of December 31, 2014 and 2013, the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014, and our report dated February 27, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Albuquerque, New Mexico

February 27, 2015

B- 5

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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 sheets of PNM Resources, Inc and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. 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 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2014, 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), the Company’s internal control over financial reporting as of December 31, 2014, 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 27, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Albuquerque, New Mexico

February 27, 2015

B- 6

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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 accompanying consolidated statements of earnings, comprehensive income, changes in equity, and cash flows of PNM Resources, Inc. and subsidiaries (the "Company") for the year 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 audit.

In our opinion, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of PNM Resources, Inc. and subsidiaries for the year 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

B- 7

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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 the accompanying consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. 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 audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 27, 2015

B- 8

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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

We have audited the accompanying consolidated statements of earnings, comprehensive income, changes in equity, and cash flows of Public Service Company of New Mexico and subsidiaries (the "Company") for the year 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 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, 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, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Public Service Company of New Mexico and subsidiaries for the year 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

B- 9

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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 sheets of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in common stockholder’s equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. 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 audits.

/s/ KPMG LLP

Albuquerque, New Mexico

February 27, 2015

B- 10

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Texas-New Mexico Power Company

Lewisville, Texas

We have audited the accompanying consolidated statements of earnings, comprehensive income, changes in common stockholder’s equity, and cash flows of Texas-New Mexico Power Company and subsidiaries (the "Company") for the year 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 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, 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, such consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of Texas-New Mexico Power Company and subsidiaries for the year 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

B- 11

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS



	Year Ended December 31,
	2014			2013			2012
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,435,853		$	1,387,923		$	1,342,403
Operating Expenses:
Cost of energy	471,556			432,316			399,850
Administrative and general	171,111			179,210			187,740
Energy production costs	185,638			175,819			185,417
Regulatory disallowances	1,062			12,235			—
Depreciation and amortization	172,634			166,881			164,173
Transmission and distribution costs	66,571			70,124			71,125
Taxes other than income taxes	67,584			64,496			60,377
Total operating expenses	1,136,156			1,101,081			1,068,682
Operating income	299,697			286,842			273,721
Other Income and Deductions:
Interest income	8,483			10,043			13,072
Gains on available-for-sale securities	10,527			10,612			12,965
Other income	12,048			10,572			12,746
Gain on sale of First Choice	—			—			1,012
Other (deductions)	(10,481		)	(21,552		)	(17,636		)
Net other income and deductions	20,577			9,675			22,159
Interest Charges	119,627			121,448			120,845
Earnings before Income Taxes	200,647			175,069			175,035
Income Taxes	69,738			59,513			54,910
Net Earnings	130,909			115,556			120,125
(Earnings) Attributable to Valencia Non-controlling Interest	(14,127		)	(14,521		)	(14,050		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Net Earnings Attributable to PNMR	$	116,254		$	100,507		$	105,547
Net Earnings Attributable to PNMR per Common Share:
Basic	$	1.46		$	1.26		$	1.32
Diluted	$	1.45		$	1.25		$	1.31

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

B- 12

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

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Net Earnings	$	130,909		$	115,556		$	120,125
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(6,812), $(10,855), and $(15,262)	10,661			16,564			23,286
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $5,461, $4,734, and $14,755	(8,401		)	(7,222		)	(22,514		)
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit of $6,024, $(6,781) and $11,910	(9,258		)	10,355			(18,174		)
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,032), $(2,524) and $(1,825)	3,120			3,840			2,786
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $53, $98, and $153	(100		)	(181		)	(275		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(195), $(73), and $(65)	363			134			117
Total Other Comprehensive Income (Loss)	(3,615		)	23,490			(14,774		)
Comprehensive Income	127,294			139,046			105,351
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,127		)	(14,521		)	(14,050		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Comprehensive Income Attributable to PNMR	$	112,639		$	123,997		$	90,773

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,
	2014			2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	130,909		$	115,556		$	120,125
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	209,867			208,173			206,499
Deferred income tax expense	72,481			60,430			56,243
(Gain) on sale of First Choice	—			—			(1,012		)
Net unrealized (gains) on derivatives	(6,504		)	(1,866		)	(1,598		)
Realized (gains) on available-for-sale securities	(10,527		)	(10,612		)	(12,965		)
Loss on reacquired debt	—			3,253			—
Abandonment of leased premises	—			—			7,411
Stock based compensation expense	5,931			5,320			3,585
Regulatory disallowances	1,062			12,235			—
Other, net	(1,518		)	(1,647		)	(798		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(4,975		)	(7,562		)	(2,547		)
Materials, supplies, and fuel stock	5,504			(7,580		)	(5,412		)
Other current assets	(30,436		)	8,577			(2,598		)
Other assets	290			(12,801		)	(30,778		)
Accounts payable	(2,311		)	4,484			14,020
Accrued interest and taxes	2,040			91,537			255
Other current liabilities	(2,453		)	(19,648		)	(19,905		)
Proceeds from governmental grants	—			—			21,567
Other liabilities	45,516			(61,262		)	(70,743		)
Net cash flows from operating activities	414,876			386,587			281,349
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(460,658		)	(348,039		)	(308,909		)
Proceeds from sales of available-for-sale securities	117,989			271,140			167,330
Purchases of available-for-sale securities	(127,016		)	(282,000		)	(176,748		)
Proceeds from sale of First Choice	—			—			4,034
Return of principal on PVNGS lessor notes	20,758			23,357			23,455
Purchase of Rio Bravo	(36,235		)	—			—
Other, net	(167		)	4,096			4,943
Net cash flows from investing activities	(485,329		)	(331,446		)	(285,895		)

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

B- 14

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

	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Cash Flows From Financing Activities:
Short-term loan	—			—			100,000
Revolving credit facilities borrowings (repayments), net	(43,600		)	(9,500		)	(24,000		)
Long-term borrowings	355,000			75,000			20,000
Repayment of long-term debt	(125,000		)	(29,468		)	(22,387		)
Cash paid in debt exchange	—			(13,048		)	—
Proceeds from stock option exercise	6,999			4,618			11,684
Purchases to satisfy awards of common stock	(17,319		)	(13,807		)	(25,168		)
Dividends paid	(59,468		)	(51,508		)	(45,137		)
Valencia’s transactions with its owner	(17,610		)	(18,335		)	(15,630		)
Other, net	(2,808		)	(5,545		)	(922		)
Net cash flows from financing activities	96,194			(61,593		)	(1,560		)
Change in Cash and Cash Equivalents	25,741			(6,452		)	(6,106		)
Cash and Cash Equivalents at Beginning of Year	2,533			8,985			15,091
Cash and Cash Equivalents at End of Year	$	28,274		$	2,533		$	8,985
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	108,741		$	110,768		$	113,265
Income taxes paid (refunded), net	$	(2,597	)	$	(95,327	)	$	5,302

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	3,089		$	6,006		$	(17,983	)
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,
	2014		2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	28,274	$	2,533
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,423	87,038		90,251
Unbilled revenues	63,719		58,806
Other receivables	39,857		53,909
Materials, supplies, and fuel stock	63,628		67,223
Regulatory assets	47,855		24,416
Commodity derivative instruments	11,232		4,064
Income taxes receivable	6,360		7,066
Current portion of accumulated deferred income taxes	26,383		58,681
Other current assets	58,471		34,590
Total current assets	432,817		401,539
Other Property and Investments:
Investment in PVNGS lessor notes	9,538		32,200
Available-for-sale securities	250,145		226,855
Other investments	1,762		1,835
Non-utility property	3,406		4,353
Total other property and investments	264,851		265,243
Utility Plant:
Plant in service and plant held for future use	5,941,581		5,563,061
Less accumulated depreciation and amortization	1,939,760		1,838,832
	4,001,821		3,724,229
Construction work in progress	190,389		132,080
Nuclear fuel, net of accumulated amortization of $44,507 and $47,347	77,796		77,602
Net utility plant	4,270,006		3,933,911
Deferred Charges and Other Assets:
Regulatory assets	491,007		523,955
Goodwill	278,297		278,297
Commodity derivative instruments	—		3,002
Other deferred charges	92,347		94,263
Total deferred charges and other assets	861,651		899,517
	$	5,829,325	$	5,500,210

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,
	2014			2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	105,600		$	149,200
Current installments of long-term debt	333,066			75,000
Accounts payable	110,029			109,666
Customer deposits	12,555			13,456
Accrued interest and taxes	53,863			49,600
Regulatory liabilities	1,703			1,081
Commodity derivative instruments	1,209			2,699
Dividends declared	16,063			14,864
Other current liabilities	70,194			77,105
Total current liabilities	704,282			492,671
Long-term Debt	1,642,024			1,670,420
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	891,111			827,263
Regulatory liabilities	466,143			460,649
Asset retirement obligations	104,170			96,135
Accrued pension liability and postretirement benefit cost	110,738			80,046
Commodity derivative instruments	477			1,094
Other deferred credits	103,759			109,805
Total deferred credits and other liabilities	1,676,398			1,574,992
Total liabilities	4,022,704			3,738,083
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)	1,173,845			1,178,369
Accumulated other comprehensive income (loss), net of income taxes	(61,755		)	(58,140		)
Retained earnings	609,456			553,340
Total PNMR common stockholders’ equity	1,721,546			1,673,569
Non-controlling interest in Valencia	73,546			77,029
Total equity	1,795,092			1,750,598
	$	5,829,325		$	5,500,210

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
	Common Stock			AOCI			Retained Earnings			Total						Total Equity
	(In thousands)
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 before 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 before 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
Proceeds from stock option exercise	6,999			—			—			6,999			—			6,999
Purchases to satisfy awards of common stock	(17,319		)	—			—			(17,319		)	—			(17,319		)
Excess tax (shortfall) from stock-based payment arrangements	(135		)	—			—			(135		)	—			(135		)
Stock based compensation expense	5,931			—			—			5,931			—			5,931
Valencia’s transactions with its owner	—			—			—			—			(17,610		)	(17,610		)
Net earnings before subsidiary preferred stock dividends	—			—			116,782			116,782			14,127			130,909
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Total other comprehensive income	—			(3,615		)	—			(3,615		)	—			(3,615		)
Dividends declared on common stock	—			—			(60,138		)	(60,138		)	—			(60,138		)
Balance at December 31, 2014	$	1,173,845		$	(61,755	)	$	609,456		$	1,721,546		$	73,546		$	1,795,092

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,
	2014			2013			2012
	(In thousands)
Electric Operating Revenues	$	1,147,914		$	1,116,312		$	1,092,264
Operating Expenses:
Cost of energy	403,626			374,710			353,649
Administrative and general	152,645			157,144			169,285
Energy production costs	185,638			175,819			185,403
Regulatory disallowances	1,062			12,235			—
Depreciation and amortization	109,524			103,826			97,291
Transmission and distribution costs	43,128			45,936			46,039
Taxes other than income taxes	39,578			37,457			34,715
Total operating expenses	935,201			907,127			886,382
Operating income	212,713			209,185			205,882
Other Income and Deductions:
Interest income	8,557			10,182			13,243
Gains on available-for-sale securities	10,527			10,612			12,965
Other income	8,949			7,650			8,126
Other (deductions)	(7,218		)	(6,974		)	(7,801		)
Net other income and deductions	20,815			21,470			26,533
Interest Charges	79,442			79,175			76,101
Earnings before Income Taxes	154,086			151,480			156,314
Income Taxes	52,633			48,804			50,713
Net Earnings	101,453			102,676			105,601
(Earnings) Attributable to Valencia Non-controlling Interest	(14,127		)	(14,521		)	(14,050		)
Net Earnings Attributable to PNM	87,326			88,155			91,551
Preferred Stock Dividends Requirements	(528		)	(528		)	(528		)
Net Earnings Available for PNM Common Stock	$	86,798		$	87,627		$	91,023

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,
	2014			2013			2012
	(In thousands)
Net Earnings	$	101,453		$	102,676		$	105,601
Other Comprehensive Income:
Unrealized Gain on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(6,812), $(10,855), and $(15,262)	10,661			16,564			23,286
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $5,461, $4,734, and $14,755	(8,401		)	(7,222		)	(22,514		)
Pension Liability Adjustment:
Experience gain (loss), net of income tax (expense) benefit of $6,024, $(6,781) and $11,910	(9,258		)	10,355			(18,174		)
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,032), $(2,524) and $(1,825)	3,120			3,840			2,786
Total Other Comprehensive Income (Loss)	(3,878		)	23,537			(14,616		)
Comprehensive Income	97,575			126,213			90,985
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,127		)	(14,521		)	(14,050		)
Comprehensive Income Attributable to PNM	$	83,448		$	111,692		$	76,935

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,
	2014			2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	101,453		$	102,676		$	105,601
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	143,303			136,732			129,514
Deferred income tax expense	55,787			50,043			65,479
Net unrealized (gains) losses on derivatives	(6,504		)	(1,866		)	(1,598		)
Realized (gains) on available-for-sale securities	(10,527		)	(10,612		)	(12,965		)
Regulatory disallowances	1,062			12,235			—
Other, net	(1,391		)	(1,614		)	(170		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(5,919		)	(3,021		)	(4,756		)
Materials, supplies, and fuel stock	5,570			(7,730		)	(5,268		)
Other current assets	(29,146		)	8,556			(3,014		)
Other assets	7,150			(13,363		)	(27,338		)
Accounts payable	212			2,807			11,028
Accrued interest and taxes	(3,599		)	72,740			47,666
Other current liabilities	(659		)	(27,376		)	(2,539		)
Proceeds from governmental grants	—			—			21,567
Other liabilities	42,325			(59,753		)	(54,787		)
Net cash flows from operating activities	299,117			260,454			268,420
Cash Flows From Investing Activities:
Utility plant additions	(316,800		)	(239,906		)	(196,800		)
Proceeds from sales of available-for-sale securities	117,989			271,140			167,330
Purchases of available-for-sale securities	(127,016		)	(282,000		)	(176,748		)
Return of principal on PVNGS lessor notes	20,758			23,357			23,455
Purchase of Rio Bravo	(36,235		)	—			—
Other, net	(363		)	3,843			2,406
Net cash flows from investing activities	(341,667		)	(223,566		)	(180,357		)

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,
	2014			2013			2012
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(49,200		)	28,100			(44,900		)
Short-term borrowings (repayments) - affiliate, net	(32,500		)	32,500			—
Long-term borrowings	275,000			75,000			20,000
Repayment of long-term debt	(75,000		)	—			(20,000		)
Valencia’s transactions with its owner	(17,610		)	(18,335		)	(15,630		)
Dividends paid	(30,791		)	(155,556		)	(34,961		)
Other, net	(1,890		)	(2,534		)	(921		)
Net cash flows from financing activities	68,009			(40,825		)	(96,412		)

Change in Cash and Cash Equivalents	25,459			(3,937		)	(8,349		)
Cash and Cash Equivalents at Beginning of Year	21			3,958			12,307
Cash and Cash Equivalents at End of Year	$	25,480		$	21		$	3,958

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	73,787		$	71,306		$	73,036
Income taxes paid (refunded), net	$	(228	)	$	(77,434	)	$	(63,113	)

Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	1,616		$	7,921		$	(19,732	)

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,
	2014		2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	25,480	$	21
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,423	67,622		70,126
Unbilled revenues	54,140		48,992
Other receivables	37,622		52,964
Affiliate receivables	8,853		10,054
Materials, supplies, and fuel stock	60,859		64,520
Regulatory assets	43,980		19,394
Commodity derivative instruments	11,232		4,064
Income taxes receivable	6,105		4,030
Current portion of accumulated deferred income taxes	12,418		43,827
Other current assets	53,095		30,510
Total current assets	381,406		348,502
Other Property and Investments:
Investment in PVNGS lessor notes	9,538		32,200
Available-for-sale securities	250,145		226,855
Other investments	397		445
Non-utility property	96		976
Total other property and investments	260,176		260,476
Utility Plant:
Plant in service and plant held for future use	4,581,066		4,314,016
Less accumulated depreciation and amortization	1,486,406		1,402,531
	3,094,660		2,911,485
Construction work in progress	169,673		107,344
Nuclear fuel, net of accumulated amortization of $44,507 and $47,347	77,796		77,602
Net utility plant	3,342,129		3,096,431
Deferred Charges and Other Assets:
Regulatory assets	357,045		384,217
Goodwill	51,632		51,632
Commodity derivative instruments	—		3,002
Other deferred charges	81,264		83,356
Total deferred charges and other assets	489,941		522,207
	$	4,473,652	$	4,227,616

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,
	2014			2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—		$	49,200
Short-term debt - affiliate	—			32,500
Current installments of long-term debt	214,300			75,000
Accounts payable	86,055			84,643
Affiliate payables	18,232			20,498
Customer deposits	12,555			13,456
Accrued interest and taxes	29,298			27,665
Regulatory liabilities	1,703			1,081
Commodity derivative instruments	1,209			2,699
Dividends declared	132			132
Other current liabilities	52,053			50,392
Total current liabilities	415,537			357,266
Long-term Debt	1,276,357			1,215,618
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	715,814			677,094
Regulatory liabilities	425,481			414,611
Asset retirement obligations	103,182			95,225
Accrued pension liability and postretirement benefit cost	102,850			76,611
Commodity derivative instruments	477			1,094
Other deferred credits	86,023			91,340
Total deferred credits and liabilities	1,433,827			1,355,975
Total liabilities	3,125,721			2,928,859
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	(61,755		)	(57,877		)
Retained earnings	262,835			206,300
Total PNM common stockholder’s equity	1,262,856			1,210,199
Non-controlling interest in Valencia	73,546			77,029
Total equity	1,336,402			1,287,228
	$	4,473,652		$	4,227,616

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, 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
Valencia’s transactions with its owner	—		—			—			—			(17,610		)	(17,610		)
Net earnings	—		—			87,326			87,326			14,127			101,453
Total other comprehensive income (loss)	—		(3,878		)	—			(3,878		)	—			(3,878		)
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(30,263		)	(30,263		)	—			(30,263		)
Balance at December 31, 2014	$	1,061,776	$	(61,755	)	$	262,835		$	1,262,856		$	73,546		$	1,336,402

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,
	2014			2013			2012
	(In thousands)

Electric Operating Revenues	$	287,939		$	271,611		$	250,140
Operating Expenses:
Cost of energy	67,930			57,606			46,201
Administrative and general	36,982			44,635			40,775
Depreciation and amortization	50,056			50,219			49,340
Transmission and distribution costs	23,443			24,188			25,086
Taxes other than income taxes	23,940			22,778			21,218
Total operating expenses	202,351			199,426			182,620
Operating income	85,588			72,185			67,520
Other Income and Deductions:
Interest income	—			—			1
Other income	2,865			2,377			4,698
Other (deductions)	(727		)	(458		)	(1,959		)
Net other income and deductions	2,138			1,919			2,740
Interest Charges	27,396			27,393			28,161
Earnings Before Income Taxes	60,330			46,711			42,099
Income Taxes	22,523			17,621			15,352
Net Earnings	$	37,807		$	29,090		$	26,747

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,
	2014			2013			2012
	(In thousands)
Net Earnings	$	37,807		$	29,090		$	26,747
Other Comprehensive Income (Loss):
Fair Value Adjustment for Designated Cash Flow Hedge:
Change in fair value, net of income tax (expense) benefit of $53, $98, and $153	(100		)	(181		)	(275		)
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit) of $(195), $(73), and $(65)	363			134			117
Total Other Comprehensive Income (Loss)	263			(47		)	(158		)
Comprehensive Income	$	38,070		$	29,043		$	26,589

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,
	2014			2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	37,807		$	29,090		$	26,747
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	52,847			54,395			54,396
Deferred income tax expense	20,549			20,662			4,378
Other, net	(10		)	(30		)	(889		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	944			(4,542		)	2,208
Materials and supplies	(66		)	150			(143		)
Other current assets	380			(1,137		)	(3,515		)
Other assets	(6,607		)	941			(3,145		)
Accounts payable	2,514			3,709			(666		)
Accrued interest and taxes	4,796			(6,713		)	9,825
Other current liabilities	(203		)	(3,197		)	(2,106		)
Other liabilities	3,112			460			4,311
Net cash flows from operating activities	116,063			93,788			91,401
Cash Flows From Investing Activities:
Utility plant additions	(127,191		)	(89,117		)	(92,973		)
Net cash flows from investing activities	(127,191		)	(89,117		)	(92,973		)

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,
	2014			2013			2012
	(In thousands)

Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	5,000			—			—
Short-term borrowings (repayments) – affiliate, net	(6,700		)	1,100			27,600
Long-term borrowings	80,000			—			—
Repayment of long-term debt	(50,000		)	—			—
Cash paid in debt exchange	—			(13,048		)	—
Equity contribution from parent	—			13,800			—
Dividends paid	(16,336		)	(3,726		)	(26,028		)
Other, net	(836		)	(2,797		)	—
Net cash flows from financing activities	11,128			(4,671		)	1,572
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	$	22,803		$	25,436		$	25,360
Income taxes paid, (refunded) net	$	(355	)	$	4,484		$	1,848

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(854	)	$	141		$	(2,749	)

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,
	2014		2013
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	19,416		20,125
Unbilled revenues	9,579		9,814
Other receivables	2,063		1,246
Materials and supplies	2,769		2,703
Regulatory assets	3,875		5,022
Current portion of accumulated deferred income taxes	6,398		6,501
Other current assets	938		980
Total current assets	45,039		46,392
Other Property and Investments:
Other investments	242		245
Non-utility property	2,240		2,240
Total other property and investments	2,482		2,485
Utility Plant:
Plant in service and plant held for future use	1,182,112		1,074,193
Less accumulated depreciation and amortization	375,407		352,105
	806,705		722,088
Construction work in progress	16,538		16,790
Net utility plant	823,243		738,878
Deferred Charges and Other Assets:
Regulatory assets	133,962		139,738
Goodwill	226,665		226,665
Other deferred charges	8,850		8,273
Total deferred charges and other assets	369,477		374,676
	$	1,240,241	$	1,162,431

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,
	2014		2013
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	5,000	$	—
Short-term debt – affiliate	22,700		29,400
Accounts payable	14,203		12,543
Affiliate payables	2,469		3,181
Accrued interest and taxes	28,574		23,778
Other current liabilities	2,271		8,999
Total current liabilities	75,217		77,901
Long-term Debt	365,667		336,036
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	217,945		190,197
Regulatory liabilities	40,662		46,038
Asset retirement obligations	848		782
Accrued pension liability and postretirement benefit cost	7,888		3,435
Other deferred credits	7,349		5,111
Total deferred credits and other liabilities	274,692		245,563
Total liabilities	715,576		659,500
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		404,166
Accumulated other comprehensive income (loss), net of income tax	—		(263		)
Retained earnings	120,435		98,964
Total common stockholder’s equity	524,665		502,931
	$	1,240,241	$	1,162,431

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, 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
Net earnings	—		—			—			37,807			37,807
Total other comprehensive income	—		—			263			—			263
Dividends declared on common stock	—		—			—			(16,336		)	(16,336		)
Balance at December 31, 2014	$	64	$	404,166		$	—		$	120,435		$	524,665

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, 2014, 2013 and 2012


(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’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 are so indicated.

Certain amounts in the 2013 and 2012 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2014 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 interest and income tax sharing payments, as well as 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. Accordingly, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the NMPRC, PUCT, and FERC. Information on regulatory assets and regulatory liabilities is contained in Note 4.

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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, 2014, 2013 and 2012

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.

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.

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, 2014, 2013, and 2012, PNM recorded $4.2 million, $3.3 million, and $3.5 million of allowance for borrowed funds used during construction and $5.6 million, $4.4 million, and $3.8 million of allowance for equity funds used during construction. TNMP recorded $0.5 million, $0.4 million, and $0.7 million of allowance for borrowed funds used during construction and zero, zero, and $0.6 million of allowance for equity funds used during construction.

Capitalized Interest

The Company 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 6.6%, 6.9%, and 6.6% for 2014, 2013, and 2012. In 2014, 2013, and 2012, capitalized interest was $1.6 million, $1.5 million, and $1.2 million for PNMR consolidated; $1.1 million, $1.1 million, and $0.8 million for PNM; and $0.1 million, zero, and zero for TNMP.

Materials, Supplies, and Fuel Stock

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

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

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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, 2014, 2013 and 2012

Inventories consisted of the following at December 31:



	PNMR				PNM				TNMP
	2014		2013		2014		2013		2014		2013
	(In thousands)
Coal	$	17,525	$	24,872	$	17,525	$	24,872	$	—	$	—
Materials and supplies	46,103		42,351		43,334		39,648		2,769		2,703
	$	63,628	$	67,223	$	60,859	$	64,520	$	2,769	$	2,703

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 and held by the PVNGS Capital Trust, which is consolidated by PNM. Eight leases continue and are classified as operating leases. The PVNGS Capital Trust held certain of the lessor notes to their maturity in January 2015 and intends to hold the other lessor notes until their maturity in 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, 2014, 2013, and 2012, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $4.8 million, $3.5 million, and $4.8 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.

Goodwill

Under GAAP, the Company does not amortize goodwill. Goodwill is evaluated for impairment annually, or more frequently if events and circumstances indicate that the goodwill might be impaired. See Note 21.

Asset Impairment

Tangible long-lived assets are evaluated in relation to the estimated 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

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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, 2014, 2013 and 2012

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.

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
	2014		2013		2012
PNM
Electric plant	2.26	%	2.27	%	2.25	%
Common, intangible, and general plant	4.64	%	4.87	%	5.35	%
TNMP	3.59	%	3.66	%	3.56	%

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.

Derivatives

The Company records derivative instruments, including energy contracts, 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. Normal purchases and normal sales are not marked to market and are reflected in results of operations when the underlying transactions settle. 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

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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, 2014, 2013 and 2012

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.

Decommissioning and Reclamation 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 periodic 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. 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 periods. 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, 2014, 2013, and 2012, as well as the amounts of environmental liabilities at December 31, 2014 and 2013 were insignificant.

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

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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, 2014, 2013 and 2012

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 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for the Company beginning on January 1, 2017. Early adoption is not permitted. The standard permits the use of either the retrospective or cumulative effect transition method. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures. The Company has not yet selected a transition method nor has it determined the effect of the standard on its ongoing financial reporting.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is in the process of analyzing the impacts of this new standard.


(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.

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.

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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, 2014, 2013 and 2012

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.

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



2014	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Electric operating revenues	$	1,147,914		$	287,939		$	—		$	1,435,853
Cost of energy	403,626			67,930			—			471,556
Margin	744,288			220,009			—			964,297
Other operating expenses	422,051			84,365			(14,450		)	491,966
Depreciation and amortization	109,524			50,056			13,054			172,634
Operating income	212,713			85,588			1,396			299,697
Interest income	8,557			—			(74		)	8,483
Other income (deductions)	12,258			2,138			(2,302		)	12,094
Interest charges	(79,442		)	(27,396		)	(12,789		)	(119,627		)
Segment earnings (loss) before income taxes	154,086			60,330			(13,769		)	200,647
Income taxes (benefit)	52,633			22,523			(5,418		)	69,738
Segment earnings (loss)	101,453			37,807			(8,351		)	130,909
Valencia non-controlling interest	(14,127		)	—			—			(14,127		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	86,798		$	37,807		$	(8,351	)	$	116,254

Gross property additions	$	316,800		$	127,191		$	16,667		$	460,658
At December 31, 2014:
Total Assets	$	4,473,652		$	1,240,241		$	115,432		$	5,829,325
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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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, 2014, 2013 and 2012



2013	PNM			TNMP			Corporate and Other			Consolidated

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		)
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, 2014, 2013 and 2012



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
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

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 15% and 17% of TNMP’s electric operating revenues in 2014 and 2013. Two other unaffiliated customers of TNMP accounted for revenues of 15% in 2014, 16% in 2013, and 17% in 2012 and 11% in 2014, 10% in 2013, and 10% in 2012.


(3)	Sale of First Choice

PNMR completed the sale of First Choice, which was also a subsidiary of TNP, on November 1, 2011. First Choice was a competitive REP operating in Texas. The amount received was subject to adjustment based on the actual amounts of the components of working capital at October 31, 2011. In 2012, PNMR received an additional amount and recorded a pre-tax gain of $1.0 million, which is included in Other income in the Consolidated Statements of Earnings. 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 from transmission and distribution services provided by TNMP to First Choice, First Choice is not reflected as discontinued operations.


(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.

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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, 2014, 2013 and 2012

PNM



	December 31,
	2014			2013
Assets:	(In thousands)
Current:
FPPAC	$	43,980		$	19,394
Non-Current:
Coal mine reclamation costs	34,224			40,144
Deferred income taxes	63,645			61,850
Loss on reacquired debt	25,439			27,490
Pension and OPEB	222,545			206,691
FPPAC	—			25,386
Renewable energy costs	5,263			13,311
Other	5,929			9,345
	357,045			384,217
Total regulatory assets	$	401,025		$	403,611
Liabilities:
Current:
Other	$	(1,703	)	$	(1,081	)
Non-Current:
Cost of removal	(277,148		)	(266,075		)
Deferred income taxes	(75,941		)	(80,495		)
AROs	(35,834		)	(37,567		)
Renewable energy tax benefits	(24,854		)	(26,011		)
Other	(11,704		)	(4,463		)
	(425,481		)	(414,611		)
Total regulatory liabilities	$	(427,184	)	$	(415,692	)

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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, 2014, 2013 and 2012

TNMP



	December 31,
	2014			2013
Assets:	(In thousands)
Current:
Transmission cost recovery factor	$	2,482		$	4,250
Other	1,393			772
	3,875			5,022
Non-Current:
CTC, including carrying charges	55,292			63,606
Deferred income taxes	10,556			10,868
Pension	23,803			19,938
Loss on reacquired debt	36,703			38,616
AMS retirement costs	6,453			5,083
Other	1,155			1,627
	133,962			139,738
Total regulatory assets	$	137,837		$	144,760
Liabilities:
Non-Current:
Cost of removal	$	(29,391	)	$	(30,863	)
Deferred income taxes	(3,923		)	(4,563		)
AMS surcharge	(5,227		)	(7,251		)
OPEB	(2,121		)	(3,361		)
Total regulatory liabilities	$	(40,662	)	$	(46,038	)

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); 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, 2014. PNMR funded a cash equity contribution of $13.8 million to TNMP in 2013. 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, 2014, 2013 and 2012

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 $30.3 million, $155.0 million, and $34.4 million in 2014, 2013, and 2012. TNMP paid cash dividends to PNMR of $16.3 million, $3.7 million, and $26.0 million in 2014, 2013, and 2012. TNMP recorded dividends paid in 2012 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 New Mexico Credit Facility, PNM 2014 Term Loan Agreement, PNM Multi-draw Term Loan, and TNMP Revolving Credit Facility 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 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, 2014, 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 $223 million and TNMP would not be able to distribute amounts in excess of approximately $203 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

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.

PNMR and TNMP have no preferred stock outstanding. The authorized shares of PNMR and TNMP preferred stock are 10 million shares and 1 million shares.


(6)	Financing

Financing Activities

PNMR

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, through several 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 December 14, 2012, PNMR entered into a $100.0 million Term Loan Agreement (as amended and restated, the “PNMR Term Loan Agreement”) among PNMR, the lenders identified therein, and JPMorgan Chase Bank, N.A., as Administrative Agent. 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. On December 27, 2013, PNMR entered into an agreement that amended and restated the PNMR Term Loan Agreement extending the maturity date to December 26, 2014 from December 27,

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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, 2014, 2013 and 2012

2013. On December 22, 2014, PNMR entered into another agreement that amends and restates the PNMR Term Loan Agreement extending the maturity date to December 21, 2015. 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.

PNM

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 2013 Term Loan Agreement”) among PNM, the lenders identified therein, and Union Bank, N.A., as Administrative Agent. Funding of the PNM 2013 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.

On March 5, 2014, PNM entered into a new $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under the PNM 2013 Term Loan Agreement. PNM also used the funds to repay other short-term amounts outstanding. The PNM 2013 Term Loan Agreement would otherwise have terminated on October 21, 2014. There were no prepayment penalties paid in connection with the termination of the PNM 2013 Term Loan Agreement. The PNM 2014 Term Loan Agreement bears interest at a variable rate, which was 1.11% at December 31, 2014, must be repaid on or before September 4, 2015, and is reflected in current maturities of long-term debt on the Consolidated Balance Sheets. The PNM 2014 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNM 2014 Term Loan Agreement has a cross default provision and a change of control provision.

On December 22, 2014, PNM entered into a new multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million and remaining capacity was $25.0 million. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.75% at December 31, 2014. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw 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 $500.0 million of senior unsecured notes that will expire in May 2017.

TNMP

On September 30, 2011, TNMP entered into the TNMP 2011 Term Loan Agreement and borrowed $50.0 million under it. Borrowings under the TNMP 2011 Term Loan Agreement were due by June 30, 2014. TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing over the life of the debt. This hedge was accounted for as a cash-flow hedge and had a fair value loss of $0.2 million at December 31, 2013, 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.

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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, 2014, 2013 and 2012

On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which provided that TNMP would issue $80.0 million aggregate principal amount of 4.03% first mortgage bonds, due 2024 (the “Series 2014A Bonds”) on or about June 27, 2014, subject to satisfaction of certain conditions. TNMP issued the Series 2014A Bonds on June 27, 2014. TNMP used $50.0 million of the proceeds to repay the full outstanding amount of the TNMP 2011 Term Loan Agreement and used the remaining $30.0 million of proceeds to reduce short-term debt. In accordance with GAAP, borrowings under the TNMP 2011 Term Loan Agreement were reflected as being long-term in the Consolidated Balance Sheet at December 31, 2013 since the TNMP 2013 Bond Purchase Agreement demonstrated TNMP’s ability and intent to re-finance the TNMP 2011 Term Loan Agreement on a long-term basis.

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million. In December 2014, both of these facilities were amended to extend their maturity from October 31, 2018 to October 31, 2019. In addition, the amendments provide for an additional one-year extension option for each facility, subject to approval by a majority of the lenders. 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. The TNMP Revolving Credit Facility matures on September 18, 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%. For PNMR and PNM, these ratios reflect the present value of payments under the PVNGS 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.

At December 31, 2014, interest rates on outstanding borrowings were 1.02% for the PNMR Term Loan Agreement (discussed under Financing Activities above), 1.67% for the PNMR Revolving Credit Facility, and 1.17% for the TNMP Revolving Credit Facility. The PNM Revolving Credit Facility and the PNM New Mexico Credit Facility had no borrowings outstanding at December 31, 2014. Short-term debt outstanding consists of:



	December 31,
Short-term Debt	2014		2013
	(In thousands)
PNM:
Revolving Credit Facility	$	—	$	49,200
PNM New Mexico Credit Facility	—		—
TNMP Revolving Credit Facility	5,000		—
PNMR
Revolving Credit Facility	600		—
PNMR Term Loan Agreement	100,000		100,000
	$	105,600	$	149,200

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $7.7 million, $3.2 million, and $0.1 million at December 31, 2014 that reduce the available capacity under their respective revolving credit facilities.

At February 20, 2015, PNMR, PNM, and TNMP had $291.5 million, $386.8 million, and $54.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $35.0 million of availability under the PNM New Mexico Credit Facility. Total availability at February 20, 2015, on a consolidated basis, was $768.2 million for PNMR. At February 20, 2015, PNMR had invested cash of $1.9 million, PNM had invested cash of $42.5 million, and TNMP had no invested cash. The above availability does not include remaining capacity of $25.0 million available under the PNM Multi-draw Term Loan at February 20, 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, 2014, 2013 and 2012

Long-Term Debt

Information concerning long-term debt outstanding is as follows:



	December 31,
Long-term Debt	2014			2013
	(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
PNM Term Loan Agreement due 2015	175,000			—
PNM Multi-draw Term Loan due 2016	100,000			—
Unamortized premiums (discounts)	(213		)	(252		)
	1,490,657			1,290,618
Less current maturities	214,300			75,000
	1,276,357			1,215,618
TNMP Debt
First Mortgage Bonds:
2011 Term Loan Agreement, due 2014	—			50,000
9.50% due 2019, Series 2009A	172,302			172,302
6.95% due 2043, Series 2013A	93,198			93,198
4.03% due 2024, Series 2014A	80,000			—
Unamortized premiums (discounts)	20,167			20,536
	365,667			336,036
Less current maturities	—			—
	365,667			336,036
PNMR Debt
Senior unsecured notes, 9.25% due 2015	118,766			118,766
Less current maturities	118,766			—
	—			118,766
Total Consolidated PNMR Debt	1,975,090			1,745,420
Less current maturities	333,066			75,000
	$	1,642,024		$	1,670,420

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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, 2014, 2013 and 2012

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



	PNMR		PNM		TNMP		PNMR Consolidated
	(In thousands)
2015	$	118,766	$	214,300	$	—	$	333,066
2016	—		100,000		—		100,000
2017	—		57,000		—		57,000
2018	—		450,025		—		450,025
2019	—		—		172,302		172,302
Thereafter	—		669,545		173,198		842,743
Total	$	118,766	$	1,490,870	$	345,500	$	1,955,136

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, 2014 and 2013, PNM had outstanding borrowings of zero and $32.5 million and TNMP had outstanding borrowings of $22.7 million and $29.4 million from PNMR. At February 20, 2015, PNM and TNMP had borrowings of zero and $17.3 million from PNMR.


(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 within the next five years. 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. All of the Company’s leases, including the Navajo Nation rights-of-way agreement, are accounted for as operating leases.

The PVNGS leases were entered into in 1985 and 1986 and 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 provided 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 provided 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 could 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. For leases that 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 provided that no later than three years prior to the expiration of the lease, PNM was required to give notice to the lessor if it would “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 provided that, if PNM gave notice to “retain” the leased assets, PNM was required to give notice as to which of the purchase or renewal options it would exercise no later than two years prior to the expiration of the lease. The election made under each of the leases was independent of the elections made under the other leases.

Following procedures set forth in the PVNGS leases, PNM notified each of the lessors under the Unit 1 leases that it would elect to renew those leases for the Maximum Option Period on the expiration date of the original leases. In addition, PNM notified

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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, 2014, 2013 and 2012

the lessor under the one Unit 2 lease containing the Maximum Option Period provision that it would elect to renew that lease for the Maximum Option Period on the expiration date of the original lease. 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 expiring on January 15, 2023. Similarly, on March 18, 2014, PNM and the lessor under the one Unit 2 lease containing the Maximum Option Period provision entered into an amendment to that lease setting forth the terms and conditions that will implement the extension of the term of the lease through the agreed upon Maximum Option Period expiring 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, 2014 shown below includes payments during the renewal periods for those leases that will be extended at the end of their original terms.

For the three PVNGS Unit 2 leases which do not contain the Maximum Option Period provisions, PNM, following procedures set forth in the leases, notified each of the lessors that PNM would elect to purchase the assets underlying those leases on the expiration date of the original leases. 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 31.25 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.

On May 1, 2014, PNM and the trusts that are the lessors under the other two PVNGS Unit 2 leases signed a letter agreement that establishes a binding agreement regarding the purchase price, representing the fair market value, to be paid by PNM for the assets underlying those leases of $85.2 million on January 15, 2016. These leases are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the letter agreement, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. The early purchase price would be equal to the January 15, 2016 purchase price discounted to the actual purchase date. The early purchase amount was $79.9 million on June 1, 2014, $81.8 million on December 31, 2014, and escalates to $85.2 million on January 14, 2016. The consideration paid to the lessor on an early purchase would include an additional amount equal to the discounted value of the lessors’ equity return portion of the future lease payments. Such additional consideration was $5.8 million on June 1, 2014, $4.5 million on December 31, 2014, and declines to $1.2 million on January 14, 2016. PNMR and PNM are unable to predict whether or not the early purchase will occur.

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. If such an event had occurred as of December 31, 2014, PNM could have been required to pay the equity participants up to approximately $122.2 million on January 15, 2015 in addition to the scheduled lease payments due on January 15, 2015. 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. Reflecting the lease renewals that were effective on January 15, 2015, if such an event were to occur, amounts payable to equity participants under the circumstances described above would be up to $217.3 million on July 15, 2015 in addition to the scheduled lease payments due on July 15, 2015.

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

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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, 2014, 2013 and 2012

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.

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



	PNMR		PNM		TNMP
	(In thousands)
2014	$	82,756	$	76,745	$	3,932
2013	$	82,882	$	78,306	$	2,663
2012	$	84,794	$	78,483	$	2,871

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. Future minimum operating lease payments at December 31, 2014 shown below have been reduced by payments on the PVNGS lessor notes of $24.0 million in 2015 and $9.0 million in 2016 that will be returned in cash to PNM:



	PNMR		PNM		TNMP
	(In thousands)
2015	$	36,350	$	33,144	$	1,186
2016	28,892		27,986		636
2017	25,185		24,907		—
2018	25,194		24,907		—
2019	25,203		24,907		—
Later years	134,068		133,842		—
Total minimum lease payments	$	274,892	$	269,693	$	1,822


(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. 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.

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

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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, 2014, 2013 and 2012

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. 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.

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. During the years ended December 31, 2014 and 2013, 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.

Commodity Derivatives

Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:



	Economic Hedges
	December 31,
	2014			2013
	(In thousands)
PNM and PNMR
Current assets	$	11,232		$	4,064
Deferred charges	—			3,002
	11,232			7,066
Current liabilities	(1,209		)	(2,699		)
Long-term liabilities	(477		)	(1,094		)
	(1,686		)	(3,793		)
Net	$	9,546		$	3,273

Included in the above table are $3.0 million of current assets at December 31, 2014 and $3.0 million of current assets and $3.0 million of deferred charges at December 31, 2013 related to contracts, which were entered into in July 2013, for the sale of energy from PVNGS Unit 3 for 2014 and 2015 at market price plus a premium. 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 were immaterial at December 31, 2014 and 2013.

At December 31, 2014 and 2013, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. In addition, at December 31, 2014 and 2013, amounts posted as cash collateral under margin arrangements were $3.8 million and

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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, 2014, 2013 and 2012

$2.8 million for both PNMR and PNM. At December 31, 2014 and 2013, obligations to return cash collateral were $0.2 million and $0.2 million for both PNMR and PNM. 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 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.

The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.



	Economic Hedges
	Year Ended December 31,
	2014		2013		2012
	(In thousands)
PNMR and PNM
Electric operating revenues	$	4,491	$	1,727	$	6,168
Cost of energy	593		1,109		(460		)
Total gain	$	5,084	$	2,836	$	5,708

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, 2014
PNMR and PNM	650,000	(1,919,000	)
December 31, 2013
PNMR and PNM	905,000	(3,343,783	)

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.

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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, 2014, 2013 and 2012



Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
December 31, 2014
PNMR and PNM	$	1,686	$	—	$	167
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in 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, 2014, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2015, at market price plus a premium. Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of these sales.

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). The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table. At December 31, 2014 and 2013, the fair value of available-for-sale securities included $244.6 million and $222.5 million for the NDT and $5.5 million and $4.4 million for the mine reclamation trust.



	December 31, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	8,276	$	—	$	3,356
Equity securities:
Domestic value	17,418		45,340		14,523		39,460
Domestic growth	21,354		74,053		25,656		76,292
International and other	156		16,599		1,040		16,633
Fixed income securities:
U.S. Government	903		22,563		158		21,941
Municipals	5,851		68,973		1,018		58,568
Corporate and other	666		14,341		207		10,605
	$	46,348	$	250,145	$	42,602	$	226,855

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 . Gross realized losses shown below exclude the change in realized impairment losses of $(0.7) million, $0.6 million, and $5.2 million.

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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, 2014, 2013 and 2012



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Proceeds from sales	$	117,989		$	271,140		$	167,330
Gross realized gains	$	15,162		$	14,308		$	15,907
Gross realized (losses)	$	(3,964	)	$	(4,298	)	$	(8,170	)

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.

At December 31, 2014, 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	$	3,946	$	8,019	$	8,019
After 1 year through 5 years	20,275		25,430		24,817
After 5 years through 10 years	13,422		—		—
After 10 years through 15 years	10,367		—		—
After 15 years through 20 years	11,539		—		—
After 20 years	46,328		—		—
	$	105,877	$	33,449	$	32,836

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. 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, 2014 and 2013.

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 the Company’s 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 certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

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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, 2014, 2013 and 2012

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, 2014 and 2013 for items recorded at fair value.



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
December 31, 2014				(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276	$	—
Equity securities:
Domestic value	45,340			45,340		—
Domestic growth	74,053			74,053		—
International and other	16,599			16,599		—
Fixed income securities:
U.S. Government	22,563			20,808		1,755
Municipals	68,973			—		68,973
Corporate and other	14,341			4,843		9,498
	$	250,145		$	169,919	$	80,226

Commodity derivative assets	$	11,232		$	—	$	11,232
Commodity derivative liabilities	(1,686		)	—		(1,686		)
Net	$	9,546		$	—	$	9,546



				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

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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, 2014, 2013 and 2012

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt are presented below:



					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
December 31, 2014	(In thousands)
PNMR
Long-term debt	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	242	$	242	$	242	$	—	$	—

December 31, 2013
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	$	—	$	—

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 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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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, 2014			(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	588,112	$	123,668	$	398,819	$	65,625
TNMP Pension Plan
Participation in PNMR Master Trust Total Plan Investments	$	69,207	$	14,823	$	44,425	$	9,959
PNM OPEB Plan
Cash and cash equivalents	$	1,242	$	1,242	$	—	$	—
Equity securities:
International funds	10,332		—		10,332		—
Domestic value	8,365		8,365		—		—
Domestic growth	5,960		5,960		—		—
Other funds	30,997		—		30,997		—
Fixed income securities:
Mutual funds	22,122		22,122		—		—
	$	79,018	$	37,689	$	41,329	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	168	$	168	$	—	$	—
Equity securities:
International funds	1,277		—		1,277		—
Domestic value	403		403		—		—
Domestic growth	1,024		1,024		—		—
Other funds	3,790		—		3,790		—
Fixed income securities:
Mutual funds	3,549		3,549		—		—
	$	10,211	$	5,144	$	5,067	$	—

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012



			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	$	557,258	$	145,364	$	330,903	$	80,991
TNMP Pension Plan
Participation in PNMR Master Trust	$	66,285	$	18,657	$	32,620	$	15,008
PNM OPEB Plan
Cash and cash equivalents	$	1,152	$	1,152	$	—	$	—
Equity securities:
International funds	11,634		—		11,634		—
Domestic value	6,388		6,388		—		—
Domestic growth	24,135		7,094		17,041		—
Other funds	14,028		—		14,028		—
Fixed income securities:
Mutual funds	16,796		16,796		—		—
	$	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	4,171		1,848		2,323		—
Other funds	1,844		—		1,844		—
Fixed income securities:
Mutual funds	1,702		1,702		—		—
	$	9,734	$	4,233	$	5,501	$	—

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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, 2014	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	15,645	$	15,645	$	—	$	—
Equity securities:
International	23,282		—		23,282		—
Domestic value	41,778		41,778		—		—
Domestic growth	28,370		28,370		—		—
Other funds	29,719		—		29,719		—
Fixed income securities:
Corporate	242,742		—		242,015		727
U.S. Government	106,634		52,537		54,097		—
Municipals	20,156		—		20,156		—
Other funds	74,136		161		73,975		—
Alternative investments:
Private equity funds	37,220		—		—		37,220
Hedge funds	23,876		—		—		23,876
Real estate funds	13,761		—		—		13,761
	$	657,319	$	138,491	$	443,244	$	75,584
December 31, 2013
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

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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



	Year Ended December 31,
	2014			2013
Level 3 Fair Value Assets and Liabilities	(In thousands)
PNM Pension	Master Trust			Master Trust
Balance at beginning of period	$	80,991		$	79,017
Actual return on assets sold during the period	10,376			3,303
Actual return on assets still held at period end	(5,731		)	3,361
Purchases	8,832			15,110
Sales	(28,843		)	(19,800		)
Balance at end of period	65,625			80,991
TNMP Pension
Balance at beginning of period	$	15,008		$	14,171
Actual return on assets sold during the period	3,409			1,400
Actual return on assets still held at period end	(1,883		)	1,425
Purchases	2,902			6,408
Sales	(9,477		)	(8,396		)
Balance at end of period	9,959			15,008
Total	$	75,584		$	95,999

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, 2012	$	38,212		$	31,277		$	23,699		$	—		$	93,188
Actual return on assets sold during the period	4,677			135			(109		)	1			4,704
Actual return on assets still held at period end	1,162			3,500			123			—			4,785
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
Actual return on assets sold during the period	5,355			8,667			(236		)	—			13,786
Actual return on assets still held at period end	(296		)	(7,536		)	237			(20		)	(7,615		)
Purchases	3,656			5,500			1,971			608			11,735
Sales	(10,617		)	(17,667		)	(10,000		)	(37		)	(38,321		)
Balance at December 31, 2014	$	37,220		$	23,876		$	13,761		$	727		$	75,584

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012


(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, 2014, 2013, and 2012, PNM paid $19.1 million, $18.9 million, and $18.8 million for fixed charges and $1.2 million, $1.2 million, and $0.9 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets.

PNM 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,
	2014			2013			2012
	(In thousands)
Operating revenues	$	20,247		$	20,166		$	19,585
Operating expenses	(6,120		)	(5,645		)	(5,535		)
Earnings attributable to non-controlling interest	$	14,127		$	14,521		$	14,050



Financial Position
	December 31,
	2014		2013
	(In thousands)
Current assets	$	2,513	$	2,658
Net property, plant and equipment	72,321		75,137
Total assets	74,834		77,795
Current liabilities	1,288		766
Owners’ equity – non-controlling interest	$	73,546	$	77,029

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, 2014, 2013 and 2012

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 was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million, prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which process could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. PNM is discussing these issues with the owner of Valencia. PNM cannot predict whether or not it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM is leasing portions of its interests in Units 1 and 2 of PVNGS. 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 2 years beyond the termination of the original lease terms. The option periods on certain leases may be further extended for up to an additional 6 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 $20.3 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. Other than as discussed in Note 7, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Consolidated Balance Sheets related to the trusts other than accrued lease payments of $26.0 million at December 31, 2014 and 2013, which are included in other current liabilities on the Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including the notices, amendments, and agreements referred to above, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since 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 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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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

Rio Bravo, formerly known as Delta

PNM had a 20-year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM also controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was 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 owned Delta. FERC approved the purchase on February 26, 2013 and the NMPRC approved the purchase on June 26, 2013. Closing was subject to the seller remedying specified operational, NERC compliance, and environmental issues, as well as other customary closing conditions. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. At closing, PNM made a cash payment of $22.8 million, which reflected an adjustment for working capital compared to a targeted working capital and included amounts placed in escrow. Delta had project financing debt, amounting to $14.6 million at closing, which PNM retired. PNM changed the name of the facility to Rio Bravo.

PNM recorded the acquisition as a business combination and reflected the requirements of the FERC Uniform System of Accounts since the purchased assets are subject to traditional rate regulation by the NMPRC and FERC. Accordingly, as of the acquisition date, PNM recorded plant in service of $58.1 million and accumulated depreciation of $23.5 million, reflecting the original cost of the facilities and the estimated economic life to PNM. PNM also recorded current assets of $3.6 million, deferred charges of $3.4 million, current liabilities of $0.3 million, and non-current regulatory liabilities of $3.4 million.

PNM made fixed and variable payments to Delta under the PPA. For the period from January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $3.5 million and variable energy charges of $0.6 million under the PPA. For the years ended December 31, 2013 and 2012, PNM incurred fixed capacity charges of $6.4 million, and $6.2 million and variable energy charges of $1.8 million, and $0.8 million under the PPA. PNM recovered the variable energy charges through its FPPAC.

PNM began consolidating Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to the Consolidated Balance Sheets of PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Consolidated Statements of Earnings of PNMR and PNM would have been 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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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012


(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,
	2014		2013		2012
	(In thousands, except per share amounts)
Earnings Attributable to PNMR	$	116,254	$	100,507	$	105,547
Average Number of Common Shares:
Outstanding during year	79,654		79,654		79,654
Vested awards of restricted stock	134		191		145
Average Shares – Basic	79,788		79,845		79,799
Dilutive Effect of Common Stock Equivalents ⁽¹⁾:
Stock options and restricted stock	491		586		618
Average Shares – Diluted	80,279		80,431		80,417
Net Earnings Per Share of Common Stock:
Basic	$	1.46	$	1.26	$	1.32
Diluted	$	1.45	$	1.25	$	1.31
Dividends Declared per Common Share	$	0.755	$	0.680	0.580


⁽¹⁾	Excludes out-of-the-money options for 254,050 shares of common stock at December 31, 2014. See Note 13.


(11)	Income Taxes

PNMR

PNMR’s income taxes consist of the following components:



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Current federal income tax	$	(2,015	)	$	—		$	(1,296	)
Current state income tax	(728		)	(917		)	(37		)
Deferred federal income tax	59,814			50,044			51,559
Deferred state income tax	14,831			12,578			6,921
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Total income taxes	$	69,738		$	59,513		$	54,910

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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,
	2014			2013			2012
	(In thousands)
Federal income tax at statutory rates	$	70,226		$	61,274		$	61,262
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Flow-through of depreciation items	1,344			1,132			1,284
Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
State income tax, net of federal benefit	5,723			3,818			4,646
Impairment of state net operating loss carryforwards	3,129			—			—
Impairment of state production tax credits, net of federal benefit	894			3,880			718
Other	(4,469		)	(3,317		)	(5,845		)
Total income taxes	$	69,738		$	59,513		$	54,910
Effective tax rate	34.76		%	33.99		%	31.37		%

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



	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Net operating loss	$	153,858		$	134,418
Regulatory liabilities related to income taxes	78,858			83,838
Federal tax credit carryforwards	54,748			40,708
Other	68,566			75,832
Total deferred tax assets	356,030			334,796
Deferred tax liabilities:
Depreciation and plant related	(914,926		)	(814,671		)
Investment tax credit	(36,790		)	(25,855		)
Regulatory assets related to income taxes	(67,910		)	(66,352		)
CTC	(19,352		)	(22,262		)
Pension	(66,498		)	(58,780		)
Other	(115,282		)	(115,458		)
Total deferred tax liabilities	(1,220,758		)	(1,103,378		)
Net accumulated deferred income tax liabilities	(864,728		)	(768,582		)
Current accumulated deferred income tax (asset) liability	(26,383		)	(58,681		)
Non-current accumulated deferred income tax liability	$	(891,111	)	$	(827,263	)

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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, 2014, 2013 and 2012

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, 2014
	(In thousands)
Net change in deferred income tax liability per above table	$	96,146
Change in tax effects of income tax related regulatory assets and liabilities	(6,538		)
Tax effect of mark-to-market adjustments	(1,612		)
Tax effect of excess pension liability	3,993
Adjustment for uncertain income tax positions	(4,858		)
Reclassification of unrecognized tax benefits	(15,031		)
Other	381
Deferred income taxes	$	72,481

PNM

PNM’s income taxes consist of the following components:



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Current federal income tax	$	(2,175	)	$	(479	)	$	(12,951	)
Current state income tax	(979		)	(760		)	(1,815		)
Deferred federal income tax	45,890			42,806			56,194
Deferred state income tax	12,061			9,429			11,522
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Total income taxes	$	52,633		$	48,804		$	50,713

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,
	2014			2013			2012
	(In thousands)
Federal income tax at statutory rates	$	53,930		$	53,018		$	54,710
Amortization of accumulated investment tax credits	(2,164		)	(2,192		)	(2,237		)
Flow-through of depreciation items	1,325			1,115			1,268
Earnings attributable to non-controlling interest in Valencia	(4,945		)	(5,082		)	(4,918		)
State income tax, net of federal benefit	5,522			6,202			6,500
Impairment of state net operating loss carryforwards	2,145			—			—
Other	(3,180		)	(4,257		)	(4,610		)
Total income taxes	$	52,633		$	48,804		$	50,713
Effective tax rate	34.16		%	32.22		%	32.44		%

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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, 2014, 2013 and 2012

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



	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Net operating loss	$	108,505		$	99,247
Regulatory liabilities related to income taxes	74,293			78,849
Federal tax credit carryforwards	35,259			22,509
Other	35,681			37,008
Total deferred tax assets	253,738			237,613
Deferred tax liabilities:
Depreciation and plant related	(733,519		)	(661,239		)
Investment tax credit	(36,790		)	(25,855		)
Regulatory assets related to income taxes	(57,637		)	(55,844		)
Pension	(58,474		)	(52,104		)
Other	(70,714		)	(75,838		)
Total deferred tax liabilities	(957,134		)	(870,880		)
Net accumulated deferred income tax liabilities	(703,396		)	(633,267		)
Current accumulated deferred income tax (asset) liability	(12,418		)	(43,827		)
Non-current accumulated deferred income tax liability	$	(715,814	)	$	(677,094	)

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, 2014
	(In thousands)

Net change in deferred income tax liability per above table	$	70,129
Change in tax effects of income tax related regulatory assets and liabilities	(6,349		)
Tax effect of mark-to-market adjustments	(1,470		)
Tax effect of excess pension liability	3,993
Adjustment for uncertain income tax positions	1,155
Reclassification of unrecognized tax benefits	(12,228		)
Other	557
Deferred income taxes	$	55,787

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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, 2014, 2013 and 2012

TNMP

TNMP’s income taxes consist of the following components:



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Current federal income tax	$	35		$	(4,957	)	$	9,152
Current state income tax	1,939			1,916			1,822
Deferred federal income tax	20,577			20,688			4,406
Deferred state income tax	(28		)	(26		)	(28		)
Total income taxes	$	22,523		$	17,621		$	15,352

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,
	2014			2013			2012
	(In thousands)
Federal income tax at statutory rates	$	21,115		$	16,349		$	14,735
State income tax, net of federal benefit	1,257			1,247			1,185
Other	151			25			(568		)
Total income taxes	$	22,523		$	17,621		$	15,352
Effective tax rate	37.33		%	37.72		%	36.47		%

The components of TNMP’s net accumulated deferred income tax liability at December 31, were:



	December 31,
	2014			2013
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	4,565		$	4,988
Other	13,429			23,479
Total deferred tax assets	17,994			28,467
Deferred tax liabilities:
Depreciation and plant related	(174,510		)	(151,581		)
CTC	(19,352		)	(22,262		)
Regulatory assets related to income taxes	(10,197		)	(10,509		)
Loss on reacquired debt	(12,846		)	(13,516		)
Other	(12,636		)	(14,295		)
Total deferred tax liabilities	(229,541		)	(212,163		)
Net accumulated deferred income tax liabilities	(211,547		)	(183,696		)
Current accumulated deferred income tax (asset)	(6,398		)	(6,501		)
Non-current accumulated deferred income tax liability	$	(217,945	)	$	(190,197	)

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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, 2014, 2013 and 2012

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, 2014
	(In thousands)
Net change in deferred income tax liability per above table	$	27,851
Change in tax effects of income tax related regulatory assets and liabilities	(111		)
Adjustment for uncertain tax positions	(6,796		)
Other	(395		)
Deferred income taxes	$	20,549

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, 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		)
Settlement payments	—			—			—
Balance at December 31, 2012	19,198			10,382			6,796
Additions based on tax positions related to 2013	(54		)	(54		)	—
Additions for tax positions of prior years	745			745			—
Settlement payments	—			—			—
Balance at December 31, 2013	19,889			11,073			6,796
Additions based on tax positions related to 2014	623			623			—
Additions (reductions) for tax positions of prior years	(5,481		)	532			(6,796		)
Settlement payments	—			—			—
Balance at December 31, 2014	$	15,031		$	12,228		$	—

Included in the balance at December 31, 2014 are $4.7 million and $1.9 million of unrecognized tax benefits that, if recognized, would affect the effective tax rate for PNMR and PNM. The Company does not anticipate that any unrecognized tax expenses or unrecognized tax benefits will be reduced or settled in 2015.

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)
2014	$	146	$	148	$	(2	)
2013	$	242	$	251	$	(2	)
2012	$	243	$	244	$	(3	)

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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, 2014, 2013 and 2012

Accumulated accrued interest receivable (payable) related to income taxes is as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2014:
Accumulated accrued interest receivable	$	3,569		$	3,569		$	—
Accumulated accrued interest payable	$	(1,120	)	$	(24	)	$	(120	)
December 31, 2013:
Accumulated accrued interest receivable	$	4,048		$	4,048		$	—
Accumulated accrued interest payable	$	(1,118	)	$	(24	)	$	(118	)

The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2011 are closed to examination by either federal or state taxing authorities other than Arizona. The tax years prior to 2009 are closed to examination by Arizona taxing authorities. Other tax years are open to examination by federal and state taxing authorities. At December 31, 2014, the Company has $405.7 million of federal net operating loss carryforwards that expire beginning in 2030 and $54.7 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 2014. 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 for 2013, 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 was required to record 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 is being 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 during the period that includes the date of enactment, which was in the year ended December 31, 2013. At that time, 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. In addition, the portion of the adjustment that is not related to PNM's regulated activities was recorded in PNMR’s Corporate and Other segment 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. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the year ended December 31, 2014, PNM’s deferred tax liabilities were increased by $4.6 million, which reduced regulatory liabilities. Additionally, deferred tax assets not related to PNM’s regulatory activities were increased by $0.1 million, of which $0.2 million increased income tax expense in PNMR's Corporate and Other segment and $0.3 million decreased income tax expense in PNM.

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.

On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico for 2014 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits, which after federal income tax

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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, 2014, 2013 and 2012

benefit, amounted to $0.9 million. The impairment is reflected in PNMR’s Corporate and Other segment. Additionally, the act resulted in an impairment of New Mexico net operating loss carryforwards, which after federal income tax benefit, amounted to $3.1 million. Of this amount, $2.1 million is reflected in PNM and $1.0 million is reflected in PNMR’s Corporate and Other segment. In accordance with GAAP, these impairments were recorded as additional income tax expense during the year ended December 31, 2014. The impairment of the New Mexico net operating loss carryforward is reflected as a valuation allowance against deferred tax assets. No such impairments occurred in prior years. TNMP had no such impairment.

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, 2014, PNMR had a total valuation allowance for these credits of $5.5 million. During the years ended December 31, 2014, 2013, and 2012, the valuation allowance for these credits increased by $0.9 million, $3.9 million, and $0.7 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 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 due to PNMR’s net operating loss carryforward position.

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.

In 2013, the FASB issued Accounting Standards Update 2013-11, which requires entities to present liabilities for uncertain tax positions as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such carryforward could be used to offset those liabilities upon settlement. The Company adopted the change for 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, $11.2 million for PNM, and $6.8 million for TNMP, along with the elimination of the corresponding assets and liabilities associated with uncertain tax positions. There was no impact to earnings from adopting the update.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the year ended December 31, 2014. PNM recorded an income tax expense of $1.1 million, TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012


(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 (collectively, the “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 is 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 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 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.

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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, 2014, 2013 and 2012

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,
	2014			2013			2014			2013
	(In thousands)
PBO at beginning of year	$	599,537		$	675,549		$	66,159		$	76,640
Service cost	—			—			—			—
Interest cost	30,163			28,142			3,193			3,087
Plan amendment	—			(6,346		)	—			—
Actuarial (gain) loss	72,524			(56,533		)	8,466			(7,820		)
Benefits paid	(44,667		)	(41,275		)	(5,513		)	(5,748		)
PBO at end of year	657,557			599,537			72,305			66,159
Fair value of plan assets at beginning of year	556,353			518,095			66,118			66,540
Actual return on plan assets	76,223			19,533			8,572			4,326
Employer contributions	—			60,000			—			1,000
Benefits paid	(44,667		)	(41,275		)	(5,513		)	(5,748		)
Fair value of plan assets at end of year	587,909			556,353			69,177			66,118
Funded status – asset (liability) for pension benefits	$	(69,648	)	$	(43,184	)	$	(3,128	)	$	(41	)

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.

The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2014.



	PNM Plan						TNMP Plan
	December 31, 2014						December 31, 2014
	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	$	(2,665	)	$	139,256		$	—
Experience loss (gain)	—			34,345			4,420
Regulatory asset (liability) adjustment	—			(19,920		)	(4,420		)
Amortization recognized in net periodic benefit cost (income)	405			(5,469		)	—
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(2,260	)	$	148,212		$	—
Amortization expected to be recognized in 2015	$	(405	)	$	6,224		$	—

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

The following table presents the components of net periodic benefit cost (income):



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
PNM Plan
Service cost	$	—		$	—		$	—
Interest cost	30,163			28,142			32,232
Expected return on plan assets	(38,044		)	(41,930		)	(41,301		)
Amortization of net (gain) loss	13,020			14,840			10,516
Amortization of prior service cost	(965		)	76			317
Net periodic benefit cost	$	4,174		$	1,128		$	1,764
TNMP Plan
Service cost	$	—		$	—		$	—
Interest cost	3,193			3,087			3,635
Expected return on plan assets	(4,526		)	(4,849		)	(5,324		)
Amortization of net (gain) loss	665			1,049			462
Amortization of prior service cost	—			—			—
Net periodic benefit cost (income)	$	(668	)	$	(713	)	$	(1,227	)

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.



	Year Ended December 31,
PNM Plan	2014		2013		2012
Discount rate for determining December 31 PBO	4.48	%	5.27	%	4.30	%
Discount rate for determining net periodic benefit cost (income)	5.27	%	4.30	%	5.67	%
Expected return on plan assets	7.20	%	7.65	%	8.25	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.39	%	5.06	%	4.19	%
Discount rate for determining net periodic benefit cost (income)	5.06	%	4.19	%	5.69	%
Expected return on plan assets	7.20	%	7.65	%	8.25	%
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 an increase in the PNM PBO of $50.6 million at December 31, 2014 and a decrease of $60.9 million at December 31, 2013. Changes in discount rates resulted in an increase in the TNMP PBO of $5.1 million at December 31, 2014 and a decrease of $6.4 million at December 31, 2013. Changes in demographic experience resulted in actuarial losses in the PNM PBO of $0.2 million and $4.4 million at December 31, 2014 and 2013. Changes in demographic experience resulted in actuarial gains in the TNMP PBO of $0.4 million at December 31, 2014 and $1.4 million at December 31, 2013. Changes in other assumptions and experience resulted in actuarial gains in the PNM PBO of $0.2 million at December 31, 2014 and less than $0.1 million at December 31, 2013. Changes in other assumptions and experience resulted in actuarial losses in the TNMP PBO of $1.3 million and less than $0.1 million at December 31, 2014 and 2013. These changes are reflected as actuarial (gain) loss above.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

In late 2014, the Society of Actuaries issued revised mortality tables that include changes in assumptions to reflect increased life expectancy and the corresponding decrease in mortality rates. This change impacts the Company’s pension plans, as the mortality assumptions are used as the basis for stating the pension obligation in financial statements, determining funding requirements, and making minimum lump-sum calculations. The actuarial valuation performed as of December 31, 2014 incorporated the impacts of the revised mortality tables. Utilizing the revised mortality tables increased the PNM PBO by $21.9 million and the TNMP PBO by $2.5 million, which are reflected as the actuarial losses 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. 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 2015 net periodic cost to increase $5.8 million and $0.6 million (analogous changes would result from a 1% increase). The actual rate of return for the PNM and TNMP pension plans was 14.3% and 13.5% for the year ended December 31, 2014.

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.

The following pension benefit payments are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2015	$	53,472	$	5,997
2016	53,468		5,667
2017	51,241		5,351
2018	49,640		5,585
2019	48,560		5,188
2020 – 2024	213,759		23,600

Due to declines during the recent recession 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. In January 2015, the Company made a contribution of to the PNM pension plan of $30.0 million. The Company does not anticipate making any additional contributions to the pension plans in 2015. Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the pension plan trust for 2016-2019 are estimated to total $22.0 million for PNM and none for TNMP. These anticipated contributions were developed using current funding assumptions with discount rates of 4.8% 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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,
	2014			2013			2014			2013
	(In thousands)
APBO at beginning of year	$	92,165		$	99,613		$	12,266		$	13,678
Service cost	181			260			237			299
Interest cost	4,630			4,113			619			566
Participant contributions	2,582			2,537			366			373
Actuarial (gain) loss	4,455			(4,566		)	1,639			(1,080		)
Benefits paid	(8,838		)	(9,792		)	(1,057		)	(1,570		)
APBO at end of year	95,175			92,165			14,070			12,266
Fair value of plan assets at beginning of year	73,565			64,464			9,601			8,643
Actual return on plan assets	7,334			12,780			841			1,813
Employer contributions	3,532			3,576			343			342
Participant contributions	2,582			2,537			366			373
Benefits paid	(8,838		)	(9,792		)	(1,057		)	(1,570		)
Fair value of plan assets at end of year	78,175			73,565			10,094			9,601
Funded status – asset (liability)	$	(17,000	)	$	(18,600	)	$	(3,976	)	$	(2,665	)

In the year ended December 31, 2014, actuarial losses of $2.8 million and $1.3 million were recorded in regulatory assets for the PNM Plan and TNMP Plan. There were no prior service costs recorded for the year ended December 31, 2014.

The following table presents the components of net periodic benefit cost:



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
PNM Plan
Service cost	$	181		$	260		$	217
Interest cost	4,630			4,113			5,293
Expected return on plan assets	(5,638		)	(5,043		)	(4,901		)
Amortization of net (gain) loss	2,225			4,242			3,888
Amortization of prior service credit	(1,343		)	(1,343		)	(1,343		)
Net periodic benefit cost	$	55		$	2,229		$	3,154
TNMP Plan
Service cost	$	237		$	299		$	244
Interest cost	619			566			624
Expected return on plan assets	(534		)	(503		)	(516		)
Amortization of net (gain) loss	(122		)	—			(209		)
Amortization of prior service cost	32			57			57
Net periodic benefit cost	$	232		$	419		$	200

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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, 2014, 2013 and 2012

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	2014		2013		2012
Discount rate for determining December 31 APBO	4.45	%	5.21	%	4.26	%
Discount rate for determining net periodic benefit cost	5.21	%	4.26	%	5.70	%
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	4.45	%	5.21	%	4.26	%
Discount rate for determining net periodic benefit cost	5.21	%	4.26	%	5.70	%
Expected return on plan assets	6.50	%	6.50	%	6.50	%
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 an increase in the PNM APBO of $6.7 million at December 31, 2014 and a decrease of $8.8 million at December 31, 2013. Changes in discount rates resulted in an increase in the TNMP APBO of $1.1 million at December 31, 2014 and a decrease of $1.3 million at December 31, 2013. Changes in claims, contributions, medical trends, and demographic experience resulted in an actuarial gain in the PNM plan of $5.4 million at December 31, 2014 and an actuarial loss of $4.2 million at December 31, 2013. Changes in claims, contributions, and demographic experience resulted in actuarial losses in the TNMP plan of less than $0.1 million at December 31, 2014 and $0.2 million at December 31, 2013. These changes are reflected as actuarial (gain) loss above.

The actuarial valuation performed as of December 31, 2014 incorporated the impacts of the revised mortality tables discussed above. Utilizing the revised mortality tables increased the PNM APBO by $3.2 million and the TNMP APBO by $0.5 million, which are reflected as actuarial losses 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 APBO. Factors that are considered include, but are not limited to, historic returns on plan assets, current market information on long-term returns (e.g., long-term bond rates), and current and target asset allocations between asset categories. 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 2015 postretirement benefit cost to increase $0.7 million and $0.1 million (analogous changes would result from a 1% increase). The actual rate of return for the PNM and TNMP postretirement benefit plans was 10.2% and 8.9% for the year ended December 31, 2014.

The following table shows the assumed health care cost trend rates for the PNM postretirement benefit plan:



	PNM Plan
	December 31,
	2014		2013
Health care cost trend rate assumed for next year	7.0	%	7.5	%
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	2023		2019

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

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	$	350	$	(281	)
Effect on APBO	$	5,305	$	(4,622	)

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 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)
2015	$	6,560	$	801
2016	6,635		822
2017	6,718		838
2018	6,875		860
2019	6,950		882
2020 - 2024	34,585		4,717

PNM expects to make contributions to the PNM postretirement benefit plan totaling $3.5 million in 2015 and $14.0 million for 2016-2019. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.3 million in 2015 and $1.4 million for 2016-2019 .

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,
	2014			2013			2014			2013
	(In thousands)
PBO at beginning of year	$	16,363		$	17,467		$	823		$	902
Service cost	—			—			—			—
Interest cost	822			720			39			36
Actuarial (gain) loss	2,040			(330		)	110			(21		)
Benefits paid	(1,495		)	(1,494		)	(94		)	(94		)
PBO at end of year – funded status	17,730			16,363			878			823
Less current liability	1,528			1,536			94			94
Non-current liability	$	16,202		$	14,827		$	784		$	729

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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, 2014, 2013 and 2012

The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2014.



	December 31, 2014
	PNM Plan			TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	1,833		$	—
Experience loss (gain)	2,040			(110		)
Regulatory asset (liability) adjustment	(1,183		)	110
Amortization recognized in net periodic benefit cost (income)	(88		)	—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,602		$	—
Amortization expected to be recognized in 2015	$	136		$	—

The following table presents the components of net periodic benefit:



	Year Ended December 31,
	2014		2013		2012
	(In thousands)
PNM Plan
Service cost	$	—	$	—	$	—
Interest cost	822		720		876
Amortization of net (gain) loss	210		232		83
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	1,032	$	952	$	959
TNMP Plan
Service cost	$	—	$	—	$	—
Interest cost	39		36		45
Amortization of net (gain) loss	—		—		—
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	39	$	36	$	45

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	2014		2013		2012
Discount rate for determining December 31 PBO	4.48	%	5.27	%	4.30	%
Discount rate for determining net periodic benefit cost	5.27	%	4.30	%	5.67	%
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	4.39	%	5.06	%	4.19	%
Discount rate for determining net periodic benefit cost	5.06	%	4.19	%	5.69	%
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.

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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, 2014, 2013 and 2012

The following executive retirement plan payments, which reflect expected future service, are expected:



	PNM Plan		TNMP Plan
	(In thousands)
2015	$	1,528	$	93
2016	1,510		92
2017	1,490		91
2018	1,468		89
2019	1,445		86
2020 – 2024	6,722		384

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.

A summary of expenses for these other retirement plans is as follows:



	Year Ended December 31,
	2014		2013		2012
	(In thousands)
PNMR
401(k) plan	$	16,703	$	16,785	$	16,185
Non-qualified plan	$	2,257	$	2,204	$	1,491
PNM
401(k) plan	$	12,745	$	12,952	$	12,427
Non-qualified plan	$	1,722	$	1,691	$	1,143
TNMP
401(k) plan	$	3,958	$	3,953	$	3,739
Non-qualified plan	$	535	$	513	$	327


(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 have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets and some of these awards 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

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

PEP refers to awards of stock subject to vesting, performance, or market conditions rather than 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. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards. The total number of shares of PNMR common stock subject to all awards under the PEP, as approved by PNMR’s shareholders in May 2014, may not exceed 13.5 million shares, subject to adjustment and certain share counting rules set forth in the PEP. This current share pool is charged five shares for each share subject to restricted stock or other full value award. 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 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 meet their service requirements.

In June 2014, the FASB issued Accounting Standards Update 2014-12 – Compensation – Stock Compensation (Topic 718) Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period, which requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in estimating the grant date fair value of the award. The FASB issued ASU 2012-12 to eliminate diversity in practice. The Company currently treats the performance targets covered by the standard as performance conditions, so this ASU has no impact on the Company.

Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2014, 2013, and 2012 was $5.9 million, $5.3 million, and $3.6 million. Stock compensation expense of $4.2 million, $3.8 million, and $2.7 million was charged to PNM and $1.7 million, $1.5 million, and $1.0 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, 2014, PNMR had unrecognized compensation expense of $4.7 million related to restricted stock and performance-based shares and $1.8 million related to market-based shares, which are expected to be recognized over an average of 1.8 years.

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.

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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, 2014, 2013 and 2012

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	2014			2013			2012
Expected quarterly dividends per share	$	0.185		$	0.165		$	0.145
Risk-free interest rate	0.62		%	0.34		%	1.22		%

Market-Based Shares
Dividend yield	2.82		%	2.86		%	3.45		%
Expected volatility	25.11		%	25.11		%	43.98		%
Risk-free interest rate	0.64		%	0.36		%	1.04		%

The following table summarizes activity in restricted stock awards, including performance-based and market-based shares, and stock options:



	Restricted Stock				Stock Options
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted Average Exercise Price
Outstanding at December 31, 2013	315,305		$	17.87	1,343,666		$	20.63
Granted	242,164		$	21.27	—		$	—
Exercised	(295,423	)	$	16.70	(345,426	)	$	20.04
Forfeited	(3,276	)	$	22.46	(17,151	)	$	26.43
Expired	—		—		(60,584	)	$	27.98
Outstanding at December 31, 2014	258,770		$	22.31	920,505		$	20.39

Included as restricted stock granted and exercised above are 112,864 shares that were based upon achieving performance or market targets for 2013. The Board approved these shares 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 2011 through 2013 performance period.

As of December 31, 2014, PNMR’s stock-based compensation program provides for performance and market targets through 2016. Excluded from the above table are 179,845 shares approved by the Board in February 2015 (based upon achieving market targets, weighted at 60%, at target levels and performance targets, weighted at 40%, at maximum levels for the 2012 through 2014 performance period), as well as maximums of 179,811 and 163,152 shares for the three-year performance periods ending in 2015 and 2016 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 PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015. 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 this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

At December 31, 2014, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $8.9 million with a weighted-average remaining contract life of 2.83 years. At December 31, 2014, the exercise price of 254,050 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore 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,
Restricted Stock	2014		2013		2012
Weighted-average grant date fair value	$	21.27	$	20.03	$	16.75
Total fair value of restricted shares that vested (in thousands)	$	4,933	$	4,395	$	5,099

Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	625	$	1,054
Total intrinsic value of options exercised (in thousands)	$	2,473	$	2,721	$	6,356


(14)	Construction Program and Jointly-Owned Electric Generating Plants

PNM is a participant in several jointly-owned power plant projects. The primary operating or participation agreements for the joint projects expire in July 2016 for Four Corners, July 2022 for SJGS, December 2046 for Luna, and November 2047 for PVNGS.

PNM’s expenditures for additions to utility plant were $316.8 million in 2014, 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 $127.2 million during 2014. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $460.7 million in 2014.

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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014, 2013 and 2012

At December 31, 2014, 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)	$	1,009,378	$	(423,364	)	$	25,551		46.30	%
PVNGS (Nuclear) ⁽¹⁾	$	533,702	$	(152,273	)	$	42,334		10.20	%
Four Corners Units 4 and 5 (Coal)	$	162,111	$	(101,007	)	$	8,253		13.00	%
Luna (Gas)	$	66,169	$	(20,297	)	$	(136	)	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.

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. In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014. PNM cannot predict whether the 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 Samchully Power & Utilities 1, LLC. The operation and maintenance of the facility has been contracted to North American Energy Services.

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December 31, 2014, 2013 and 2012

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:



	2015		2016		2017		2018		2019		Total
					(In millions)
PNM	$	423.9	$	402.3	$	334.8	$	180.6	$	260.3	$	1,601.9
TNMP	121.3		92.8		93.3		105.9		105.0		518.3
Corporate and Other	24.0		19.3		15.4		13.7		14.7		87.1
Total PNMR	$	569.2	$	514.4	$	443.5	$	300.2	$	380.0	$	2,207.3


(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, 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
Liabilities incurred	—			—			—
Liabilities settled	—			—			—
Accretion expense	7,984			7,906			66
Revisions to estimated cash flows	51			51			—
Liability at December 31, 2014	$	104,170		$	103,182		$	848


⁽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 2013, a new decommissioning study for PVNGS

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December 31, 2014, 2013 and 2012

was implemented reflecting updated cash flow estimates, including the extended operating licenses. The new study resulted in an increase of $0.5 million to the ARO. 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 also is 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. Also, the Company is 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. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes 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. 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. Except as otherwise disclosed, 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, $4.9 million, and $2.6 million for the years ended December 31, 2014, 2013, and 2012 into the qualified and non-qualified trust funds. The estimated market value of the trusts at December 31, 2014 and 2013 was $244.6 million and $222.5 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. 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 alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the

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December 31, 2014, 2013 and 2012

settlement is $5.9 million, substantially all of which is credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 30, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. On October 31, 2014, APS submitted a $42.5 million claim for costs paid between July 1, 2011, and June 30, 2014. PNM’s share of the settlement would amount to $4.3 million, will be recorded when a final determination of the claim is made, which is anticipated to be in March 2015, and would primarily be credited back to PNM’s customers. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement.

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, 2014 and 2013, PNM had a liability for interim storage costs of $12.3 million and $11.9 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 and temporary storage rule (“Waste Confidence Decision”).

The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’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 Waste Confidence Decision update for further action consistent with NEPA.

On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision. The NRC commissioners also directed the staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012, decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals.

PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

In 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. 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 DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. In 2013, the one-mill fee for PNM’s share of the output from all three units at PVNGS amounted to $3.0 million. The fee applicable to PVNGS Units 1 and

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December 31, 2014, 2013 and 2012

2 is being recovered by PNM in its retail rates. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

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 required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

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. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. The parties file periodic status reports with the Tenth Circuit, but proceedings are being held in abeyance as agreed to by the parties.

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 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.

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. NMED developed a RSIP and submitted it to the EIB for approval in May 2013. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.

Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million. The costs for the project to install

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December 31, 2014, 2013 and 2012

SCRs would encompass installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.

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 BDT 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 above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would be about 46.3%.

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement contract.

NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:


•	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 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 and BDT 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 net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV 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. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 17. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately $268.4 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 would 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 SNCR and BDT equipment.

As discussed under SJGS Ownership Restructuring Matters below, the owners of SJGS are attempting to negotiate agreements concerning numerous matters, the resolution of which is necessary in order to facilitate the shutdown of SJGS Units 2 and 3 and comply with the RSIP. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time. In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements are memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by other intervenors.

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December 31, 2014, 2013 and 2012

Under the terms of the stipulation, PNM:


•	Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017


•	Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million


•	Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at December 31, 2014, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $282 million

•

Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at December 31, 2014, PNM’s net book value of PVNGS Unit 3 was approximately $144 million


•	Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million


•	Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA

A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:


•	PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below


•	PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval


•	PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015

PNM expects a decision from the NMPRC in the second quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

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. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

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The SJGS participants have engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions among the SJGS participants regarding restructuring have also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS, the resolution of which is necessary for continued operation of SJGS after December 31, 2017. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014. The Fuel and Capital Funding Agreement provides that the SJGS participants will return to the prior arrangement if a binding restructuring agreement is not reached.

On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of the unsubscribed MWs. However, a scenario is being evaluated in which PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS and mediated discussions regarding remaining issues have continued, including matters that were addressed in the Fuel and Capital Funding Agreement.

The participants continue to negotiate other definitive agreements that would formalize the matters contained in the Resolution, as amended. A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Any final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the impact of the above developments on negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained, but expects negotiations to proceed consistent with the time frames described in NMPRC Filing above.

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Other Developments and Current Status – 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 property common to more than one unit. 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 described below, to the SJGS 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. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014, $6.4 million on June 27, 2014, and total project expenses of $76.6 million (including the two prior requests) on January 22, 2015. The Unit 4 owners did not approve these requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA 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 must evaluate 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 take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014 and July 14, 2014, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3. Obtaining NMPRC approval will likely require that final binding agreements be reached among the SJGS owners on a revised ownership structure to facilitate the retirement of these two units. In turn, reaching agreement on ownership restructuring, will likely require that agreement be reached regarding the supply of coal for SJGS for periods after December 31, 2017. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

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 its share of 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.

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 had no ownership interest in Units 1, 2, and 3, which were shut down 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

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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.

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. In March 2014, APS received a draft of the EIS in connection with the DOI review process. On June 19, 2014, PNM submitted comments on the draft EIS as owner and operator of two electric transmission lines that are part of the connected action for the EIS. A final EIS is expected to be issued in March 2015. In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014. PNM cannot predict whether the 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 the Four Corners participants.

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 $80.0 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. On July 23, 2014, the Tenth Circuit issued a unanimous decision affirming EPA’s action and denying WEG’s petition for review. On September 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.

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. Oral argument was heard before the Tenth Circuit on March 20, 2014. On October 21, 2014, the Tenth Circuit denied the petitions for review and affirmed EPA’s actions. On December 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.

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. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which

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air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. 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 November 8, 2013, PNM received an amendment to its NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. The revised permit, requires the reduction of SO₂emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to require the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. It is anticipated that the equipment modifications 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. 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 60-70 parts per billion (“ppb”). On December 17, 2014, EPA published a proposed rule that would revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA is proposing a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA is proposing to set an 8-hour secondary standard at a level within the range of 65 to 70 ppb. According to EPA, 2011-2013 ozone ambient air monitoring data indicates that Bernalillo, Dona Ana, Eddy, and San Juan counties in New Mexico exceed a 70 ppb ozone concentration. In addition, Lea, Luna Santa Fe, and Valencia counties exceed the 65 ppb ozone concentration. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. 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 controls to meet a new ozone NAAQS. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation. EPA is under a court order to finalize the ozone standard by October 1, 2015.

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. 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 sought 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. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM was required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions monitoring system used in the initial study. The results of the mercury study will establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM completed stack testing and submitted the study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. NMED and the plaintiffs are evaluating the study and PNM’s recommendation. PNM cannot predict 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.

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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 parties have recently agreed on terms of a settlement. The terms of the settlement do not have a material impact on PNM. PNM recorded the impact of its share of the proposed settlement in 2014. A final consent decree has not yet been executed.

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 NEPA 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 a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. Legal briefing is complete and the matter is ready for a ruling from the court. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

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.

Cooling Water Intake Structures

EPA issued its final cooling water intake structures rule on May 19, 2013, which establishes 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 final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting “best technology available” standards for reducing impingement. To minimize entrainment mortality, the permitting authority must establish the “best technology available” for entrainment on a site-specific basis, taking into consideration an array of factors, including social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a

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schedule of compliance established by the permitting authority. The renewal date for the SJGS NPDES permit is March 31, 2016; however, additional time to submit the application may be allowed by the NPDES permit writer. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material. 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 wastewater 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 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. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions. 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 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 conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property. This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels. Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation. PNM is unable to predict the outcome of these matters.

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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 included two options for waste designation of coal ash. One option was 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 was 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 is developing a proposed rule governing the placement of CCBs at coal mining and reclamation operations.

On January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, and industry group members, the court issued 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.

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non- compliance with the new requirements.

PNM is reviewing the rule to fully understand its implications. The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCR rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows.

Sierra Club Consent Decree

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 included 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.

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December 31, 2014, 2013 and 2012

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 must comply with the MATS rule by April 16, 2015, unless the facility has been granted a 1-year extension under CAA section 112(i)(3). PNM has not requested an extension and will begin complying with the MATS rule by the date specified in the 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. 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 requested and received a 1-year extension until April 16, 2016 for Four Corners to comply with the MATS rule. However, 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, 2014 and 2013, prepayments for coal, which are included in other current assets, amounted to $37.3 million and $12.3 million. 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.

PNM and the other owners of SJGS are evaluating alternatives for the supply of coal after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants will need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants are in the process of negotiating agreements concerning future fuel supply for SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the coal sales agreement. The parties to the coal sales agreement and the amendment are SJCC, PNM, and Tucson. The amendment provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. The amendment, which was effective as of October 2, 2014, also released the parties from the obligation to negotiate an extension of the coal sales agreement, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed. On February 12, 2015, the SJGS Coordination Committee approved a resolution authorizing the modification of the amendment to extend the date for negotiation of a transaction until May 1, 2015 and to allow for a direct sale of the SJCC mining operations by BHP to a third-party mining company. PNM anticipates that in connection with a consummated purchase transaction, the third-party mining company would enter into an agreement to supply coal to SJGS. The parties to the amendment also entered into an agreement in October 2014 providing the SJGS participants with access to data necessary to evaluate the mine assets and liabilities. This agreement has terminated and was not renewed in order to allow the parties to focus on the direct sales process. Currently, PNM cannot predict the outcome of these negotiations or if a transaction will be consummated.

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had 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. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

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December 31, 2014, 2013 and 2012

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 current 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 2014 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $57.3 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, 2014. At December 31, 2014 and 2013, liabilities, in current dollars, of $25.7 million and $23.8 million for surface mine reclamation and $8.6 million and $7.8 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 $1.0 million in 2014, $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 (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, which was performed in 2013, 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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. How costs would be divided among the owners of SJGS has not been finalized. Regulatory determinations made by the NMPRC may also affect the impact on PNM. 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 completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembled it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. Coal inventories have been restored to pre-incident levels and SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal operations.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM included the portion of such costs allocable to its customers subject to New Mexico regulation in its FPPAC. 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 informed PNM that it settled with its insurance carrier. PNM’s portion of the insurance recovery is $18.7 million. PNM has credited its FPPAC balancing account for the insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 17.

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December 31, 2014, 2013 and 2012

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. There is no legal deadline for adoption of the final 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 were submitted to a panel for binding arbitration. The issues were: 1) whether the SJGS participants owed SJCC unbilled mining costs of $5.2 million or whether SJCC owed 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 were not billable under the mining contract. PNM’s share of amounts subject to the arbitration was approximately 46.3%. A hearing before the arbitration panel on the remaining issues was held in May 2014. The arbitration panel found in favor of SJCC on both issues. Of PNM’s share of the costs, approximately 33% of the first issue was passed through PNM’s FPPAC and the rest impacted earnings in 2014. The amounts related to the second issue were recorded when billed in prior periods and had no impact in 2014.

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 9.4%, 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. 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 cannot predict the timing or outcome of this litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

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 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 retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.7 million.

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December 31, 2014, 2013 and 2012

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, 2014, a sublimit of $2.25 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 premium assessments of $4.8 million for each retrospective premium 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, Rio Bravo, 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 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 has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

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December 31, 2014, 2013 and 2012

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.

Rights-of-Way Matter

On January 28, 2014, 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. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment of one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to the ordinance are 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 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

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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. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

In a separate matter, in September 2012, 43 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. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allotees’ appeal was dismissed with prejudice concluding this matter. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested. The letter indicated that the renewals were not processed because the necessary consent was not met. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. PNM is in the process of investigating the validity of this notice of revocation and its potential impact in light of the BIA’s position and the recent dismissal with prejudice of the appeal, and is therefore unable at this time to predict the likely outcome of this matter.


(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

2014 Electric Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future year test period. The application proposes a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE is 10.5%. The requested base rate increase, combined with other rate changes, represent an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, is related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs is a contributing factor to the decline in PNM’s energy sales since the last rate case and accounts for the balance of the rate increase after accounting for offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals include increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing photovoltaic systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. A public hearing on the rate case is expected to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015.

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.” The current diversity requirements are 30% wind, 20% solar, 5% other, and 1.5% distributed generation, increasing to 3% in 2015, subject to the limitation of the RCT.

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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. Currently, the RCT is set at 3% of customers’ annual electric charges.

PNM’s renewable energy procurement plan for 2012 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. 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 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 enabled 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 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 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 generator 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 filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 16). On September 25, 2014, a stipulated settlement was filed by PNM, staff of the NMPRC, the NMAG, NMIEC, Coalition for Clean Affordable Energy, and Western Resource Advocates. The stipulation proposed approval of PNM’s procurement proposals; however, the costs for the 40 MW of solar would be included in base rates to be set in PNM’s next general rate case rather than through PNM’s renewable energy rider. Under the agreement, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. A public hearing on the stipulation was held on October 27, 2014. On November 26, 2014, the NMPRC issued an order approving the stipulation with a modification that revised the not-to-exceed price from $4.25 per MWh to $3.00 per MWh for any additional necessary procurements to meet the RPS requirement in 2013 or 2014. In December 2014, PNM procured an additional 44,000 MWh of renewable resources to meet the 2013 RPS requirement at an average cost of $1.75 per MWh.

PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next general rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. On April 1, 2014, PNM made a filing with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013. Preliminary calculations indicate PNM’s jurisdictional equity return did not exceed 10.5% in 2014.

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December 31, 2014, 2013 and 2012

PNM recorded revenues from the rider of $34.3 million, $23.7 million, and $6.4 million in 2014, 2013, and 2012. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015.

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 October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. If approved, the stipulation would establish program budgets and incentive amounts, assuming a threshold level of energy savings are achieved, for 2015 and 2016. Two parties filed statements in opposition to the stipulation. A public hearing on the stipulation was held in February 2015.

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 November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million.

In June 2011, the NMPRC approved PNM-specific incentives for savings. PNM collected approximately $1.3 million, on an annual basis, in incentive revenues through November 2013 consistent with this order. 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. In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved. A public hearing was held in February 2015. The NMPRC has not yet acted upon PNM’s application.

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.

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December 31, 2014, 2013 and 2012

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 utility’s WACC times its approved annual program costs. The NMPRC received comments and a public hearing was held on November 20, 2013. The NMPRC issued an order on October 8, 2014, adopting the proposed rule.

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 to resolve this case. On April 23, 2014, the NMPRC approved the stipulation. The settlement allows PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, resolves all costs related to the mine fire incident discussed in Note 16, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, required PNM to write-off $10.5 million of the under-collected balance in its FPPAC balancing account, and required 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 the fourth quarter of 2013.

The NMPRC approval of the amended stipulation in PNM’s 2010 Electric Rate Case limited the amount that could be recovered on an annual basis for fuel costs during certain years. Costs in excess of the limits were deferred, without carrying costs, for recovery in future periods. The fuel cost caps were $38.8 million for the FPPAC year beginning July 1, 2012 and $36.2 million for the FPPAC year beginning July 1, 2013. The fuel cost caps ended on June 30, 2014. The resulting under-recovery as of April 30, 2014 was $63.5 million. Consistent with the order approved in PNM’s FPPAC Continuation Application, PNM is recovering this under-collection, net of the write-off agreed to in the settlement, over an 18 month period beginning July 1, 2014.

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. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 16) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation is set forth in Note 16. A public hearing in the NMPRC case was held in January 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.

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December 31, 2014, 2013 and 2012

Four Corners Right of First Refusal

On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM intends to inform the NMPRC about receipt of the notice and advise the NMPRC that PNM does not intend to exercise its rights under the ROFR. If not exercised, the ROFR will expire 120 days from the date of the notice.

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. 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 (“ROE”), 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 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 apply to all of PNM’s wholesale electric transmission service 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. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. The parties have engaged in settlement negotiations and PNM anticipates that a settlement will be filed with FERC in the near future. There is no required time frame for FERC to act upon a settlement. PNM is unable to predict the outcome of this proceeding.

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December 31, 2014, 2013 and 2012

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 and an extension of the contract for 10 years through December 31, 2035. On April 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 provided 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.

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014 and totaled $11.7 million during 2013. PNM’s 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 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 requested comments and held a public meeting on 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 through an initial fee and ongoing monthly charge. All transmission and distribution utilities in ERCOT were 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 sought recovery of $0.2 million through proposed initial fees ranging from $142.84 to $247.48 and an additional $0.5 million in annual ongoing expenses via a proposed monthly charge of $38.99. On June 20, 2014, the PUCT approved a settlement among the parties permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard

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December 31, 2014, 2013 and 2012

metering. As of February 20, 2015, 89 customers have made the election. TNMP does not expect the implementation of non-standard metering service 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 various appeals, the ERCOT transmission rates approved for the fourth quarter of 1999 and 2000 were remanded back to the PUCT. In October 2011, TNMP joined in a non-unanimous settlement relating to resettlement of the fourth quarter of 1999. In January 2012, the PUCT approved the non-unanimous settlement awarding TNMP $1.6 million. 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 must be credited against the costs TNMP requested in its TCRF. After further discussion, PUCT staff agreed that no credit was required since TNMP had not recovered those costs in 1999. The PUCT staff agreed to interim rate relief permitting TNMP to add $1.6 million in uncontested costs to its existing TCRF. TNMP implemented the interim rates on September 1, 2012. On November 19, 2012, the PUCT ordered that the $1.6 million in interim rates were final and authorized TNMP to institute a surcharge in March 2013 to collect the additional $1.6 million in initially disputed costs plus interest.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). 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 permitted TNMP to collect an aggregate of $5.2 million effective January 1, 2013. On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014 permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP recorded the $1.5 million incentive bonus for 2013 upon approval by the PUCT.

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. The following sets forth TNMP’s most recent interim transmission cost rate increases:



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 27, 2012	$	26.4	$	2.5
March 20, 2013	21.9		2.9
September 17, 2013	18.1		2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2

In January 2015, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $27.1 million, which would increase revenues by $4.4 million annually. The application is pending before the PUCT.

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December 31, 2014, 2013 and 2012

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.


(18)	Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. 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.

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,
	2014		2013		2012
			(In thousands)
Services billings:
PNMR to PNM	$	86,871	$	92,597	$	99,986
PNMR to TNMP	28,349		28,937		29,110
PNM to TNMP	524		562		595
TNMP to PNMR	31		7		15
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	65		4		1
TNMP to PNMR	309		481		137

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December 31, 2014, 2013 and 2012


(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, 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		)
Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			558			(8,152		)
Income tax impact of amounts reclassified	5,461			(2,032		)	(195		)	3,234
Other OCI changes (pre-tax)	17,473			(15,282		)	(153		)	2,038
Income tax impact of other OCI changes	(6,812		)	6,024			53			(735		)
Net change after income taxes	2,260			(6,138		)	263			(3,615		)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—		$	(61,755	)

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December 31, 2014, 2013 and 2012



	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, 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		)
Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			—		(8,710		)
Income tax impact of amounts reclassified	5,461			(2,032		)	—		3,429
Other OCI changes (pre-tax)	17,473			(15,282		)	—		2,191
Income tax impact of other OCI changes	(6,812		)	6,024			—		(788		)
Net change after income taxes	2,260			(6,138		)	—		(3,878		)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	—	$	(61,755	)

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December 31, 2014, 2013 and 2012



	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, 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		)
Amounts reclassified from AOCI (pre-tax)	—		—		558			558
Income tax impact of amounts reclassified	—		—		(195		)	(195		)
Other OCI changes (pre-tax)	—		—		(153		)	(153		)
Income tax impact of other OCI changes	—		—		53			53
Net change after income taxes	—		—		263			263
Balance at December 31, 2014	$	—	$	—	$	—		$	—

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 years ended December 31, 2014 and 2013, approximately 24.4% and 18.7% of the amount reclassified were capitalized into construction work in process and approximately 2.0% and 3.0% were 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) Goodwill; Impairments

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 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.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. The Company evaluates goodwill impairment as of April 1st of each year. PNMR’s 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,

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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, 2014, 2013 and 2012

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. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in determining 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 two, an impairment loss would be reflected in results of operations.

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 evaluations performed as of April 1, 2014 and 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit.

For the PNM reporting unit, a discounted cash flow methodology was primarily used in 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, 2014 and 2013 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 30% and 27%. 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 23% and 20% at April 1, 2014 and 2013. The 2014 and 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. The annual evaluations performed as of April 1, 2014 and 2013 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 2014 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, First Choice, a PNMR reporting unit that was sold in 2011, was significantly impacted by depressed economic conditions and changes in the market in which it operated. As a result, goodwill impairments of $51.1 million for PNM, $34.5 million for TNMP, and an aggregate of $174.4 million for PNMR were 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. 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.

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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, 2014, 2013 and 2012

(21) Quarterly Operating Results (Unaudited)

Unaudited operating results by quarters for 2014 and 2013 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.



	Quarter Ended
	March 31		June 30		September 30		December 31
	(In thousands, except per share amounts)
PNMR
2014
Operating revenues	$	328,897	$	346,160	$	413,951	$	346,845
Operating income	48,753		71,296		116,799		62,849
Net earnings	16,131		33,181		59,486		22,111
Net earnings attributable to PNMR	12,468		29,141		55,653		18,992
Net Earnings Attributable to PNMR per Common Share:
Basic	0.16		0.37		0.70		0.24
Diluted	0.16		0.36		0.69		0.24
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
PNM
2014
Operating revenues	$	262,736	$	275,704	$	334,993	$	274,481
Operating income	31,304		49,806		90,615		40,988
Net earnings	11,205		24,254		49,052		16,942
Net earnings attributable to PNM	7,674		20,346		45,351		13,955
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
TNMP
2014
Operating revenues	$	66,161	$	70,456	$	78,958	$	72,364
Operating income	17,262		21,265		25,873		21,188
Net earnings	6,803		9,534		12,355		9,115
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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

PNM Resources, Inc:

We have reported separately herein on the consolidated balance sheets of PNM Resources, Inc and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. In connection with our audits 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 audits.

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 27, 2015

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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 reported separately herein on the consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. In connection with our audits 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 audits.

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 27, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder

Texas-New Mexico Power Company:

We have audited and reported separately herein on the consolidated balance sheets of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of earnings, consolidated statements of comprehensive income, consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the two-year period ended December 31, 2014. In connection with our audits 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 audits.

/s/ KPMG LLP

Albuquerque, New Mexico

February 27, 2015

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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") for the year ended December 31, 2012, and have issued our report thereon dated March 1, 2013; such consolidated financial statements and report are included elsewhere in this Form 10-K. Our audit also included the consolidated financial statement schedules for the year ended December 31, 2012 of the Company listed in Item 15. These consolidated financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audit. In our opinion, such consolidated financial statement 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") for the year 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 for the year ended December 31, 2012 of the Companies listed in Item 15 . These consolidated financial statement schedules are the responsibility of the Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth 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,
	2014			2013			2012
	(In thousands)
Operating Revenues	$	—		$	—		$	—
Operating Expenses	650			941			3,287
Operating income (loss)	(650		)	(941		)	(3,287		)
Other Income and Deductions:
Equity in earnings of subsidiaries	124,543			116,634			117,900
Other income	622			769			670
Other deductions	(13,650		)	(22,825		)	(20,904		)
Net other income (deductions)	111,515			94,578			97,666
Earnings Before Income Taxes	110,865			93,637			94,379
Income Tax Expense (Benefit)	(5,389		)	(6,870		)	(11,168		)
Net Earnings	$	116,254		$	100,507		$	105,547

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2014			2013			2012
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	116,254		$	100,507		$	105,547
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	680			4,192			5,000
Deferred income tax expense	(69,442		)	(51,820		)	(46,632		)
Equity in (earnings) of subsidiaries	(124,543		)	(116,634		)	(117,900		)
Loss on reacquired debt	—			3,253			—
Stock based compensation expense	5,931			5,320			3,585
Changes in certain assets and liabilities:
Other current assets	22,955			28,460			(43,638		)
Other assets	51,644			46,558			34,096
Accounts payable	(88		)	620			8
Accrued interest and taxes	(7,683		)	(9,266		)	(28,855		)
Other current liabilities	(1,668		)	(146		)	3,876
Other liabilities	28,704			(27,756		)	(29,601		)
Net cash flows from operating activities	22,744			(16,712		)	(114,514		)
Cash Flows From Investing Activities:
Utility plant additions	(474		)	(960		)	(7,524		)
Investments in subsidiaries	—			(13,800		)	—
Cash dividends from subsidiaries	46,599			158,772			61,406
Net cash flows from investing activities	46,125			144,012			53,882
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	600			(37,600		)	120,900
Repayment of long-term debt	—			(29,468		)	(2,387		)
Proceeds from stock option exercise	6,999			4,618			11,684
Purchases to satisfy awards of common stock	(17,319		)	(13,807		)	(25,168		)
Dividends paid	(58,940		)	(50,980		)	(44,609		)
Other, net	81			—			—
Net cash flows from financing activities	(68,579		)	(127,237		)	60,420
Change in Cash and Cash Equivalents	290			63			(212		)
Cash and Cash Equivalents at Beginning of Period	92			29			241
Cash and Cash Equivalents at End of Period	$	382		$	92		$	29
Supplemental Cash Flow Disclosures:
Interest paid	$	12,152		$	14,510		$	15,007
Income taxes paid (refunded), net	$	(2,014	)	$	22,378		$	1,501

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

BALANCE SHEETS



	December 31,
	2014			2013
	(In thousands)
Assets
Cash and cash equivalents	$	382		$	92
Intercompany receivables	107,619			136,387
Income taxes receivable	29			14,989
Other, net	8,115			8,544
Total current assets	116,145			160,012
Property, plant and equipment, net of accumulated depreciation of $10,251 and $9,167	27,076			26,601
Investment in subsidiaries	1,757,650			1,683,321
Other long-term assets	70,939			53,892
Total long-term assets	1,855,665			1,763,814
	$	1,971,810		$	1,923,826
Liabilities and Stockholders’ Equity
Short-term debt	$	100,600		$	100,000
Short-term debt-affiliate	8,819			8,819
Current maturities of long-term debt	118,766			—
Accrued interest and taxes	2,816			2,797
Other current liabilities	16,320			16,876
Total current liabilities	247,321			128,492
Long-term debt	—			118,766
Other long-term liabilities	2,943			2,999
Total liabilities	250,264			250,257
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,173,845			1,178,369
Accumulated other comprehensive income (loss), net of tax	(61,755		)	(58,140		)
Retained earnings	609,456			553,340
Total common stockholders’ equity	1,721,546			1,673,569
	$	1,971,810		$	1,923,826

See Notes 6, 7, 14, 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:
2012	$	1,778	$	3,367	$	—	$	3,394	$	1,751
2013	$	1,751	$	2,849	$	—	$	3,177	$	1,423
2014	$	1,423	$	3,267	$	—	$	3,224	$	1,466

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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:
2012	$	1,778	$	3,384	$	—	$	3,411	$	1,751
2013	$	1,751	$	2,864	$	—	$	3,192	$	1,423
2014	$	1,423	$	3,275	$	—	$	3,232	$	1,466

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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:
2012	$	—	$	(17	)	$	—	$	(17	)	$	—
2013	$	—	$	(15	)	$	—	$	(15	)	$	—
2014	$	—	$	(8	)	$	—	$	(8	)	$	—

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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, 2014 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, 2014 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, 2014 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, 2014 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

On February 26, 2015, the Board approved an amendment to PNMR’s bylaws effective February 26, 2015. The amendment revised one of the qualifications for director candidates set forth in Article II, Section 9(f) of PNMR’s bylaws by deleting the requirement that candidates have an equity ownership interest in PNMR before commencing service on the Board. The bylaws retain the requirement that each director have an equity ownership in PNMR consistent with the approved director stock ownership guidelines. Disclosure of PNMR’s bylaw amendment is being made under this Item 9B of Form 10-K in lieu of Item 5.03(a) of Form 8-K.

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 12, 2015 (the “2015 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 2015 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 June 3, 2014.


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 2015 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 2015 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 2015 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 2015 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2015 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 2014, 2013, and 2012 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

3.4	PNMR	Bylaws of PNM Resources, Inc. with all amendments through February 26, 2015

10.1.1**	PNMR	2015 Director Compensation Summary

10.1.2**	PNMR	PNM Resources, Inc. Executive Savings Plan II, amended and restated effective as of January 1, 2015, executed as of December 29, 2014

10.2**	PNM	Employee Retention Agreement executed December 9, 2014 between PNM Resources, Inc. and Charles N. Eldred

10.3	PNM	Extension of LOI Deadline Under Amendment No. Six to Underground Coal Sales Agreement among SJCC, PNM and Tucson dated February 20, 2015

10.4.1**	PNMR	Acknowledgment Form for officer performance share awards granted under the Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009, as amended

10.4.2**	PNMR	Acknowledgment Form for officer restricted stock rights awards granted under the PNM Resources, Inc. 2014 Performance Equity Plan dated May 15, 2014

10.4.3**	PNMR	Acknowledgment Form for director restricted stock rights awards granted under the PNM Resources, Inc. 2014 Performance Equity Plan dated May 15, 2014

10.4.4**	PNMR	Employee Retention Agreement executed December 9, 2014 between PNMR Services Company and Thomas G. Sategna

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

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101.INS	PNMR	XBRL Instance Document

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:

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 February 26, 2015	3.4 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014	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

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PNM
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

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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

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 3, 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

4.31	Sixth Supplemental Indenture dated as of June 27, 2014 between TNMP and Union Bank, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed June 27, 2014	2-97230 TNMP

Material Contracts
10.5	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

10.6	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

10.7	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

10.8	Third Amendment to Credit Agreement dated December 17, 2014 among PNMR, the lenders party thereto and Wells Fargo Bank, National Association, as Administrative Agent	10.1 to the Company’s Current Report on Form 8-K filed December 17, 2014	1-32462 PNMR

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10.9	Second Amended and Restated Term Loan Agreement dated as of December 22, 2014 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 Current Report on Form 10-K December 22, 2014	1-32462 PNMR

10.10	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

10.11	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

10.12	Second Amendment to Credit Agreement executed December 17, 2014 and fully effective as of January 22, 2015	10.2 to the Company’s Current Report on Form 8-K filed December 17, 2014	1-6986 PNM

10.13	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



10.14	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

10.15		Term Loan Agreement dated as of December 22, 2014 between PNM and JPMorgan Chase Bank, as lender and administrative agent		10.2 to PNM’s Current Report on Form 8-K filed December 22, 2014		1-6987 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. 2014 Performance Equity Plan dated May 15, 2014		4.3 to PNMR’s Form S-8 Registration Statement filed May 15, 2014	333-195974 PNMR

10.20**		PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009		4.1 to PNM Resources’ Form S-8 Registration Statement filed May 20, 2009		333-159361 PNMR

10.21**		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

10.22**		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

10.23**		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

10.24**		PNM Resources, Inc. 2014 Officer Annual Incentive Plan dated March 20, 2014		10.1 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014		1-32462 PNMR

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10.25**	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

10.26**	PNM Resources, Inc. 2014 Long-Term Incentive Plan dated March 20, 2014	10.2 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014	1-32464 PNMR

10.27**	PNM Resources, Inc. 2013 Long-Term Incentive Plan dated March 29, 2013	10.2 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013	1-32462 PNMR

10.28**	PNM Resources, Inc. 2012 Long-Term Incentive Plan dated March 28, 2012	10.2 to the Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.29**	Acknowledgment Form for officer performance share awards granted under Second Amended Restated Omnibus Performance Equity Plan dated May 19, 2009, as amended	10.4.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.30**	Form of Stock Option Award Agreement for non-qualified stock options granted under performance equity plan in 2010	10.3 to PNMR’s Current Report on Form 8-K filed May 26, 2009	1-32462 PNMR

10.31**	Form of the award agreement for non- qualified stock options granted under performance equity plan in 2007-2009	10.2 to the Company’s Current Report on Form 8-K filed February 16, 2007	1-32462 PNMR

10.32**	Acknowledgement Forms for restricted stock rights 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

10.33**	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

10.34*	Employee Retention Agreement executed December 9, 2014 between PNMR and Charles N. Eldred	10.2 to PNMR’s Annual Report on For 10-K for the year ended December 31, 2014	1-32462 PNMR

10.35**	Acknowledgement Form for officer restricted stock rights awards granted under the PNM Resources, Inc. 2014 Performance Equity Plan dated May 15, 2014	10.4.2 to PNMR’s Annual Report on For 10-K for the year ended December 31, 2014	1-32462 PNMR

10.36**	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

10.37**	2015 Director Compensation Summary	10.1.1 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.38**	Acknowledgement Forms for restricted stock rights and stock option awards granted to directors under the Second Amended and Restated Omnibus Performance Equity Plan dated May 19, 2009, as amended	10.3 to the Company’s Current Report on Form 8-K filed March 1, 2011	1-32462 PNMR

10.39**	Acknowledgment Form with attached Terms and Conditions for restricted stock rights awards granted to directors under the PNM Resources, Inc. 2014 Performance Equity Plan dated May 15, 2014	10.4.3 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.40**	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	1-32462 PNMR

10.41**	PNM Resources, Inc. Executive Savings Plan II (amended and restated effective January 1, 2015)	10.1.2 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

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10.42**	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

10.43**	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

10.44**	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

10.45**	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

10.46**	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

10.47**	PNM Resources, Inc. Annual Executive Physical Exam Program Wraparound Plan Document effective as of January 1, 2014	10.7 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013	1-32462 PNMR

10.48**	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

10.49**	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

10.50**	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

10.51**	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

10.52**	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

10.53**	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

10.54**	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

10.55**	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

10.56**	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

10.57**	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

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10.58**	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

10.59**	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

10.60**	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

10.61	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

10.62	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

10.63	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

10.64	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

10.65	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

10.66	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

10.67	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

10.68	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

10.69	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

10.70	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

10.71	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

10.72	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

10.73	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

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10.74	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

10.75	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

1076	Amendment No. 16, effective as of April 28, 2014, to the Arizona Nuclear Power Project Participation Agreement	10.3 to PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014	1-6986 PNM

10.77	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

10.78	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

10.79	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

10.80	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

10.81	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

10.82	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

10.83	Amendment No. Six to Underground Coal Sales Agreement executed October 2, 2014 among San Juan Coal Company, PNM and Tucson Electric Power Company and acknowledged by San Juan Transportation Company	10.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014	1-6986 PNM

10.83.1	Extension of LOI Deadline Under Amendment No. Six to Underground Coal Sales Agreement among SJCC, PNM and Tucson dated February 20, 2015	10.3 to the Company’s Annual Report on Form 10-K for the year ended December, 31 2014	1-6986 PNM

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10.84	San Juan Generation Station Fuel and Capital Funding Agreement dated September 12, 2014 among PNM, 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 Systems, and Tri-State Generation and Transmission Association, Inc.	10.2 to PNM’s Quarter Report on Form 10-Q for the quarter ended September 30, 2014	1-6986 PNM

10.85	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

10.86	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

10.87	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

10.88*	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

10.89*	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


10.90	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

10.91*	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

10.92	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

10.93	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

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10.94	Amendment No. 2 dated as of March 18, 2014, to the Facility Lease dated December 15, 1986, as heretofore amended, between U.S. Bank National Association, not in its individual capacity, but solely as Owner Trustee under a Trust Agreement ,dated as of December 15, 1986, with PV2-PNM December 35 Corporation, Lessor, and PNM, Lessee	10.1 to PNM’s Current Report on Form 8-K filed March 18, 2014	1-6986 PNM

10.95	Letter Agreement dated February 25, 2014, between Public Service Company of New Mexico and CGI Capital, Inc.	10.1 to PNM’s Current Report on Form 8-K filed February 28, 2014	1-6986 PNM

10.96	Letter Agreement dated May 1, 2014, among PNM, PNMR Development and Management Corporation, Cypress Verde LLC, and Cypress Second PV Partnership	10.4 to PNM’s Quarter Repot on Form 10-Q for the quarter ended March 31, 2014	1-6986 PNM

10.97	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

10.98	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

10.99	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

10.100	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

10.101	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

10.102	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

10.103	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

10.104	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, 2014	1-32462 PNMR

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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

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

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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

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

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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 27, 2015	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 27, 2015
P. K. Collawn
Chairman, President, and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer	February 27, 2015
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ T. G. Sategna	Principal Accounting Officer	February 27, 2015
T. G. Sategna
Vice President and
Corporate Controller

/s/ A. E. Archuleta	Director	February 27, 2015
A. E. Archuleta

/s/ E. R. Conley	Director	February 27, 2015
E. R. Conley

/s/ A. J. Fohrer	Director	February 27, 2015
A. J. Fohrer

/s/ M. T. Mullarkey	Director	February 27, 2015
M. T. Mullarkey

/s/ R. R. Nordhaus	Director	February 27, 2015
R. R. Nordhaus

/s/ D. K. Schwanz	Director	February 27, 2015
D. K. Schwanz

/s/ B. W. Wilkinson	Director	February 27, 2015
B. W. Wilkinson

/s/ J. B. Woodard	Director	February 27, 2015
J. B. Woodard

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SIGNATURES



			PUBLIC SERVICE COMPANY OF NEW MEXICO
			(Registrant)

Date:	February 27, 2015	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 27, 2015
P. K. Collawn
President and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 27, 2015
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ T. G. Sategna	Principal Accounting Officer	February 27, 2015
T. G. Sategna
Vice President and
Corporate Controller

	Director
R. N. Darnell

/s/ R. E. Talbot	Director	February 27, 2015
R. E. Talbot

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SIGNATURES



			TEXAS-NEW MEXICO POWER COMPANY
			(Registrant)

Date:	February 27, 2015	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 27, 2015
P. K. Collawn
Chief Executive Officer

/s/ T. G. Sategna	Principal Financial Officer and Principal Accounting Officer	February 27, 2015
T. G. Sategna
Vice President and
Controller

	Director
R. N. Darnell

/s/ C. N. Eldred	Director	February 27, 2015
C. N. Eldred

/s/ R. E. Talbot	Director	February 27, 2015
R. E. Talbot

/s/ J. N. Walker	Director	February 27, 2015
J. N. Walker

E-3