PNM RESOURCES INC - Annual Report: 2015 (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, 2015



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 19, 2016, shares of common stock outstanding were:



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

On June 30, 2015, 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 $24.60 per share reported by The Wall Street Journal, was $1,959,479,150. 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 17, 2016.

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- 21
ITEM 2. PROPERTIES			A- 21
ITEM 3. LEGAL PROCEEDINGS			A- 22
ITEM 4. MINE SAFETY DISCLOSURES			A- 23
SUPPLEMENTAL ITEM – EXECUTIVE OFFICERS OF PNM RESOURCES, INC.			A- 24
PART II
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER			A- 25
MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA			A- 26
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			A- 30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			A- 64
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

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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
Anaheim		City of Anaheim, California
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
Board		Board of Directors of PNMR
BTMU		The Bank of Tokyo-Mitsubishi UFJ, Ltd.
BTMU Term Loan Agreement		NM Capital’s $125.0 Million Unsecured Term Loan
BTU		British Thermal Unit
CAA		Clean Air Act
CCB		Coal Combustion Byproducts
CCN		Certificate of Convenience and Necessity
CO₂		Carbon Dioxide
COFA		Capacity Option and Funding Agreement
CSA		Coal Supply Agreement
CTC		Competition Transition Charge
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
Delta		Delta-Person Generating Station, now known as Rio Bravo
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 Company
EPNG		El Paso Natural Gas Company, L.L.C.
ERCOT		Electric Reliability Council of Texas
ESA		Endangered Species Act
Exchange Act		Securities Exchange Act of 1934
Farmington		The City of Farmington, New Mexico
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

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FPPAC		Fuel and Purchased Power Adjustment Clause
FTY		Future Test Year
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
ISFSI		Independent Spent Fuel Storage Installation
KW		Kilowatt
KWh		Kilowatt Hour
La Luz		La Luz Generating Station
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
Los Alamos		The Incorporated County of Los Alamos, New Mexico
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.
MSR		M-S-R Public Power Agency
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.
NEE		New Energy Economy
NEPA		National Environmental Policy Act
NERC		North American Electric Reliability Corporation
New Mexico Wind		New Mexico Wind Energy Center
NM Capital		NM Capital Utility Corporation, an unregulated wholly-owned subsidiary of PNMR
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMPRC		New Mexico Public Regulation Commission
NMSC		New Mexico Supreme Court
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
OSM		United States Office of Surface Mining Reclamation and Enforcement
PBO		Projected Benefit Obligation
PCRBs		Pollution Control Revenue Bonds

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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 2015 Term Loan Agreement		PNMR’s $150.0 Million Three-Year Unsecured Term Loan
PNMR Development		PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Revolving Credit Facility		PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement		PNMR’s $150.0 Million One-Year Unsecured Term Loan
PPA		Power Purchase Agreement
PSA		Power Sales Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RA		San Juan Project Restructuring Agreement
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 known as Delta
RMC		Risk Management Committee
ROE		Return on Equity
RPS		Renewable Energy Portfolio Standard
RSIP		Revised State Implementation Plan
S&P		Standard and Poor’s Ratings Services
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
TCEQ		Texas Commission on Environmental Quality

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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 2013 Bond Purchase Agreement		TNMP’s $80.0 Million First Mortgage Bonds
TNMP 2015 Bond Purchase Agreement		TNMP’s $60.0 Million First Mortgage Bonds
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 Systems
UG-CSA		Underground Coal Sales Agreement
USSC		United States Supreme Court
Valencia		Valencia Energy Facility
VaR		Value at Risk
VIE		Variable Interest Entity
WACC		Weighted Average Cost of Capital
WEG		WildEarth Guardians
Westmoreland		Westmoreland Coal Company
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


•	Delivering above industry-average earnings and dividend growth


•	Maintaining solid investment grade credit ratings

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 has a general rate case, filed in August 2015, pending before the NMPRC. 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 PNM 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 3.2% of its revenues for the year ended December 31, 2015. 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 proposed a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year (“FTY”). On May 13, 2015, the NMPRC voted to dismiss PNM’s application as being incomplete, primarily due to procedural defects. On August 27, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase of $123.5 million, including base fuel revenues. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. New rates are expected to become effective in the third quarter of 2016. See Note 17 for additional information concerning this filing.

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, which PNM requested in its current rate filing. 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%, PNM would refund the excess to customers during May through December of the following year. PNM’s earned return on jurisdictional equity did not exceed 10.5% in 2013, 2014, or 2015.

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 above. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC.

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No party has filed in opposition of the settlement. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. The FERC ALJ authorized the interim implementation of settled rates beginning on April 1, 2015, subject to refund. 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 aggregated approximately 62 MW in 2015. No firm-requirements customer of PNM accounted for more than 2.5% of PNM’s revenues for the year ended December 31, 2015.

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. 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. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third-party supplier(s) under the PSA. PNM intervened, requesting that FERC deny NEC’s petition. On October 29, 2015, PNM and NEC entered into and filed with FERC a settlement agreement that includes amendments to the PSA and related contracts, subject to FERC approval. Under the agreement, PNM would serve all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. The PSA would terminate on December 31, 2016. In 2017, PNM would continue to serve 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices currently available under short-term market rates. FERC approved the settlement on January 21, 2016. PNM anticipates that, in future general rate cases, assets and costs previously assigned to serve NEC will be reassigned, primarily to retail customers. In 2015 and 2014, monthly billing demand for power supplied to NEC averaged approximately 54 MW and 55 MW and revenues were $27.1 million and $28.4 million under the PSA.

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 also provides electricity at wholesale to the City of Aztec, New Mexico under a contract that will expire on June 30, 2016. PNM’s recently filed general rate case discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of these contracts. See Results of Operations in MD&A and Note 17. In 2014, PNM entered into a contract with the Jicarilla Apache Nation to provide electricity at wholesale through May 8, 2019, although the customer has the option to terminate the contract upon appropriate notice.

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. In October 2015, FERC denied PNM’s request.

Operational Information

Weather-normalized retail electric KWh sales decreased by 1.4% in 2015 and 1.7% in 2014. The system peak demands for retail and firm-requirements customers were as follows:

System Peak Demands



	2015	2014	2013
	(Megawatts)
Summer	1,889	1,878	2,008
Winter	1,433	1,471	1,576

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 49.8%, 10.7%, and 9.9% of PNM’s 2015 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.

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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 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 3,199 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, PNM’s transmission system is fully committed during peak hours for delivery of existing resources, 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 bring 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 shareholders realize any earnings or losses. PNM has contracted to sell all of PVNGS Unit 3 output through 2017 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 in 2016. In December 2015, the NMPRC approved PNM’s request 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. See Note 16. In addition to 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. Through PNM’s FPPAC, 90% of the margins from these optimization sales are credited to retail customers through December 31, 2016, after which date 100% of the margins will be credited to customers.

Use of Future Test Year

Under New Mexico law, the NMPRC must set rates using the test period, including a FTY, that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. In November 2015, the NMPRC clarified that FTY could begin up to 13 months after the filing of a rate case application. The NMPRC also 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 FTY 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, PNM’s current request for a general rate increase is based on a FTY period beginning October 1, 2015. As with any forward looking financial information, utilizing a FTY 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 Energy

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% of retail electric sales 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.

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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. TNMP’s transmission and distribution activities are solely within ERCOT, which is the independent system operator responsible for maintaining reliable operations for the bulk electric power supply system in most of Texas. Therefore, 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.

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.

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 2.6% in 2015 and 3.2% in 2014. As of December 31, 2015, 101 active REPs receive transmission and distribution services from TNMP. In 2015, the three largest REP customers of TNMP accounted for operating revenues of 16%, 13%, and 11%. 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 in 2016.

The PUCT approved interim adjustments to TNMP’s transmission rates of $2.9 million in March 2013, $2.8 million in September 2013, $2.9 million in March 2014, $4.2 million in September 2014, $4.4 million in March 2015, and $1.4 million in September 2015. On January 29, 2016, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.3 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 to 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, 2015, the total net generation capacity of facilities owned or leased by PNM was 2,477 MW. PNM also obtains power under long-term PPAs for the power produced by New Mexico Wind, which has a capacity of 204 MW, the output of the Lightning Dock Geothermal facility, which currently has a capacity of 4 MW, and 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 December 31, 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	Albuquerque, New Mexico	138
Gas	Valencia	Belen, New Mexico	158
Gas	La Luz	Belen, New Mexico	40
Nuclear	PVNGS	Wintersburg, Arizona	402
Solar	PNM-owned solar	Fifteen sites in New Mexico	107
Wind	New Mexico Wind	House, New Mexico	204
Wind	Red Mesa Wind	Seboyeta, New Mexico	102
Geothermal	Lightning Dock Geothermal	Lordsburg, New Mexico	4
			2,787

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, 10.04% by Anaheim, 8.475% by Farmington, 7.2% by Los Alamos, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the shutdown of Units 2 and 3 on December 31, 2017 and the restructuring of the ownership interests in SJGS. Under the restructuring agreement, PNM would own 64.5% of Unit 4, PNMR Development would own 12.8% of Unit 4, and SCPPA, Tri-State, MSR, and Anaheim would no longer have any ownership interest in SJGS following the December 31, 2017 restructuring. However, PNMR anticipates that the interest of PNMR Development will be transferred to PNM, as authorized by the NMPRC, prior to the restructuring date.

Four Corners Units 4 and 5 are 13% owned by PNM. These units 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 required the approval of the DOI, as did a related federal rights-of-way grant, which was received in July 2015. APS has announced it has agreed to acquire the 7% interest of EPE, which is anticipated to become effective in July 2016. APS is negotiating an agreement for the sale of that 7% interest to an entity of the Navajo Nation. See Note 16 for additional information about Four Corners.

PNM owns 100% of Reeves, Afton, Rio Bravo, Lordsburg, and La Luz 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 the energy and capacity of Rio Bravo under a PPA. PNM is entitled to the entire output of Valencia under a PPA. Valencia is a variable interest entity and is consolidated by PNM as required by GAAP. Reeves, Lordsburg, Rio Bravo, La Luz, 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, including portions that are leased to PNM. See Note 7 for additional in

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formation concerning the PVNGS leases, including the renewal of the four PVNGS Unit 1 leases and one of the PVNGS Unit 2 leases and the purchase of the assets underlying the other three Unit 2 leases. Following the January 15, 2016 exercise of the Unit 2 purchase options, PNM has ownership interests of 2.3% in Unit 1, 9.4% in Unit 2, and 10.2% in Unit 3 and has leasehold interests of 7.9% in Unit 1 and 0.8% in Unit 2. The lease payments for the leased portions of PVNGS are recovered through retail rates approved by the NMPRC. See Note 16 for information on other PVNGS matters, including the NMPRC’s approval of 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. PVNGS has met the NRC’s imposed deadlines for installation of equipment to address these requirements, but has minor additional work to perform in 2016. PVNGS has spent approximately $125 million on capital enhancements as of December 31, 2015 (PNM’s share is 10.2%).

Solar

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 2011. PNM also 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. In 2015, PNM completed construction of an additional 40 MW of PNM-owned solar PV facilities at four additional sites. The NMPRC has approved a voluntary tariff that allows PNM retail customers to buy renewable electricity for a small monthly premium. Power from 1 MW of PNM’s solar capacity is used to service load under the voluntary tariff.

Plant Operating Statistics

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



Plant	Operator	2015	2014	2013
SJGS	PNM	67.4%	76.5%	77.6%
Four Corners	APS	77.8%	68.1%	72.9%
PVNGS	APS	94.2%	91.8%	89.4%

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. The Four Corners owners executed amendments to the agreements governing the operations of Four Corners that would extend those agreements until July 2041. The amendments are expected to become effective upon APS’ purchase of the ownership interest of EPE, which is anticipated to occur in July 2016. In addition, SJGS and Four Corners are coal-fired generating plants that obtain their coal requirements from mines near the plants. A new agreement for coal supply for SJGS, which expires on June 30, 2022, became effective at 11:59 PM on January 31, 2016. At that same time, an agreement to restructure the ownership in SJGS became effective. That agreement provides for certain existing participants in SJGS to exit ownership at December 31, 2017, at which time two of the four SJGS units will be permanently shutdown. In December 2013, the coal supply arrangement for Four Corners was extended through 2031. See Note 16 for a discussion of the restructuring of SJGS ownership and developments with respect to Four Corners. 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 these leases. It is possible that other participants in the joint projects have circumstances and objectives that have changed 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 proj

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ects. 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.

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. Power from New Mexico Wind is used to service load under the voluntary tariff discussed above 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 9 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,
	2015		2014		2013
Purchased under long-term PPAs
MWh	599,562		492,906		490,539
Cost per MWh	$	22.18	$	27.82	$	27.25
Other purchased power
Total MWh	729,895		1,023,744		1,061,514
Cost per MWh	$	28.94	$	40.30	$	35.64

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
2015	53.3	%	$	2.88	32.6	%	$	0.70	12.6	%	$	2.91
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

In 2015, 2014, and 2013, 1.5%, 1.0%, and 0.6% of PNM’s generation was from utility owned solar, which has no fuel cost. The generation mix for 2016 is expected to be 57.1% coal, 30.7% nuclear, 9.5% gas and oil, and 2.7% utility owned solar. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits, and the generally adequate

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supply of nuclear fuel, PNM believes that adequate sources of fuel are available for its generating stations into the foreseeable future. See Sources of Power – PNM – PPAs for information concerning the cost of purchased power.

Coal

A new coal supply contract for SJGS, which expires on June 30, 2022, became effective at 11:59 PM on January 31, 2016. Substantially all of the benefits of lower coal pricing under the new contract will be passed through to PNM’s customers under the FPPAC. Coal supply has not been arranged for periods after the existing contract expires. PNM believes there is adequate availability of coal resources to continue to operate SJGS although an extended or new contract could result in higher prices. In late December 2013, a new fifteen-year coal supply contract for Four Corners, beginning in July 2016, was executed. Coal costs are anticipated to increase approximately 40% in the first year 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. Certain of 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 2019-2025. The participants have also contracted for 100% of PVNGS’s enrichment services through 2020 and 20% of its enrichment services through 2026. 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.

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Water Supply

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

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. 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 (Note 14) includes the environmental upgrades at SJGS and Four Corners discussed in Note 16, which aggregate $46.9 million in 2016 and $44.8 million in 2017 through 2020. 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”


•	Four Corners Coal Mine


•	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


•	Environmental Matters under the caption “Coal Supply”

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, 2015:



	PNMR	PNM	TNMP
Corporate ⁽¹⁾	437	—	—
PNM	1,074	1,074	—
TNMP	357	—	357
Total	1,868	1,074	357

(1)Represents employees of PNMR Services Company.

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As of December 31, 2015, PNM had 561 employees in its power plant and operations areas that are currently covered by a collective bargaining agreement with the IBEW Local 611 that is in effect from December 5, 2015 through April 30, 2020. 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.

As of December 31, 2015, TNMP had 185 employees represented by IBEW Local 66. The parties have a collective bargaining agreement that is in effect from March 9, 2015 through September 9, 2016.

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 the pending application for a retail rate increase before the NMPRC and other impacts of federal or state regulatory and judicial actions


•	State and federal regulation or legislation relating to environmental matters, the resultant costs of compliance, and other impacts on the operations and economic viability of PNM’s generating plants


•	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, including the Clean Power Plan


•	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 the 2018 required NMPRC filing to determine the extent to which SJGS should continue serving PNM’s retail customers

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


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


•	Uncertainty surrounding counterparty credit risk, including financial support provided to facilitate the new coal supply and ownership restructuring at SJGS, as well as obligations to provide additional collateral in support of required reclamation bonds


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


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


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


•	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


•	The effectiveness of risk management regarding commodity transactions and counterparty risk


•	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.

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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 2016-2020 to be $2,037.0 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:


•	New asset construction related to generation, transmission, and distribution systems necessary to provide electric service, including costs of generation capacity to replace the early retirement of SJGS Units 2 and 3 as part of compliance with the regional haze provisions of the CAA (Note 16)


•	Environmental compliance expenditures


•	The regulatory mandate to acquire power from renewable resources


•	Increased regulation related to nuclear safety


•	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


•	Adverse economic conditions


•	Reductions in costs of energy efficient technology


•	Reduced new sources of demand


•	Unpredictable weather patterns

In 2015 and 2014, PNM experienced decreases in weather-normalized retail sales of 1.4% and 1.7%. The sales decreases reflect a continued sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area has lagged the nation in economic recovery. The economy in New Mexico continues to have mixed indicators. New Mexico’s overall economy continues to experience softness that is driven primarily by low oil and natural gas prices. Although PNM does not serve the regions of the state that produce oil and gas, it is anticipated that the impacts of layoffs and the decrease in state royalty revenues will further soften the economies in PNM’s service territory to some degree, particularly in the Albuquerque metro area and Santa Fe, as the state deals with budget shortfalls. In Texas, the drop in oil prices has impacted the economy, particularly in the Houston area, 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.

As discussed in Note 17, PNM filed an application for a general rate increase in December 2014, which the NMPRC dismissed in May 2015, based on the Hearing Examiners recommendation, which cited procedural defects in the filing. PNM filed a new application with the NMPRC for a $123.5 million general rate increase in August 27, 2015. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and the recovery of those investment dollars, including depreciation based on an updated depreciation study, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed changes to rate design, a revenue decoupling pilot program, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. PNM believes that all of the capital costs proposed to be recovered in the rate case should be approved by the NMPRC. However, certain intervenors have proposed the disallowance or only partial recovery of PNM’s capital investment in BDT equipment installed on SJGS Units 1 and 4 (Note 16) and disallowance of all or a portion of the acquisition costs for PNM’s January 15, 2016 purchase of 64 MW of PVNGS Unit 2, which were previously leased to PNM. The NMPRC’s designated Hearing Exa

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miner has established a procedural schedule that anticipates a public hearing on the proposed new rates will begin on March 14, 2016. An adverse outcome in the current rate case could negatively impact PNM’s results of operation and cash flows.

PNM currently recovers the cost of fuel for its generation facilities through its FPPAC. A new coal supply contract for SJGS, which expires on June 30, 2022, became effective at 11:59 PM on January 31, 2016 and provides for lower coal pricing than under the prior contract. In December 2013, a new fifteen-year coal supply contract for Four Corners, beginning in July 2016, was executed. Four Corners coal costs are anticipated to increase approximately 40% in the first year of the new contract. The contracts provide for pricing adjustments over their terms based on economic indices. Although PNM believes costs under coal supply arrangements would continue to be recovered through the FPPAC, there can be no assurance that full recovery would be allowed.

PNM’s regulatory approvals from the NMPRC, which are necessary for PNM to comply with the regional haze requirements of the CAA pertaining to SJGS, have been appealed to the NMSC and are subject to a motion for reconsideration before the NMPRC. PNMR has counterparty credit risk in connection with financial support provided to facilitate the new coal supply arrangement for SJGS. Furthermore, the NMPRC approval requires PNM to make a filing in 2018 to determine the extent to which SJGS should continue to serve PNM’s retail customers after June 30, 2022, on which date the SJPPA and the current coal supply agreement will expire. Adverse developments from these factors could have a negative impact on PNM’s business, financial condition, results of operations, and cash flows.

SJGS, which currently comprises 31.6% of PNM’s owned and leased generation capacity and is its largest generation resource, is subject to the CAA. As discussed in Note 16, in December 2015, the NMPRC approved a plan enabling SJGS to comply with the CAA (the “BART Approval”). The plan requires the installation of SNCRs on SJGS Units 1 and 4 combined with the shutdown of SJGS Units 2 and 3. NEE, an intervenor in the NMPRC proceeding regarding the approval of the plan, has appealed the BART Approval to the NMSC. NEE has also filed a motion with the NMPRC asking for reconsideration of the BART Approval order based on developments subsequent to the order related to the loan made by NM Capital, a subsidiary of PNMR, to facilitate the sale of SJCC, which is discussed below and described under Coal Supply in Note 16. NEE alleges the loan is a transaction that requires prior NMPRC approval. If the BART Approval is negated, PNM may not be able to continue to operate SJGS without being in violation of the environmental requirements of EPA.

The BART Approval also requires PNM to make a filing with the NMPRC no later than December 31, 2018, and before entering into an agreement for post-2022 coal supply for SJGS, setting forth its position in a case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022. The existing SJPPA among the SJGS participants, which governs the operations of SJGS, and the new CSA for coal supply at SJGS described in Note 16 both expire on June 30, 2022. PNM has the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. Failure to obtain NMPRC approval to continue including SJGS as a resource to serve PNM’s retail customers after June 30, 2022 would likely lead to the early retirement of SJGS at that date, as would failure to extend the SJPPA or to enter into an arrangement for coal supply after June 30, 2022.

A restructuring of SJGS ownership and obtaining a new coal supply for SJGS were integral components of the process to achieve compliance with the CAA at SJGS. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator. In support of the closing of the mine purchase, NM Capital provided a loan of $125.0 million to the purchaser, which has been organized to be a bankruptcy-remote entity. In addition, PNMR used $40.0 million of the available capacity under its revolving credit facility to support a bank letter of credit arrangement with a surety in order for the surety to post reclamation bonds that are required under the mine’s operating permit. PNMR is also obligated to provide the surety with additional collateral in support of the reclamation bonds within 180 days. PNMR is exposed to credit risk in the event the purchaser of the mining operation cannot meet the scheduled repayment obligations under the loan and to a reduction in its financing capability if the required additional collateral cannot be obtained from other sources. See Note 16.

The inability to operate SJGS or the early retirement of SJGS would require PNM to obtain power from other sources in order to serve the needs of its customers. There can be no assurance that adequate sources of power would be available, that adequate transmission capabilities would be available to bring that power in to PNM’s service territory, or whether the cost of obtaining those resources would be reasonable. Any such events would negatively impact PNM’s financial position, results of operation, and cash flows unless the NMPRC authorized the collection from customers of any un-recovered costs related to SJGS as well as costs of obtaining replacement power.

It is also possible that unsatisfactory outcomes of these matters, the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, the adequacy and timeliness of cost recovery mechanisms, and other busine

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ss considerations, could jeopardize the economic viability of the plant or the ability of individual participants to continue participation in SJGS.

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, other federal and state agencies, environmental advocacy groups, and other organizations are focusing 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. As discussed in the Climate Change Issues subsection of Other Issues Facing the Company section of MD&A, this generation is subject to EPA’s regulations requiring GHG reductions. This includes new, existing and modified or reconstructed EGUs. These 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, 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 have been made or will be required for the installation of control technology at both generating stations and operating costs will 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 the implementation of EPA’s regulations regarding climate change, including the Clean Power Plan, how CCBs used for mine reclamation will be regulated, and regulation of other power plant emissions, including changes to the ambient air quality standards, such regulations could have a material impact on operations. Timely regulatory recovery of costs associated with any environmental-related regulations would be needed to maintain a strong financial and operational profile. The above factors could adversely affect the Company’s business, financial position, results of operations, and liquidity.

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

To operate their businesses, PNMR, PNM, and TNMP are required to have numerous permits and approvals from a variety of regulatory agencies. Regulatory bodies with jurisdiction over the utilities include the NMPRC, NMED, PUCT, TCEQ, ERCOT, FERC, NRC, EPA, and NERC. Oversight by these agencies 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

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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 final reclamation of the surface coal mines that may be recovered from customers. PNM records estimated liabilities for its share of the legal obligations for decommissioning and reclamation. These estimates include many assumptions about future events and are inherently imprecise. In the event any of these costs exceed current estimates, results of operations 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

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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. 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 16.2% of PNM’s total owned and leased generating capacity. PVNGS is subject to environmental, health, and financial risks, including, but not limited to:


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


•	The ability to dispose of spent nuclear fuel


•	Decommissioning of the plant


•	Securing the facilities against possible terrorist attacks


•	Unscheduled outages due to equipment failures

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

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. Events at nuclear facilities of other operators or which impact 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 powe

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r 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. As a result of the Fukushima Daiichi event, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s near term task force. In response to these recommendations, PVNGS expects to spend approximately $0.5 million for capital enhancements to the plant over the next year in addition to the approximate $125 million that has already been spent on capital enhancements as of December 31, 2015 (PNM’s share is 10.2%). PNM cannot predict whether these amounts will increase or whether additional financial and/or operational requirements on PVNGS and APS 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 shutdown 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.

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

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

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

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


•	Future growth plans and the related capital requirements


•	Other business considerations

Disruption in the credit and capital markets may impact the Company’s 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, as discussed in MD&A – Liquidity and Capital Resources, not satisfied by cash flow from operations. 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 2016-2020 to be $2,037.0 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.

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

Governance Factors

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

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


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


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


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

Under the New Mexico Public Utility Act, NMPRC approval is required for certain transactions that may result in PNMR’s change in control or exercise of control, including ownership of 10% or more of PNMR’s voting stock. PUCT approval is required for changes to the ownership of TNMP or its parent and certain other transactions relating to TNMP. 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

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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, 2015, PNM owned, jointly owned, or leased, 3,199 circuit miles of electric transmission lines (including the EIP), 6,067 miles of distribution overhead lines, 5,759 cable miles of underground distribution lines (excluding street lighting), and 274 substations. PNM’s electric transmission and distribution lines are generally located within easements and rights-of-way on public, private, and Native American lands. PNM leases interests in PVNGS Units 1 and 2 and related property, 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 PNM’s renewal of certain of the PVNGS leases and exercise of its option to purchase the assets underlying certain other leases at the expiration of the original lease terms. As discussed in Note 7, PNM exercised 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, 2015, TNMP owned 966 circuit miles of overhead electric transmission lines, 7,087 pole miles of overhead distribution lines, 1,167 circuit miles of underground distribution lines, and 110 substations. Substantially all of TNMP’s property is pledged to secure its first mortgage bonds. See Note 6.


ITEM 3.	LEGAL PROCEEDINGS

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

Note 16


•	The Clean Air Act – Regional Haze – SJGS


•	The Clean Air Act – Regional Haze – Four Corners


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


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


•	Four Corners Coal Mine


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Santa Fe Generating Station


•	Continuous Highwall Mining Royalty Rate


•	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 – New Mexico General Rate Case


•	PNM – Proceeding Regarding Definition of Future Test Year


•	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 – Application for Certificate of Convenience and Necessity


•	PNM – Transmission Rate Case


•	PNM – Formula Transmission Rate Case


•	PNM – Firm-Requirements Wholesale Customers – Navopache Electric Cooperative, Inc.


•	TNMP – Advanced Meter System Deployment


•	TNMP – Energy Efficiency


•	TNMP – Transmission Cost of Service Rates

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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 19, 2016 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	57	Chairman, President, and Chief Executive Officer	January 2012
		President and Chief Executive Officer	March 2010

C. N. Eldred	62	Executive Vice President and Chief Financial Officer	July 2007

P. V. Apodaca	64	Senior Vice President, General Counsel, and Secretary	January 2010

R. E. Talbot	55	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	58	Senior Vice President, Public Policy	January 2012
		Vice President, Regulatory Affairs	April 2008

J.D. Tarry ⁽¹⁾	45	Vice President, Corporate Controller, and Chief Information Officer	April 2015
		Vice President, Customer Service and Chief Information Officer	May 2012
		Executive Director, Financial Planning and Business Analysis	January 2010

⁽¹⁾On December 9, 2014, T. G. Sategna notified the Company that he intended to retire as the Company’s principal accounting officer effective as of March 31, 2015. On December 11, 2014, the Company appointed J. D. Tarry as its Vice President and Controller, effective as of April 1, 2015. His appointment was approved by the Board on February 26, 2015.

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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 2015 and 2014, by quarters, are as follows:



Quarter Ended	Range of Sales Prices				Dividends Declared Per Share
	High		Low		Dividends Declared Per Share
2015
March 31	$	31.18	$	27.06	$	0.200
June 30	29.78		24.49		0.200
September 30	28.17		24.42		0.200
December 31	31.23		26.56		0.220
Fiscal Year	31.23		24.42		0.820
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

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 $0.185 per share in July 2014 and $0.200 per share in July 2015, 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 $0.185 per share in September 2014 and $0.200 per share in September 2015, which are reflected as being in the third quarter above. On February 25, 2016, the Board declared a quarterly dividend of $0.22 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 19, 2016, there were 11,057 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 2015 and 2014. 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.



PNM RESOURCES, INC. AND SUBSIDIARIES
	2015			2014			2013			2012			2011
	(In thousands except per share amounts and ratios)
Total Operating Revenues	$	1,439,082		$	1,435,853		$	1,387,923		$	1,342,403		$	1,700,619
Net Earnings	$	31,078		$	130,909		$	115,556		$	120,125		$	190,934
Net Earnings Attributable to PNMR	$	15,640		$	116,254		$	100,507		$	105,547		$	176,359
Net Earnings Attributable to PNMR per Common Share
Basic	$	0.20		$	1.46		$	1.26		$	1.32		$	1.98
Diluted	$	0.20		$	1.45		$	1.25		$	1.31		$	1.96
Cash Flow Data
Net cash flows from operating activities	$	386,874		$	414,876		$	386,587		$	281,349		$	292,240
Net cash flows from investing activities	$	(544,528	)	$	(485,329	)	$	(331,446	)	$	(285,895	)	$	19,778
Net cash flows from financing activities	$	175,431		$	96,194		$	(61,593	)	$	(1,560	)	$	(312,331	)
Total Assets	$	6,009,328		$	5,790,237		$	5,426,858		$	5,356,411		$	5,185,931
Long-Term Debt, including current installments	$	2,091,948		$	1,962,385		$	1,730,749		$	1,656,118		$	1,655,331
Common Stock Data
Market price per common share at year end	$	30.57		$	29.63		$	24.12		$	20.51		$	18.23
Book value per common share at year end	$	20.78		$	21.61		$	21.01		$	20.19		$	19.76
Tangible book value per share at year end	$	17.28		$	18.12		$	17.52		$	16.70		$	16.27
Average number of common shares outstanding – diluted	80,139			80,279			80,431			80,417			89,757
Dividends declared per common share	$	0.820		$	0.755		$	0.680		$	0.580		$	0.500
Capitalization
PNMR common stockholders’ equity	44.0		%	46.6		%	49.0		%	49.1		%	48.6		%
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.3			0.3			0.3			0.3
Long-term debt	55.7			53.1			50.7			50.6			51.1
	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%

Notes: 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.

As discussed in Note 6, the Company adopted a new accounting standard during 2015 that required debt issuance costs, which were previously included in other deferred charges on the Consolidated Balance Sheets, to be reclassified as a reduction of the related long-term debt. As discussed in Note 11, the Company adopted a new accounting standard during 2015 to present all deferred taxes as non-current rather than classifying deferred tax assets and liabilities as non-current or current. These changes were applied retroactively to all years shown above. Total assets, long-term debt, and capitalization presented in the above table have been changed from the presentation of those items in prior years to reflect the retroactive application of the changes in accounting standards.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2015			2014		2013		2012		2011
	(In thousands)
PNM Revenues
Residential	$	427,958		$	411,412	$	411,579	$	409,005	$	390,380
Commercial	437,279			428,085		415,621		413,332		386,383
Industrial	75,308			73,002		74,552		78,637		73,742
Public authority	26,202			25,278		25,745		25,495		23,970
Economy service	35,132			39,123		32,909		25,354		21,141
Transmission	33,216			38,284		38,228		39,373		43,637
Firm-requirements wholesale	31,263			38,313		42,370		39,390		34,127
Other sales for resale	63,195			82,508		67,538		47,321		69,318
Mark-to-market activity	(5,270		)	5,996		293		892		4,214
Other	6,912			5,913		7,477		13,465		10,377
Total PNM Revenues	$	1,131,195		$	1,147,914	$	1,116,312	$	1,092,264	$	1,057,289
TNMP Revenues
Residential	$	120,771		$	114,826	$	111,373	$	103,255	$	100,290
Commercial	102,956			99,701		95,098		88,258		84,896
Industrial	16,316			15,049		13,084		13,405		13,065
Other	67,844			58,363		52,056		45,222		39,607
Total TNMP Revenues	$	307,887		$	287,939	$	271,611	$	250,140	$	237,858
First Choice Revenues
Residential	$	—		$	—	$	—	$	—	$	260,161
Commercial	—			—		—		—		166,498
Other	—			—		—		—		12,791
Total First Choice Revenues	$	—		$	—	$	—	$	—	$	439,450

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 received from First Choice in 2011.

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
	2015	2014	2013	2012	2011
PNM MWh Sales
Residential	3,185,363	3,169,071	3,304,350	3,323,544	3,402,842
Commercial	3,800,472	3,874,292	3,954,774	4,022,184	4,043,796
Industrial	957,308	984,130	1,041,160	1,136,011	1,132,110
Public authority	246,496	251,187	266,368	279,169	282,062
Economy service	796,430	758,629	719,342	635,305	428,757
Firm-requirements wholesale	444,495	527,597	654,135	651,972	650,356
Other sales for resale	2,110,947	2,271,480	2,061,851	1,652,225	2,076,869
Total PNM MWh Sales	11,541,511	11,836,386	12,001,980	11,700,410	12,016,792
TNMP MWh Sales
Residential	2,912,019	2,802,768	2,796,661	2,714,511	2,862,337
Commercial	2,654,102	2,583,664	2,472,979	2,374,805	2,381,872
Industrial	2,804,919	2,708,151	2,576,762	2,705,456	2,558,003
Other	100,999	102,118	104,516	103,856	108,664
Total TNMP MWh Sales	8,472,039	8,196,701	7,950,918	7,898,628	7,910,876
First Choice MWh Sales
Residential	—	—	—	—	2,006,437
Commercial	—	—	—	—	1,538,203
Total First Choice MWh Sales	—	—	—	—	3,544,640


Notes:	The MWh reported above for TNMP include 836,599 for 2011, 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.

The MWh reported above for TNMP for 2011 through 2014 reflect a reclassification from industrial to commercial to be consistent with current year presentation.

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2015		2014		2013		2012		2011
PNM Customers
Residential	459,353		455,907		453,218		450,507		448,979
Commercial	56,107		55,853		55,447		54,953		54,468
Industrial	250		249		251		250		251
Economy service	1		1		1		1		1
Other sales for resale	39		39		34		36		28
Other	908		911		928		952		983
Total PNM Customers	516,658		512,960		509,879		506,699		504,710
TNMP Consumers
Residential	202,359		199,963		196,799		193,550		192,356
Commercial	39,014		38,033		37,460		36,819		37,208
Industrial	70		70		70		70		73
Other	2,018		2,044		2,070		2,037		2,092
Total TNMP Consumers	243,461		240,110		236,399		232,476		231,729
First Choice Customers
Residential	—		—		—		—		176,577
Commercial	—		—		—		—		44,485
Total First Choice Customers	—		—		—		—		221,062
PNMR Generation Statistics
Net Capability – MW, including PPAs	2,787		2,707		2,572		2,537		2,547
Coincidental Peak Demand – MW	1,889		1,878		2,008		1,948		1,938
Average Fuel Cost per MMBTU	$	2.168	$	2.415	$	2.237	$	2.308	$	2.267
BTU per KWh of Net Generation	10,456		10,422		10,308		10,289		10,441


Notes:	The consumers reported above for TNMP include 64,732 consumers for 2011, 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 760,000 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 regulated businesses


•	Delivering above industry-average earnings and dividend growth


•	Maintaining solid investment grade credit ratings

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


•	Maintaining strong plant performance, system reliability, and employee safety


•	Delivering a superior customer experience


•	Environmental leadership in their business operations


•	Supporting the communities in their service territories

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 proposed a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year (“FTY”). On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete, primarily due to procedural defects, and reject it. PNM disagreed with the Hearing Examiner’s Initial Recommended Decision and filed exceptions. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision and dismissed PNM’s application.

On August 27, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase of $123.5 million, including base fuel revenues. The application is based on a FTY beginning October 1, 2015, which met the NMPRC’s May 2015 interpretation of the FTY statute discussed below, and a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The application includes several proposed 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, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. New rates are expected to become effective in the third quarter of 2016.

On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM believes that the correct interpretation of the New Mexico FTY statute allows

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a FTY to begin up to 13 months after the filing of an application. On June 25, 2015, PNM filed a Notice of Appeal to the NMSC, challenging the NMPRC’s order. The NMSC remanded this matter back to the NMPRC. On November 30, 2015, the NMPRC modified its previous order to provide for a FTY to begin up to 13 months after the filing of a rate case application and the NMPRC filed its revised order with the NMSC on December 9, 2015. On January 20, 2016, PNM and the NMPRC filed an unopposed stipulation of voluntary dismissal of the appeal and the NMSC dismissed the appeal on February 15, 2016.

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 allow for more timely recovery of investments and improve PNM’s ability to earn its authorized return.

In early 2013, 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. PNM has allocated a portion of its generation assets to serve FERC wholesale generation services customers for a number of years. Recently, the low natural gas price environment has caused market prices for power to be substantially lower than what PNM is able to offer customers under the cost of service model that FERC requires PNM to use. As a result of this change in market conditions, PNM has not been earning an adequate return on the assets required to serve wholesale contracts and has decided to stop pursuing wholesale contracts that are served with the same generation assets that serve retail customers.

PNM had a PSA to supply power to NEC through 2035, which was approved by FERC in April 2013. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the PSA. PNM intervened, requesting that FERC deny NEC’s petition. On July 16, 2015, FERC set the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures.

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement that includes amendments to the PSA and related contracts, subject to FERC approval. Under the agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014 and only partially paid in 2015. The PSA would terminate on December 31, 2016. In 2017, PNM would continue to serve 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices currently available under short-term market rates. FERC approved the settlement on January 21, 2016. In 2015 and 2014, monthly billing demand for power supplied to NEC averaged approximately 54 MW and 55 MW and revenues were $27.1 million and $28.4 million under the PSA. Although the settlement agreement will negatively impact results of operations in 2016 and 2017, PNM expects to be able to mitigate these impacts through market sales of power that would have been sold to NEC, reductions in fuel and transmission expenses, and other measures. PNM anticipates that, in future general rate cases, assets and costs previously assigned to serve NEC will be reassigned, primarily to retail customers.

On June 29, 2014, the contract to provide power to Gallup, previously PNM’s second largest customer for wholesale generation services expired. PNM’s general rate case application 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. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. The FERC ALJ authorized the settled rates to be implemented beginning April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.

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

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 growth in EPS.

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Additional information about rate filings is provided in Note 17.

Delivering Above Industry-Average Earnings and Dividend Growth

PNMR’s strategic goal to deliver above industry-average earnings and dividend growth enables investors to realize the value in the Company’s business. PNMR’s current target is seven to nine percent earnings growth through 2019. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that 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. 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. The Board approved the following increases in the indicated annual common stock dividend:



Approval Date		Percent Increase
February 2012		16%
February 2013		14%
December 2013		12%
December 2014		8%
December 2015		10%

Maintaining Solid Investment Grade Credit Ratings

The Company is committed to maintaining investment grade credit ratings in order to reduce the cost of debt financing and to help ensure access to credit markets, when required. 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 December 21, 2015, S&P raised by one notch the issuer credit ratings for PNMR, PNM, and TNMP and the debt ratings for PNM and TNMP, with a stable outlook. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade.

Business Focus

PNMR strives to create enduring value for customers, communities, and stockholders. PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power. 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. Equally important are PNMR’s utilities’ focus on customer satisfaction and community engagement.

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. Through 2014, both PNM and TNMP ranked in the top quartile nationally for reliability for three out of the previous five years. In 2014, PNM delivered its best reliability performance in the past seven years and TNMP’s reliability was its best in a decade. PNM anticipates again being in the top quartile for 2015 despite 2015 being one of the wettest years on record in New Mexico, whereas TNMP’s reliability was more negatively impacted by violent weather events accompanied with record amounts of rain in certain areas of Texas.

In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its Texas service area. Through the end of 2015, TNMP had completed installation of more than 218,000 advanced meters, which is approximately 91% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

As part of the State of Texas’ long-term initiative to create an advanced electric grid, installation of advanced meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In addition,

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TNMP recently completed installation of a new outage management system that will leverage capabilities of the advanced metering infrastructure to enhance TNMP’s responsiveness to outages.

During the 2013 to 2015 period, PNM and TNMP together invested $1,302.4 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. Construction began in April 2015 and the facility went into service in December 2015. In addition, in January 15, 2016, PNM completed the $163.3 million acquisition of 64 MW of capacity in PVNGS Unit 2 that had previously been leased to PNM.

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 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

PNM continues its efforts to reduce the amount of fresh water used to make electricity (about 25% more efficient than in 2002). Continued growth in PNM’s fleet of solar, wind, and geothermal energy sources, energy efficiency programs, and innovative uses of gray water and air-cooling technology have contributed to this reduction. Water usage will continue to decline as PNM substitutes less fresh-water-intensive generation resources for SJGS Units 2 and 3 starting in 2018 (reducing water consumption at that plant by around 50%). Focusing on responsible stewardship of New Mexico’s scarce water resources improves PNM’s water-resilience in the face of persistent drought and ever-increasing demands for water to spur the growth of New Mexico’s economy. 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 renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPAs. As of December 31, 2015, PNM had 107 MW of utility-owned solar capacity, including 40 MW completed in 2015. The application for a general rate increase discussed above includes recovery of the costs associated with the new 40 MW solar facilities. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 49.5 MW at December 31, 2015. PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of advanced grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid. Since 2003, PNM has purchased the output from a 204 MW wind facility and began purchasing the output of another existing 102 MW wind energy center on January 1, 2015. PNM has 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 9 MW of generation capacity. PNM also purchases RECs as necessary to meet the RPS.

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 limit set by the NMPRC. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2016 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2016 and 2017. PNM will continue to procure renewable resources while balancing the impact to customers’ bills in order to meet New Mexico’s escalating RPS requirements.

SJGS

In December 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. Additional information

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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. However, 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. A RSIP was approved by the EIB and EPA. Installation of SNCRs and related BDT equipment has been completed within the timeframe contained in the RSIP.

The RSIP provides for 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. In October 2014, PNM filed a stipulation with the NMPRC that, if approved, would have settled the case. A public hearing in the NMPRC case was held in January 2015. On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommended that the NMPRC reject the stipulation as proposed. Among other things, the certification cited the lack of final restructuring and post-2017 coal supply agreements for SJGS. PNM filed final executed restructuring and post-2017 coal supply agreements for SJGS in July 2015.

Following a NMPRC ordered facilitation process, PNM and several intervenors in the case agreed to a settlement agreement, which was filed with the NMPRC in August 2015. NEE filed in opposition to the agreement. The stipulating parties agreed that the October 2014 stipulation should be approved, as modified by the settlement agreement (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement, PNM will:


•	Retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% (currently estimated to be approximately $127.6 million) of their undepreciated net book value at that date and earn a regulated return on those costs


•	Be granted a CCN for 132 MW in SJGS Unit 4, with an initial book value of zero, plus SNCR costs and whatever portion of BDT costs the NMPRC determines to be reasonable and prudent to be allowed for recovery in rates


•	Be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017 (estimated to be approximately $150 million)


•	Be authorized to acquire 65 MW of SJGS Unit 4 as merchant utility plant, which would not be included in rates charged to retail customers


•	Accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case)


•	Make a NMPRC filing in 2018 to determine the extent that SJGS should continue serving PNM’s customers’ needs after mid-2022


•	Retire one MWh of RECs that include a zero-CO₂ emission attribute beginning January 1, 2020 for every MWh produced by 197 MW of coal-fired generation from PNM’s ownership share of SJGS (the cost of these RECs would be capped at $7.0 million per year and recovered in rates)


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

A hearing on the Stipulated Settlement was held from October 13, 2015 through October 20, 2015. On November 16, 2015, the Hearing Examiner issued a Certification of Stipulation, essentially adopting the Stipulated Settlement. On December 16, 2015, following oral argument, the NMPRC issued a final order adopting the Certification of Stipulation issued by the Hearing Examiner. The Hearing Examiner’s certification included a non-substantive change, which the signatories subsequently approved.

At December 31, 2015, PNM recorded a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered. A regulatory disallowance of $21.6 million was also recorded at December 31, 2015 for other unrecoverable costs based on the approved Stipulated Settlement. The new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”), discussed below and further described under Coal Supply in Note 16, resulted in a $16.5 million increase in the estimated liability recorded for coal mine reclamation. The expense recorded for this increase and the above disallowances are included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss).

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apital to facilitate the sale of SJCC, which is discussed below. NEE alleges the loan is a transaction that, under the New Mexico Public Utility Act, requires prior NMPRC approval. PNM filed its response to NEE’s motion for reconsideration on February 18, 2016.

In connection with the implementation of the RSIP and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants began negotiating 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 future operating costs, among other items.

In June 2014, non-binding arrangements were reached among the SJGS owners that identified 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. These arrangements provided the essential terms of restructured ownership of SJGS. These arrangements recognized the need to have greater certainty 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.

The San Juan Project Restructuring Agreement (“RA”) sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 2014 arrangements. On December 31, 2017, PNM will acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development will acquire 65 MW of such capacity. It is currently anticipated that PNMR Development will transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity. The Stipulated Settlement provides that PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates. The RA also sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants as of January 1, 2016 and will provide coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers through the FPPAC.

The RA became effective contemporaneously with the effectiveness of the new CSA for SJGS. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Note 16 occurred on January 31, 2016. In support of the closing of the mine purchase and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company (the “Purchaser”) to finance the purchase price. NM Capital was able to provide the $125.0 million financing to the Purchaser by first entering into a $125.0 million term loan agreement with a commercial bank. PNMR guarantees the obligations of NM Capital. The Westmoreland loan has a maturity date of February 1, 2021 and initially bears interest at a 7.25% rate plus LIBOR and escalates over time. The Purchaser must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. The Westmoreland loan has been structured to encourage prepayments and early retirement of the debt.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $161.6 million with the New Mexico Mining and Minerals Division. In order to facilitate the posting of reclamation bonds, PNMR, Westmoreland, and SJCC entered into a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) with a surety. In connection with the Reclamation Bond Agreement, PNMR used $40.0 million of the available capacity under the PNMR Revolving Credit Facility to support a bank letter of credit arrangement with the surety. See Note 16.

The NM Capital loan and the letter of credit appear to result in PNMR being considered to have a variable interest in the Purchaser, including its subsidiary, SJCC. Both of those entities would likely be considered to be variable interest entities (“VIEs”). Under GAAP an enterprise that has the power to direct the activities that most significantly impact the economic performance of a VIE is considered to be the VIE’s primary beneficiary and is required to consolidate the VIE. Although PNMR has not completed its analysis of these arrangements, PNMR’s preliminary conclusion is that Westmoreland, as the parent of the Purchaser, has the ability to direct the SJCC mining operations, which will be the factor that most significantly impacts the economic performance of the Purchaser. Accordingly, PNMR currently believes Westmoreland, and not PNMR, is the primary beneficiary of the Purchaser and that PNMR would not consolidate the Purchaser.

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 also were 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. Accordingly, PNM has 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.

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Therefore, PNM issued several “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 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 49%, SO₂ by 77%, particulate matter by 78%, and mercury by 98%.

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 2015, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 79 GWh. This is equivalent to the annual consumption of approximately 10,900 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 2015 resulted in energy savings totaling an estimated 18 GWh. This is equivalent to the annual consumption of approximately 1,660 homes in TNMP’s service territory.

Customer, Stakeholder, and Community Engagement

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.

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. 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 proactively communicates with communities about its efforts and plans related to environmental stewardship. Customers take 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.

PNM expanded its integrated communication efforts with the launch of a new customer information website focused on PNM’s major regulatory filings, including 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.

PNM continues its 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 2015, PNM hosted 38 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.4 million of assistance with utility bills to 3,554 families in 2015. In 2015, PNM committed funding of $0.6 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 2015, the foundation awarded $0.3 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 $1.9 million of support. In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities. In 2014 and 2015, Power Up Grants in the aggregate amount of $0.5 million and $0.5 million were awarded to 24 and 34 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

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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 discussed above 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 also demonstrate TNMP’s commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In 2015 and 2014, PNM experienced decreases in weather-normalized retail load of 1.4% and 1.7%. PNM has been impacted by a sluggish economy in New Mexico, particularly the Albuquerque metropolitan area, which has lagged the nation in economic recovery. The economy in New Mexico continues to have mixed indicators. The employment growth recently in the Albuquerque metro area has been improving. New Mexico overall continues to experience softness that is driven primarily by low oil and natural gas prices. Although PNM does not serve the regions of the state that produce oil and gas, it is anticipated that the impacts of layoffs and the decrease in state royalty revenues will further soften the economies in PNM’s service territory to some degree, particularly in the Albuquerque metro area and Santa Fe, as the state deals with budget shortfalls. TNMP experienced increases in weather normalized retail load of 2.6% and 3.2% in 2015 and 2014. Since the recent recession, Texas has fared better than the national average in job growth and unemployment although there has been some recent softening in job growth, particularly in the Houston area that appears to be related to lower oil prices.

Results of Operations

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



	Year Ended December 31,						Change
	2015		2014		2013		2015/2014			2014/2013
	(In millions, except per share amounts)

Net earnings	$	15.6	$	116.3	$	100.5	$	(100.7	)	$	15.8
Average diluted common and common equivalent shares	80.1		80.3		80.4		(0.2		)	(0.1		)
Net earnings per diluted share	$	0.20	$	1.45	$	1.25	$	(1.25	)	$	0.20

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



	Change
	2015/2014			2014/2013
	(In millions)
PNM	$	(102.6	)	$	(0.8	)
TNMP	4.2			8.7
Corporate and Other	(2.2		)	7.8
Net change	$	(100.7	)	$	15.8

PNMR’s operational results were affected by the following:


•	The $165.7 million pre-tax write-off recorded for regulatory disallowances and restructuring costs due to agreements among the owners of SJGS necessary to bring SJGS into compliance with the CAA and PNM’s related regulatory proceedings (Note 16)


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


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


•	Weather

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•	Reduced rent payments upon renewal of leases for PVNGS Unit 1


•	A refund of amounts previously paid under the FERC tariff for gas transportation agreements and settlement of a complaint filed at FERC against SPS Note 16)


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


•	Changes in other income (deductions), primarily related to gains and losses on available-for-sale securities, a third-party pre-treatment process for coal at SJGS, and equity AFUDC


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


•	Fluctuations in prices for sales of power from PVNGS Unit 3


•	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 have been extended to expire in October 2020. 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 $598.2 million at February 19, 2016. 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 $2,390.1 million for 2016-2020. The construction expenditures include estimated amounts related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16, environmental upgrades at SJGS and Four Corners, 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 2016-2020 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.

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. Also, refer to Disclosure Regarding Forward Looking Statements in Part I, Item 1 and to Risk Factors in Part I, Item 1A.

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PNM

The table below summarizes operating results for PNM:



	Year Ended December 31,									Change
	2015			2014			2013			2015/2014			2014/2013
	(In millions)
Electric operating revenues	$	1,131.2		$	1,147.9		$	1,116.3		$	(16.7	)	$	31.6
Cost of energy	391.1			403.6			374.7			(12.5		)	28.9
Margin	740.1			744.3			741.6			(4.2		)	2.7
Operating expenses	591.0			422.1			428.6			168.9			(6.5		)
Depreciation and amortization	115.7			109.5			103.8			6.2			5.7
Operating income	33.4			212.7			209.2			(179.3		)	3.5
Other income (deductions)	33.5			20.8			21.5			12.7			(0.7		)
Interest charges	(80.0		)	(79.4		)	(79.2		)	(0.6		)	(0.2		)
Segment earnings (loss) before income taxes	(13.1		)	154.1			151.5			(167.2		)	2.6
Income (taxes) benefit	12.8			(52.6		)	(48.8		)	65.4			(3.8		)
Valencia non-controlling interest	(14.9		)	(14.1		)	(14.5		)	(0.8		)	0.4
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings (loss)	$	(15.8	)	$	86.8		$	87.6		$	(102.6	)	$	(0.8	)

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



	Year Ended December 31,							Change
	2015			2014		2013		2015/2014			2014/2013
	(In millions, except customers)
Residential	$	428.0		$	411.4	$	411.6	$	16.6		$	(0.2	)
Commercial	437.3			428.1		415.6		9.2			12.5
Industrial	75.3			73.0		74.6		2.3			(1.6		)
Public authority	26.2			25.3		25.7		0.9			(0.4		)
Economy energy service	35.1			39.1		32.9		(4.0		)	6.2
Transmission	33.2			38.3		38.2		(5.1		)	0.1
Firm-requirements wholesale	31.3			38.3		42.4		(7.0		)	(4.1		)
Other sales for resale	63.2			82.5		67.5		(19.3		)	15.0
Mark-to-market activity	(5.3		)	6.0		0.3		(11.3		)	5.7
Other	6.9			5.9		7.5		1.0			(1.6		)
	$	1,131.2		$	1,147.9	$	1,116.3	$	(16.7	)	$	31.6
Average retail customers (thousands)	514.9			511.2		508.2		3.7			3.0

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The following table shows PNM GWh sales by customer class:



	Year Ended December 31,			Change
	2015	2014	2013	2015/2014		2014/2013
	(Gigawatt hours)
Residential	3,185.4	3,169.1	3,304.3	16.3		(135.2	)
Commercial	3,800.5	3,874.3	3,954.8	(73.8	)	(80.5	)
Industrial	957.3	984.1	1,041.2	(26.8	)	(57.1	)
Public authority	246.5	251.2	266.4	(4.7	)	(15.2	)
Economy energy service ⁽¹⁾	796.4	758.6	719.3	37.8		39.3
Firm-requirements wholesale	444.5	527.6	654.1	(83.1	)	(126.5	)
Other sales for resale	2,110.9	2,271.5	2,061.9	(160.6	)	209.6
	11,541.5	11,836.4	12,002.0	(294.9	)	(165.6	)

⁽¹⁾

PNM purchases energy for a major customer on the customer’s behalf and delivers the energy to the customer’s location through PNM’s transmission system. PNM charges the customer for the cost of the energy as a direct pass through to the customer with no impact to PNM’s margin so there is only a minor impact in margin resulting from providing ancillary services. Although KWh sales to this customer increased in 2015, revenue decreased due to lower market prices.

Operating Results – 2015 Compared to 2014

Operating Revenues, Cost of Energy and Margin – The table below summarizes the significant changes to total revenues, cost of energy, and margin:



	2015/2014 Change
	Total Revenues			Cost of Energy			Margin
	(In millions)
Weather normalized customer usage/load	$	(8.7	)	$	—		$	(8.7	)
Impacts of weather	2.1			—			2.1
Lower transmission margin, primarily resulting from expiration of long-term contracts	(5.4		)	(0.3		)	(5.1		)
Higher FPPAC billings (Note 17)	10.1			10.1			—
Wholesale contracts, primarily due to the expiration of Gallup contract (Note 17)	(6.1		)	(2.7		)	(3.4		)
Rio Bravo purchase and termination of PPA on July 17, 2014 (Note 9)	—			(3.6		)	3.6
Renewable energy rider rate increase, partially offset by the purchase of REC’s and renewable power (Note 17)	10.0			3.7			6.3
Lower market prices of unrealized economic hedges, primarily associated with PVNGS Unit 3	(11.2		)	0.5			(11.7		)
Refund under FERC tariff for gas transportation agreement and SPS settlement (Note 16)	—			(5.4		)	5.4
Off-system and economy energy sales (not included in the FPPAC)	(11.1		)	(10.6		)	(0.5		)
Other	3.6			(4.2		)	7.8
Net change	$	(16.7	)	$	(12.5	)	$	(4.2	)

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Changes in total revenues, cost of energy, and margin are primarily due to:


•	PNM’s weather normalized retail KWh sales were 1.4% lower in 2015 compared to 2014, primarily resulting from a sluggish economy in New Mexico, particularly in the Albuquerque metropolitan area, which has lagged the nation in economic recovery


•	Warmer summer weather and colder winter weather increased revenue in 2015; cooling degree days were 5.7% higher and heating degree days were 2.9% higher in 2015 than in 2014


•	The June 29, 2014 expiration of PNM’s contract with Gallup, its second largest wholesale generation customer, reduced revenues, cost of energy, and margin; these decreases were partially offset by an increase in off-system sales and lower fuel expenses that would have otherwise been used to serve Gallup

•

In January 2015, PNM increased the rate charged under the renewable rider to include PNM-owned solar facilities completed in 2014; cost of energy, which reflects the purchase of RECs and renewable power under PPAs increased in 2015, primarily due to the addition of Red Mesa Wind; increases in revenues and margin for PNM’s renewable rider are partially offset by increases in operating expenses and depreciation

•

In 2015, PNM negotiated new gas transportation agreements with EPNG, resulting in the refund of previously paid gas fixed-transportation costs under the EPNG FERC tariff and establishing new reduced rates through October 31, 2022; this refund decreased the cost of energy and increased margin $4.0 million in 2015; the newly established rates are anticipated to decrease gas transportation costs approximately $0.8 million on an annual basis

Operating expenses – Changes in operating expenses are primarily due to:


•	2015 pre-tax write-off of $165.7 million associated with the BART determination and the ownership restructuring of SJGS discussed in Note 16


•	Higher plant maintenance costs of $8.9 million primarily at SJGS and PVNGS


•	Higher employee medical expenses of $4.6 million, primarily due to unfavorable claims experience, including an unusually high number of large dollar claims


•	Higher costs associated with exploring alternative fuel supply for SJGS of $2.2 million


•	Higher energy efficiency rider program costs and renewable rider costs of $2.3 million and $0.4 million, which are offset in revenues


•	Lower rentals of $16.0 million related to renewal of the PVNGS Unit 1 leases (See Note 7) on January 15, 2015


•	Lower costs of $2.1 million associate with the termination of the EIP lease on April 1, 2015

Depreciation and amortization – The increase in depreciation and amortization expense is primarily due to additions of utility plant in service, including PNM-owned solar PV facilities and the Rio Bravo purchase.

Other income (deductions) – Changes in other income (deductions) are primarily due to:


•	Higher pre-tax gains, net of impairments, of $5.5 million on available-for-sale securities, reflecting performance of the NDT and the trust for coal mine reclamation, partially offset by higher fees and taxes on the NDT of $2.0 million


•	Higher income of $4.0 million from refined coal (a third-party pre-treatment process, which began November 2014) at SJGS


•	Higher equity AFUDC of $5.0 million due to increased levels of construction

Interest charges – Interest charges increased in 2015 compared to 2014 primarily due to higher costs of borrowing for the $250.0 million Senior Unsecured Notes issued on August 11, 2015 Note 6 compared to the debt paid off with the proceeds of that offering, partially offset by higher debt AFUDC.

Income taxes – Income taxes decreased primarily due to the effects of the pretax loss in 2015. The extension of bonus depreciation for income tax purposes reduces anticipated future taxable income, which resulted in impairments of New Mexico net operating loss carryforwards of $3.6 million in 2015 and $2.1 million in 2014. Income tax expense in 2015 also includes $1.8 million due to the reversal of certain deferred tax items related to the BART determination for SJGS. See Note 11. Equity AFUDC is recorded in other income (deductions), but is not included in income for income tax purposes. The impacts of this permanent difference reduced income tax expense by $1.7 million in 2015 compared to 2014.

Operating Results – 2014 Compared to 2013

Operating Revenues, Cost of Energy and Margin – The table below summarizes the significant changes to total revenues, cost of energy, and margin:

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	2014/2013 Change
	Total Revenues			Cost of Energy			Margin

Weather normalized customer usage/load	$	(10.9	)	$	—		$	(10.9	)
Impacts of weather	(11.0		)	—			(11.0		)
Transmission rate increases in August 2013 and May 2014 (Note 17)	2.0			0.9			1.1
FPPAC billings (Note 17)	23.0			23.0			—
Wholesale contracts, primarily due to the expiration of Gallup contract (Note 17)	(1.2		)	(1.6		)	0.4
Rio Bravo purchase and termination of PPA on July 17, 2014 (Note 9)	—			(3.3		)	3.3
Renewable energy rider rate increase, partially offset by the purchase of REC’s and renewable power (See Note 17)	10.2			3.7			6.5
Higher market prices of unrealized economic hedges, primarily associated with PVNGS Unit 3	5.7			1.1			4.6
Off-system and economy energy sales (not included in the FPPAC)	2.1			4.7			(2.6		)
Higher unregulated margin	5.3			(1.8		)	7.1
Other	6.4			2.2			4.2
Net change	$	31.6		$	28.9		$	2.7

Changes in total revenues, cost of energy, and margin are primarily due to:


•	PNM’s weather normalized retail KWh sales were 1.7% lower in 2014 compared to 2013, primarily due to New Mexico’s sluggish economy


•	Milder weather decreased revenue in 2014; cooling degree days were 7.4% lower and heating degree days were 12.7% lower in 2014 than in 2013


•	The expiration of PNM’s contract with Gallup on June 29, 2014 reduced revenues, cost of energy, and margin; these decreases were partially offset by an increase in off-system sales and lower fuel expenses that would have otherwise been used to serve Gallup; a new wholesale contract with the Jicarilla Apache Nation increased revenues and margin in 2014 by $1.0 million


•	In January 2014, PNM increased the rate charged under the renewable rider to include PNM-owned solar facilities completed in 2013; cost of energy reflects increased purchase of RECs and renewable power under PPAs; increases in revenues and margin for PNM’s renewable rider are partially offset by increases in operating expenses and depreciation


•	Higher market prices combined with higher available generation associated with PVNGS Unit 3 increased unregulated revenues by $5.3 million in 2014; gas imbalance settlements in 2014, which did not occur in 2013, lowered cost of energy $2.1 million

Operating expenses – Changes in operating expenses are primarily due to:


•	PNM recorded a $10.5 million regulatory disallowance of the FPPAC under-collected balance in 2013, which did not occur in 2014 (See Note 17)


•	PNM made contributions of $3.3 million in 2013 to the PNM Resources Foundation and Good Neighbor Fund, which did not occur in 2014


•	Lower labor and employee benefit costs of $2.4 million and $0.6 million


•	Higher capitalization of administrative and general expenses, which decreases operating expenses, of $2.7 million due to higher capital spending in 2014.


•	Increase plant maintenance costs of $6.1 million, primarily at Four Corners, PVNGS, and PNM’s natural gas plants


•	Higher energy efficiency rider program costs and higher renewable rider costs of $3.2 million and $0.4 million, which are offset in revenue.


•	Higher property taxes of $2.4 million due to increased plant in service and higher assessed values

Depreciation and amortization – Depreciation and amortization expense increased primarily due to additions to utility plant in service, including PNM-owned solar PV facilities and the Rio Bravo purchase.

Other income (deductions) – Other income (deductions) decreased primarily due to lower interest income on the PVNGS lessor notes reflecting lower outstanding balances.

Interest charges – Interest charges increased primarily due to interest costs associated with the construction of PNM-owned solar PV facilities.

Income taxes – Income taxes increased primarily due to the effects of higher pretax income in 2014. The Company also 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.

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TNMP

The table below summarizes the operating results for TNMP:



	Year Ended December 31,									Change
	2015			2014			2013			2015/2014			2014/2013
	(In millions)
Electric operating revenues	$	307.9		$	287.9		$	271.6		$	20.0		$	16.3
Cost of energy	73.5			67.9			57.6			5.6			10.3
Margin	234.4			220.0			214.0			14.4			6.0
Operating expenses	88.1			84.4			91.6			3.7			(7.2		)
Depreciation and amortization	56.3			50.1			50.2			6.2			(0.1		)
Operating income	90.0			85.6			72.2			4.4			13.4
Other income (deductions)	3.7			2.1			1.9			1.6			0.2
Interest charges	(27.7		)	(27.4		)	(27.4		)	(0.3		)	—
Segment earnings before income taxes	66.1			60.3			46.7			5.8			13.6
Income (taxes)	(24.1		)	(22.5		)	(17.6		)	(1.6		)	(4.9		)
Segment earnings	$	42.0		$	37.8		$	29.1		$	4.2		$	8.7

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



	Year Ended December 31,						Change
	2015		2014		2013		2015/2014		2014/2013
	(In millions, except customers)
Residential	$	120.8	$	114.8	$	111.3	$	6.0	$	3.5
Commercial	103.0		99.7		95.1		3.3		4.6
Industrial	16.3		15.0		13.1		1.3		1.9
Other	67.8		58.4		52.1		9.4		6.3
	$	307.9	$	287.9	$	271.6	$	20.0	$	16.3
Average consumers (thousands) ⁽¹⁾	241.6		238.2		235.1		3.4		3.1


⁽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 consumer class:



	Year Ended December 31,			Change
	2015	2014 ⁽¹⁾	2013 ⁽¹⁾	2015/2014		2014/2013
	(Gigawatt hours)
Residential	2,912.0	2,802.8	2,796.7	109.2		6.1
Commercial	2,654.1	2,583.7	2,472.9	70.4		110.8
Industrial	2,804.9	2,708.2	2,576.8	96.7		131.4
Other	101.0	102.1	104.5	(1.1	)	(2.4	)
	8,472.0	8,196.7	7,950.9	275.2		245.9


⁽¹⁾	The 2014 and 2013 GWh amounts reflect a reclassification of 18.9 GWh and 21.7 GWh from industrial to commercial to be consistent with the current year presentation.

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Operating results – 2015 compared to 2014

Operating Revenues, Cost of Energy and Margin – The table below summarizes the significant changes to total revenues, cost of energy, and margin:



	2015/2014 Change
	Total Revenues			Cost of Energy		Margin
	(In millions)
Transmission cost of service rate increases in March and September of 2015 and 2014 (See Note 17)	$	8.0		$	—	$	8.0
Weather normalized customer usage/load	2.0			—		2.0
Customer growth of 1.5% in 2015	1.0			—		1.0
Impacts of weather	(0.2		)	—		(0.2		)
Recovery of third-party transmission costs	5.6			5.6		—
Higher AMS surcharge revenues due to increased AMS deployment which are offset in O&M (See Note 17)	4.9			—		4.9
Lower energy efficiency incentive in 2015 (See Note 17)	(0.8		)	—		(0.8		)
Other	(0.5		)	—		(0.5		)
Net change	$	20.0		$	5.6	$	14.4

Changes in total revenues, cost of energy, and margin are primarily due to:


•	The Texas economy has fared better than the national average in job growth and unemployment growth, increasing weather normalized retail KWh sales 2.6% in 2015; the weather normalized load impacts are primarily related to the residential class


•	Weather had minimal impacts on margin as heating degree days were 12.2% lower and cooling degree days were 6.4% higher than in 2014; 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


•	Changes in costs charged by third-party transmission providers are deferred and recovered through a transmission cost recovery factor; higher third party transmission costs of energy resulted in, and are offset by, TNMP rate increases for the recovery of these costs

Operating expenses – Changes in operating expenses are primarily due to:


•	Increased employee medical expenses of $2.4 million, due primarily to unfavorable claims experience, including an unusually high number of large dollar claims


•	Increased property taxes of $1.4 million, due primarily to increases in utility plant in service and higher assessed values


•	Higher operating expenses of $1.1 million associated with the AMS deployment, which are recovered through the AMS surcharge


•	Higher capitalization of administrative and general expenses of $0.9 million decreased operating expenses due to the mix of transmission and distribution construction expenditures

Depreciation and amortization – Depreciation and amortization expense increased in 2015 primarily due to $2.9 million from greater AMS deployment, $2.5 million from other increases in utility plant in service, and $0.8 million from increased amortization of the CTC regulatory asset.

Other income (deductions) – Other income (deductions) increased in 2015 due primarily to an increase in contributions in aid of construction.

Interest charges – Interest charges increased in 2015 primarily due to the issuance of $80.0 million of long-term debt on June 27, 2014, partially offset by the maturity of $50.0 million of long-term debt on June 30, 2014.

Income taxes – Income taxes increased in 2015 primarily due to higher pretax income in 2015.

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Operating results – 2014 compared to 2013

Operating Revenues, Cost of Energy and Margin – The table below summarizes the significant changes to total revenues, cost of energy, and margin:



	2014/2013 Change
	Total Revenues			Cost of Energy		Margin

Transmission cost of service rate increases in March and September of 2014 and 2013 (See Note 17)	$	6.3		$	—	$	6.3
Weather normalized customer usage/load	0.5			—		0.5
Customer growth of 1.3% in 2014	1.7			—		1.7
Impacts of weather	(2.0		)	—		(2.0		)
Recovery of third-party transmission costs	10.3			10.3		—
Higher AMS surcharge revenues due to increased AMS deployment (See Note 17)	4.0			—		4.0
Lower Hurricane Ike surcharge revenues due to termination of surcharge upon full recovery of associated costs in November 2013	(4.8		)	—		(4.8		)
Higher energy efficiency incentive in 2014 (See Note 17)	0.8			—		0.8
Other	(0.5		)	—		(0.5		)
Net change	$	16.3		$	10.3	$	6.0

Changes in total revenues, cost of energy, and margin are primarily due to:


•	A strong Texas economy helped increase weather normalized retail KWh sales 3.2% in 2014, primarily related to the commercial class


•	Milder weather in the summer decreased revenues as cooling degree days were 2.2% lower and heating degree days were 2.0% higher than in 2014


•	Higher costs charged by third-party transmission providers, which are deferred and recovered through a transmission cost recovery factor


•	Changes in AMS and Hurricane Ike surcharge revenues are offset in operating expenses and depreciation and amortization

Operating expenses – Changes in operating expenses are primarily due to:


•	Higher capitalization of administrative and general expenses, which decreases operating expenses, of $2.9 million due higher capital spending in 2014


•	Lower employee healthcare costs of $2.1 million primarily due to lower claims experience


•	2013 write-off of $0.5 million in costs incurred in an effort to securitize the remaining CTC costs


•	2013 contributions to the PNM Resources Foundation of $0.7 million


•	Lower energy efficiency program expenses of $0.3 million and lower rate case expense amortization of $0.7 million

Depreciation and amortization – Depreciation and amortization expense decreased primarily due to $4.7 million lower amortization of the Hurricane Ike regulatory asset, which was offset by higher depreciation expense of $1.6 million due to an increase in utility plant in service, $2.2 million increase from greater AMS deployment, and $0.7 million from higher CTC amortization.

Other income (deductions) – Other income (deductions) increased primarily due to an increase in contributions in aid of construction.

Income taxes – Income taxes increased primarily to higher pretax income in 2014.

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Corporate and Other

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



	Year Ended December 31,									Change
	2015			2014			2013			2015/2014			2014/2013
				(In millions)
Electric operating revenues	$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—
Margin	—			—			—			—			—
Operating expenses	(14.9		)	(14.5		)	(18.3		)	(0.4		)	3.8
Depreciation and amortization	13.9			13.1			12.8			0.8			0.3
Operating income	0.9			1.4			5.5			(0.5		)	(4.1		)
Other income (deductions)	(0.6		)	(2.4		)	(13.7		)	1.8			11.3
Interest charges	(7.2		)	(12.8		)	(14.9		)	5.6			2.1
Segment earnings (loss) before income taxes	(6.9		)	(13.8		)	(23.1		)	6.9			9.3
Income (taxes) benefit	(3.7		)	5.4			6.9			(9.1		)	(1.5		)
Segment earnings (loss)	$	(10.6	)	$	(8.4	)	$	(16.2	)	$	(2.2	)	$	7.8

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. Depreciation expense increases are primarily due to additions of computer software. Substantially all depreciation and amortization expense is offset in operating expenses as a result of allocation of these costs to other business segments.

Operating results – 2015 compared to 2014

Other income (deductions) – Other income (deductions) increases primarily due to the $3.1 million impact of PNMR Development’s share of the fee resulting from the ownership restructuring of SJGS, which was recorded at December 31, 2015 (Note 16. This was partially offset by the 2015 write off of $1.1 million for investments related to a former PNMR subsidiary, which ceased operations in 2008.

Interest charges – Interest charges decreased in 2015 primarily due to the maturity of PNMR’s $118.8 million of 9.25% Senior Unsecured Notes Series A on May 15, 2015 partially offset by PNMR’s new $150.0 million Term Loan Agreement entered into on March 9, 2015. A decrease in overall short-term borrowings and lower interest rates also reduced interest expense.

Income taxes – The increase in income taxes (benefit) reflects changes in income before income taxes. The extension of bonus depreciation for income tax purposes reduces anticipated future taxable income, which resulted in impairments of the deferred tax assets recorded for New Mexico net operating loss, New Mexico wind energy production tax credit, and charitable contribution carryforwards aggregating $6.8 million and $1.9 million in 2015 and 2014 Note 11. The settlement of an IRS examination in 2014 which resulted in an income tax benefit of $1.3 million also contributed to the increase.

Operating results – 2014 compared to 2013

Operating expenses - Operating expenses decreased in 2014 primarily due to the allocation of $4.0 million of the Company’s 2013 contributions to the PNM Resources Foundation and financial support to the PNM Good Neighbor Fund, recorded in other income (deductions), which did not recur in 2014.

Other income (deductions) – Changes in other income (deductions) are primarily due to:


•	Increase due to the $4.0 million contribution in 2013 to the PNM Resources Foundation and financial support to the PNM Good Neighbor Fund, which were allocated to PNM and TNMP reducing operating expenses as discussed above


•	Increase due to 2013 losses of $3.3 million on the repurchase of $23.8 million of PNMR’s 9.25% senior unsecured notes (Note 6)


•	Increase due to $3.6 million lower amortization related to corporate investments that became fully amortized in 2013

Interest charges – Interest charges decreased in 2014 primarily due to the repurchase of $23.8 million of 9.25% senior unsecured notes in 2013, as well as a decrease in overall short-term borrowings and lower interest rates.

Income taxes – Income taxes decreased in 2014 compared to 2013 primarily due to the settlement of an IRS examination in 2014 which resulted in an income tax benefit of $1.3 million. An additional income tax expense of $1.1 million reflected in the PNM segment offsets this amount.

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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
	2015			2014			2013			2015/2014			2014/2013
	(In millions)
Net cash flows from:
Operating activities	$	386.9		$	414.9		$	386.6		$	(28.0	)	$	28.3
Investing activities	(544.5		)	(485.3		)	(331.4		)	(59.2		)	$	(153.9	)
Financing activities	175.4			96.2			(61.6		)	79.2			157.8
Net change in cash and cash equivalents	$	17.8		$	25.7		$	(6.5	)	$	(8.0	)	$	32.2

Changes in PNMR’s cash flows from operating activities result from net earnings, adjusted for items impacting earnings that do not provide or use cash. See Results of Operations above. Certain changes in assets and liabilities resulting from normal operations also impact operating cash flows. Cash flows from operating activities also increased $55.4 million in 2015 compared to 2014 related to the collection of amounts under PNM’s FPPAC, primarily resulting from the cap on amounts passed through to ratepayers prior to June 30, 2014. In addition, PNMR received income tax refunds of $1.9 million in 2015 and $2.6 million in 2014 compared to refunds received of $95.3 million in 2013. PNMR made contributions to the PNM and TNMP pension and other postretirement benefit plans of $35.5 million in 2015 compared to $5.4 million in 2014 and $66.5 million in 2013. 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.

The changes in PNMR’s cash flows from investing activities relate primarily to increases in plant additions of $97.9 million in 2015 compared to 2014 and $112.6 million in 2014 compared to 2013. At PNM, total utility plant additions were $88.0 million higher in 2015 compared to 2014, including increased generation additions of $47.0 million, renewable additions of $34.4 million, transmission and distribution additions of $3.8 million, and nuclear fuel purchases of $2.8 million. 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. TNMP utility plant additions decreased $2.6 million in 2015 compared to 2014, including decreases in transmission additions of $17.6 million and AMS additions of $4.9 million offset by an increase in distribution additions of $16.1 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. Corporate and other plant additions were $12.5 million higher in 2015 compared to 2014, including PNMR Development utility plant additions of $8.2 million and computer hardware and software additions of $4.3 million. Corporate and other plant additions decreased by $2.3 million in 2014 compared to 2013 related to computer hardware and software additions. Construction expenditures were funded primarily through cash flows from operating activities and short-term borrowings. Investing activities includes $2.6 million from the sale of Gallup assets in 2015 and $36.2 million for the acquisition of Rio Bravo in 2014 as discussed in Note 9.

The changes in PNMR’s cash flows from financing activities include an increase in net short-term borrowings of $188.6 million in 2015 compared to 2014. Long-term borrowings in 2015 include the $150.0 million PNMR 2015 Term Loan Agreement and $25.0 million of additional long-term borrowings under the PNM Multi-draw Term Loan. PNMR used portions of the proceeds to repay $118.8 million of 9.25% Senior Unsecured Notes, Series A, that matured on May 15, 2015. In addition, PNM issued $250.0 million aggregate principal amounts of its 3.850% Senior Unsecured Notes due 2025. PNM used the proceeds to repay the $175.0 million PNM 2014 Term Loan Agreement and other outstanding short-term borrowings, including PNM’s intercompany loan from PNMR. In 2015, PNM also successfully remarketed $39.3 million of PCRBs. In 2014, PNMR’s cash flows from financing activity also include a reduction in net short-term borrowings of $34.1 million compared to 2013. 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 PNM 2013 Term Loan Agreement. In addition, $13.0 million was paid in connection with TNMP’s debt exchange and $26.9 million was paid by PNMR to repurchase $23.8 million of its outstanding 9.25% Senior Unsecured Notes, Series A, due 2015, in 2013.

Financing Activities

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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


•	Conditions in the financial markets


•	Credit ratings

On March 9, 2015, PNMR entered into the $150.0 million PNMR 2015 Term Loan Agreement. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.22% at December 31, 2015, and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants and conditions. PNMR utilized a portion of the proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility to retire the $118.8 million of 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927% for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018.

On August 11, 2015, PNM issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. The notes will mature on August 1, 2025. Portions of the proceeds from the offering were used to repay the existing $175.0 million PNM 2014 Term Loan Agreement and to repay outstanding borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and PNM’s intercompany loan from PNMR.

On December 17, 2015 TNMP entered into an agreement, which provided that TNMP would issue $60.0 million aggregate principal amount of 3.53% first mortgage bonds, due 2026, on or about February 10, 2016. TNMP issued the Series 2016A Bonds on February 10, 2016 and used the proceeds to reduce short-term debt and intercompany debt.

On December 21, 2015, PNMR amended and restated the $100.0 million PNMR Term Loan Agreement by entering into the PNMR Third Amended and Restated Term Loan Agreement that increased the amount of the loan to $150.0 million and extended its maturity to December 21, 2016.

PNMR, PNM, and TNMP are subject to debt-to-capital ratio requirements of less than or equal to 65%. These ratios for PNMR and PNM include the present value of payments under the PVNGS leases as debt. At December 31, 2015, interest rates on outstanding borrowings were 1.26% for the PNMR Term Loan Agreement, 1.22% for the PNMR 2015 Term Loan Agreement, and 0.99% for the PNM Multi-draw Term Loan.

As discussed in Note 16, NM Capital, a wholly owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as Administrative Agent, as of February 1, 2016. The BTMU Term Loan Agreement has a maturity date of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million to a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC.

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

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Projected capital requirements for 2016-2020 are:



	2016		2017-2020		Total
	(In millions)
Construction expenditures	$	546.8	$	1,490.2	$	2,037.0
Dividends on PNMR common stock	70.1		280.4		350.5
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	617.4	$	1,772.7	$	2,390.1

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 $100.8 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 16, environmental upgrades of $3.0 million at SJGS and $88.7 million at Four Corners, and the January 2016 purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases for $163.3 million. Expenditures for environmental upgrades are estimated to be $46.9 million in 2016. 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, 2015, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and the additional borrowings described under Financing Activities above.

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 $118.8 million of 9.25% Senior Unsecured Notes, Series A matured and were repaid on May 15, 2015; $39.3 million of PNM’s PCRBs were subject to mandatory tender for remarketing on June 1, 2015 (the bonds were remarketed on that date and are next subject to mandatory tender for remarketing on June 1, 2020); the $175.0 million PNM 2014 Term Loan Agreement was repaid on August 12, 2015; and the $125.0 million PNM Multi-draw Term Loan matures on June 21, 2016. Note 6 contains additional information about the maturities of long-term debt. Also, the one-year $150.0 million PNMR Term Loan Agreement matures on December 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 both of which have been extended to expire in October 2020 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. PNM also has 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 $45.3 million during the year ended December 31, 2015, zero to $21.1 million during the year ended December 31, 2014, and zero to $84.0 million during the year ended December 31, 2013. Such borrowings ranged from zero to $45.3 million during the three months ended December 31, 2015. Borrowings under the PNM Revolving Credit Facility ranged from zero to $48.4 million during the year ended December 31, 2015, zero to $82.0 million during the year ended December 31, 2014, and zero to $130.8 million during the year ended December 31, 2013. Such borrowings ranged from zero to $32.2 million during the three months ended December 31, 2015. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $20.0 million during the year ended December 31, 2015 and zero to $25.0 million during the year ended December 31, 2014. There were no such borrowings in 2013 or during the three months ended December 31, 2015. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $64.0 million during the year ended December 31, 2015,

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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. Such borrowings ranged from $12.0 million to $64.0 million during the three months ended December 31, 2015. At December 31, 2015, the interest rates on outstanding borrowings were 1.67% for the PNMR Revolving Credit Facility and 1.29% 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, 2015.

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 2016-2020 period. This could include new debt issuances and/or new equity.

As discussed above, PNMR retired the 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015, which results in PNMR having no senior unsecured notes outstanding. Following this repayment, Moody’s and S&P withdrew their ratings of PNMR senior unsecured debt. On June 22, 2015, Moody’s assigned an issuer rating of Baa3 to PNMR, upgraded the issuer rating of TNMP to A3 from Baa1, upgraded the senior secured debt rating of TNMP to A1 from A2, and changed the outlook for PNMR, PNM, and TNMP to stable from positive. On December 21, 2015, S&P raised by one notch the issuer credit ratings for PNMR, PNM, and TNMP and the debt ratings for PNM and TNMP, with a stable outlook. 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 19, 2016, ratings on the Company’s securities were as follows:



	PNMR	PNM	TNMP
S&P
Corporate rating	BBB+	BBB+	BBB+
Senior secured debt	*	*	A
Senior unsecured debt	*	BBB+	*
Preferred stock	*	BBB-	*
Moody’s
Issuer rating	Baa3	Baa2	A3
Senior secured debt	*	*	A1
Senior unsecured debt	*	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 19, 2016 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 19, 2016:
Revolving credit facility	$	66.1	$	46.2	$	15.0	$	127.3
PNM New Mexico Credit Facility	—		50.0		—		50.0
Letters of credit	46.2		3.2		0.1		49.5
Total short term-debt and letters of credit	112.3		99.4		15.1		226.8
Remaining availability as of February 19, 2016	$	187.7	$	350.6	$	59.9	$	598.2
Invested cash as of February 19, 2016	$	1.9	$	—	$	—	$	1.9

The above table includes a $40.0 million letter of credit issued under the PNMR Revolving Credit Facility to facilitate the posting of reclamation bonds by a surety in connection with the purchase of SJCC by a subsidiary of Westmoreland from BHP. See Note 16. The above table excludes intercompany debt. As of February 19, 2016, TNMP had $15.1 million in intercompany borrowings from PNMR. 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.

PNMR can offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2018. PNM has a shelf registration statement for up to $250.0 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, until April 1, 2015, 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 extended the leases through January 15, 2023 from their original expiration on January 15, 2015. In addition, PNM entered into an amendment with the lessor under one of the PVNGS Unit 2 leases that extended that lease through January 15, 2024 from its original expiration on January 15, 2016. PNM entered into agreements with the lessors under the other three PVNGS Unit 2 leases under which PNM exercised 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 for 2016 shown below for the PVNGS leases have been reduced by $9.0 million returned to PNM through its ownership in related lessor notes and include the renewals described above.



	PVNGS Units 1&2
	(In thousands)
2016	$	20,589
2017	18,139
2018	18,139
2019	18,139
2020	18,139
Thereafter	46,985
Total	$	140,130

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. Prior to April 1, 2015, PNM owned 60% and operated the other 40% of the EIP line under the terms of a lease agreement. The lease, which contained fixed-rate and fair market value renewal options and a fair market value purchase option, expired on April 1, 2015. PNM exercised 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, 2015. See Note 7 for further details about the Company’s significant leases:



	Payments Due
Contractual Obligations	2016		2017-2018		2019-2020		2021 and Thereafter		Total
	(In thousands)
Long-term debt (a)	$	125,000	$	657,025	$	272,647	$	1,031,698	$	2,086,370
Interest on long-term debt (b)	113,556		214,133		115,973		637,407		1,081,069
Operating leases (c)	29,825		51,311		50,387		108,990		240,513
Transmission reservation payments	14,166		23,408		6,171		11,084		54,829
Coal contracts (d)	74,243		101,026		67,514		409,351		652,134
Coal mine decommissioning (e)	9,674		15,640		7,229		184,627		217,170
Nuclear decommissioning funding requirements (f)	2,637		5,274		5,274		8,614		21,799
Outsourcing	4,947		3,527		—		—		8,474
Pension and retiree medical (g)	5,452		10,842		10,736		—		27,030
Construction expenditures (h)	546,818		812,744		677,395		—		2,036,957
Total (i)	$	926,318	$	1,894,930	$	1,213,326	$	2,391,771	$	6,426,345


(a)	Represents total long-term debt, excluding unamortized discounts, premiums, and issuance costs (Note 6); does not include NM Capital’s $125.0 million BTMU Term Loan Agreement entered into on February 1, 2016 and TNMP’s $60.0 million of 3.53% first mortgage bonds issued on February 10, 2016, as discussed above


(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 renewed; the amounts in the above table are net of amounts returned to PNM in 2016 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 in effect on December 31, 2015 if no deliveries are made; under the CSA to supply coal to SJGS, which became effective at 11:59 PM on January 31, 2016, the minimum payments increased by between $76 million and $96 million per year in 2016 through 2020 and by a total of $84 million for 2021 through 2032

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(e)	Includes funding of trusts for post-term reclamation related to the mines serving SJGS and Four Corners (Note 16)


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


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

(h)

Represents forecasted construction expenditures, including nuclear fuel, under which substantial commitments have been made (Note 14); the Company only forecasts capital expenditures for the next five years; the construction expenditures include the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases on January 15, 2016 for $163.3 million; 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 and, therefore, PNMR’s liability of $6.5 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, as discussed in 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 Company’s term loans, 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. Note 16 discusses circumstances under the Bond Reclamation Agreement that could obligate PNMR to provide additional collateral to the surety in connection with the reclamation bonds posted by the surety in connection with the purchase of SJCC by Westmoreland.

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	2015		2014
PNMR common equity	44.0	%	46.6	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	55.7	%	53.1	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	45.3	%	45.8	%
Preferred stock	0.4	%	0.4	%
Long-term debt	54.3	%	53.8	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	59.6	%	59.2	%
Long-term debt	40.4	%	40.8	%
Total capitalization	100.0	%	100.0	%

As discussed in Note 6, the Company adopted a new accounting standard during 2015 that required debt issuance costs, which were previously included in other deferred charges on the Consolidated Balance Sheets, to be reclassified as a reduction of the related long-term debt. The change was applied retroactively, which reduced the long-term debt portion of capitalization in 2014. The above table reflects changes to increase the common equity percentage and decrease the long-term percentage by 0.2% for PNMR, 0.1% for PNM, and 0.3% for TNMP from those previously shown for 2014.

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2015, GHG associated with PNM’s interests in its generating plants included approximately 6.4 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG. By comparison, the total GHG in the United States in 2013, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.5 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 2015, PNM completed construction of 40 MW of utility-scale solar generation, bringing its total solar generation capacity to 107 MW. 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 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 geothermal facility is 4 MW and future expansion may result in up to 9 MW of generation capacity. Additionally, PNM has a customer distributed solar generation program that represented 49.5 MW at December 31, 2015. PNM’s 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 budget of $25.8 million for the program year beginning in June 2015. PNM estimates these programs saved approximately 79 GWh of electricity in 2015. Over the next 18 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 9,000 GWh of electricity, which will avoid at least 5.5 million metric tons of CO₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships 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

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of the Company’s practices and procedures to assess the sustainability impacts of operations on the environment. The Board considers associated issues around climate change, the Company’s GHG exposures, and the financial consequences that might result from potential federal and/or state regulation of GHG.

As of December 31, 2015, approximately 70.2% 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, PNM received approval to shutdown SJGS Units 2 and 3 on December 31, 2017 as part of its strategy to address the regional haze requirements of the CAA. The shutdown of Units 2 and 3 would result in a reduction of GHG for the entire station of approximately 50%, including a reduction of approximately 28% for the Company’s ownership interests. 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.

Because of PNM’s dependence on fossil-fueled generation, 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. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal-fired generating plants. Water shortage sharing agreements are in place with the more senior water rights holders to mutually share the impacts of water shortages although no shortage has been declared due to sufficient precipitation in the San Juan River basin. These agreements have been extended through 2016. PNM’s service areas also experience periodic high winds, forest fires, and severe thunderstorms. 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. Climate changes are generally not expected to have material consequences to the Company in the near-term.

EPA Regulation

In April 2007, the USSC 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 the construction of new emission units that emit GHG of at least 100,000 tons per year in CO₂ equivalents (even if PSD is not triggered for other pollutants). In addition, modifications at existing major-emitting facilities that increase GHG by at least 75,000 tons per year in CO₂ equivalents 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 court case in 2014 now limits 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 USSC granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The USSC 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 Title V permitting programs. The

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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 USSC issued its opinion on the above case. The USSC largely reversed the D.C. Circuit. First, the USSC 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 USSC rejected this argument. Third, the USSC found EPA lacked authority to “tailor” the CAA’s unambiguous numerical thresholds of 100 or 250 tons per year. Fourth, the USSC 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 USSC said that EPA needed to establish a de minimis level below which BACT would not be required for “anyway” sources.

On June 25, 2013, President Obama announced his 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 issuance of carbon pollution standards for new sources under Section 111(b) and for existing sources under Section 111(d) of the CAA. On August 3, 2015, EPA issued its final standards to limit CO₂ emissions from power plants. The final rule was published on October 23, 2015. Three separate but related actions took place: (1) the final Carbon Pollution Standards for new, modified, and reconstructed power plants were established (under Section 111(b)); (2) the final Clean Power Plan was issued to set standards for carbon emission reductions from existing power plants (under Section 111(d)); and (3) a proposed federal plan associated with the final Clean Power Plan was released.

EPA’s final rule to limit GHG emissions from new, modified, and reconstructed power establishes standards based upon certain, specific conditions. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA finalized a standard of 1,000 lb CO₂/MWh-gross based on efficient natural gas combined cycled technology as the best system of emissions reductions (“BSER”). Alternatively, owners and operators of base load natural gas-fired combustion turbines may elect to comply with a standard based on an output of 1,030 lb CO₂/MWh-net. A new source is any newly constructed fossil fuel-fired power plant that commenced construction after January 8, 2014.

The final standards for coal-fired power plants vary depending on whether the unit is new, modified, or reconstructed. The BSER for new steam units is a supercritical pulverized coal unit with partial carbon capture and storage. Based on that technology, new coal-fired units will be required to meet an emissions standard equal to 1,400 lbs CO₂/MWh from the beginning of the power plant’s life. The BSER for modified units is based on each affected unit’s own best potential performance. Standards will be in the form of an emission limit in pounds of CO₂ per MWh, which will apply to units with modifications resulting in an increase of hourly CO₂ emissions of more than 10% relative to the emissions of the most recent five years from that unit. The BSER for reconstructed coal-fired power units is the performance of the most efficient generating technology for these types of units. Final emissions standards depend on heat input. Sources with heat input greater than 2,000 MMBTU/hour would be required to meet an emission limit of 1,800 lbs CO₂/MWh-gross, and sources with a heat input of less than or equal to 2,000 MMBTU/hour would be required to meet an emission limit of 2,000 lbs CO₂/MWh-gross.

The final Clean Power Plan rule changed significantly in structure from the proposed rule that was released in June 2014. Changes include delaying the first compliance date by two years from 2020 to 2022; adopting a new approach to calculating the emission targets which resulted in different state goals than those originally proposed; adding a reliability safety valve; and proposing rewards for early reductions. The rule establishes two numeric “emission standards” - one for “fossil-steam” units (coal- and oil-fired units) and one for natural gas-fired units (combined cycle only). The emission standards are based on emission reduction opportunities that EPA deemed achievable using technical assumptions for three “building blocks:” efficiency improvements at coal-fired EGUs, displacement of affected EGUs with renewable energy, and displacement of coal-fired generation with natural gas-fired generation. The final standards are 1,305 lb/MWH for fossil-steam units and 771 lb/MWH for gas units, both of which

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phase in over the period 2022-2030. To facilitate implementation, EPA converted the emission standards into state goals. Each state’s goal reflects the average state-wide emission rate that all of the state’s affected EGUs would meet in the aggregate if each one achieved the emission standards alone based upon a weighted average of each state’s unique mix of affected units.

Under the final rule, states are required to make initial plan submissions to EPA by September 6, 2016. EPA will grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans are due by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. Plans using state measures may only be used with mass-based goals and must include “backstop” federally enforceable standards for EGUs that will become effective if the state measures fail to achieve the expected level of emission reductions.

The Clean Power Plan also proposes a Clean Energy Incentive Program designed to award credits for early development of certain renewable energy and energy efficiency programs that displace fossil generation in 2020 and 2021 prior to the compliance obligation taking effect in 2022. In addition, the Clean Power Plan contains a reliability safety valve for individual power plants. The reliability safety valve allows for a 90-day relief from CO₂ emissions limits if generating units need to continue to operate and release excess emissions during emergencies that could compromise electric system reliability.

As discussed above, EPA issued a proposed Federal Plan in association with the Clean Power Plan. Under Section 111(d), EPA is authorized to issue a federal plan for states that do not submit an approvable state plan. EPA indicates that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explains in its communications that the proposed Federal Plan will be released in advance of the deadline for submission of state plans to provide regulatory certainty to states that fail to submit approvable plan. The proposed Federal Plan will apply emission reduction obligations directly on affected EGUs. The plan presents two approaches: a rate-based emissions trading program and a mass-based emissions trading program. EPA indicates that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule will offer both approaches for states to use as models in their own plans. EPA asked for comments on the proposed Federal Plan by January 21, 2016. PNM submitted comments in response. EPA intends to finalize both the rate-based and mass-based model trading rules in summer 2016.

Multiple states, utilities, and trade groups have filed petitions for review and motions to stay in the D.C. Circuit. On January 21, 2016, the D.C. Circuit denied the motions to stay the EPA’s section 111(d) rule (the Clean Power Plan). It did, however, expedite briefing in the case and set it for oral argument on June 2, 2016. Under the court’s order, the parties were required to submit a proposed briefing format to the court by January 27, 2016, which ensures that briefing on all issues is completed by April 22, 2016. Petitioners had asked for bifurcated briefing that would allow the core legal issues to be litigated first and the programmatic issues related to the rule to be litigated later depending on the outcome of the litigation. The court denied that request.

On January 26, 2016, 29 states and state agencies filed a petition to the USSC asking the court to reverse the D.C. Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the USSC granted the applications to stay the Clean Power Plan pending judicial review of the rule. The USSC issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the USSC Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. If the rule prevails through the legal challenges, states will be able to resume preparing state plans where they left off and should still have six more months to prepare initial plans and two-and- a-half years for final plans. The D.C. Circuit will hear oral arguments on the merits of the states’ case on June 2, 2016. A final ruling from that court might not come for months. The stay will remain in effect pending USSC review if such review is sought.

If the Clean Power Plan prevails, the rule will impact PNM’s existing and future fossil-fueled EGUs. The Carbon Pollution Standards covering new sources will also impact PNM’s generation fleet. Impacts could involve investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at the fossil-fueled EGUs. Under an emissions rate or mass based trading program, PNM may be required to purchase credits or allowances to comply with New Mexico’s final state plan. 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. The only 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. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of purchasing carbon credits or allowances, making improvements, or installing new technology could impact the economic viability of some plants. PNM estimates that implementation of the RSIP for BART at SJGS that required the installation of SNCRs on Units 1 and 4 by early 2016, which has been completed, and the retirement of SJGS Units 2 and 3 by the end of 2017

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as described in Note 16, should provide a significant step for New Mexico to meet its ultimate compliance with Section 111(d). PNM 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 2016. Instead, EPA continues to be the primary venue for GHG regulation in the near future, especially for coal-fired EGUs. The USSC’s decision to stay the Clean Power Plan does put into question the viability of the rule, but EPA is encouraging states to continue to develop plans for compliance even during the stay. In addition, while there are legislative proposals to limit or block implementation of the Clean Power Plan once it is finalized, enactment of such legislation appears unlikely.

PNM has assessed, and continues to assess, the impacts of 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.

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. Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP. 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.

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International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994. The objective of the treaty is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” Parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in meeting the objectives of the UNFCCC. This assessment process led to the negotiation of the Kyoto Protocol in the mid-1990s. The Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG emissions, was never ratified by the United States. PNM 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 agreement involving commitment by all nations to begin reducing carbon emissions by 2020. On December 12, 2015, the Paris Agreement was negotiated during the 2015 COP. The agreement signed by more than 190 countries includes Intended Nationally Determined Contributions (“INDCs”), which are national targets and actions that arise out of national polices, and elements relating to oversight, guidance and coordination of actions to reduce emissions by all countries. In November 2014, President Obama announced the United States’ commitment to reduce greenhouse gas emissions by 26%-28% from 2005 levels by the year 2025, which would put the United States on a path to achieve economy-wide reductions of around 80% by 2050. As part of the process for developing the new global climate agreement, the United States formally submitted its INDC to the UNFCCC Secretariat on March 31, 2015, which reflected no change from the November 2014 announcement. To date, INDCs have been submitted by 186 nations, including the United States and the European Union. PNM will continue to monitor the United States participation in international accords. The Obama administration’s GHG emissions reduction target for the electric utility industry is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources. With the stay of the Clean Power Plan that covers existing sources, it is uncertain how the Obama administration plans to meet its commitments under the UNFCCC. PNM believes that implementation of the RSIP for BART at SJGS should provide a significant step towards compliance with the Clean Power Plan, should it prevail, or other GHG emission reduction 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 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 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

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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 for significant transmission planning related changes. In response, PNM and WestConnect (an organization of utility companies providing transmission of electricity in the western region that includes PNM) participants filed modified versions to the Attachment K (Transmission Planning Process) of their respective Open Access Transmission Tariff (“OATT”). In March 2013, FERC issued its order regarding PNM’s and six other WestConnect FERC jurisdictional utilities’ compliance filings partially accepting many aspects of the filings. 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. On September 20, 2013, PNM and the other WestConnect FERC jurisdictional entities submitted their revised regional compliance filings to address and comply with the March 2013 FERC order.

In September 2014, FERC issued an additional order concerning the regional planning process and cost allocation in response to the September 2013 compliance filings. The FERC order required the WestConnect entities to make another compliance filing to hold a single year “abbreviated planning process for year 2015.” The order also required the entities to file the WestConnect “Planning Participation Agreement.” Of significant concern to FERC jurisdictional entities in this order was FERC’s ruling that the non-jurisdictional entities would not be required to participate in cost allocation on regional projects, which the WestConnect FERC jurisdictional entities believe 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. Due to the cost allocation issue, FERC-regulated entities jointly filed a request for re-hearing or clarification of the FERC order in October 2014. The FERC-regulated entities filed compliance filings regarding the September 2014 FERC order in November 2014, making several adjustments to the language in their respective Attachment Ks, as well as a separate unsigned version of the proposed final version of the Planning Participation Agreement. In May 2015, FERC conditionally accepted the November 2014 filings, but denied the re-hearing request filed in October 2014. The WestConnect FERC jurisdictional entities made compliance filings regarding the May 2015 FERC order on June 16, 2015, making several adjustments to the language in their respective Attachment K. In October 2015, FERC accepted the compliance filings, subject to making two further procedural modifications. On November 19, 2015, the FERC jurisdictional entities filed revisions to Attachment K of their respective OATT. On January 21, 2016, FERC accepted PNM’s November 2015 filing with an effective date of January 1, 2016.

In July 2013, the WestConnect participants submitted their cost allocation and inter-regional coordination plan between WestConnect and three other planning regions. In December 2014, FERC issued an order conditionally accepting the WestConnect compliance filing including the California Independent System Operator Corporation (“CAISO”), Northern Tier Transmission Group Applicants, and Columbia Grid (collectively the “Western Filing Parties”). The order required the Western Filing Parties to use the same method for determining the regional benefits of a proposed interregional transmission facility through revisions to the common tariff language. Without requiring modification to the common tariff language for all four Western planning regions, CAISO would tender revised tariff sheets to address the Western Filing Parties compliance condition. The WestConnect entities and the other Western Filing Parties submitted a common compliance filing on February 17, 2015, stating that CAISO had agreed to change its OATT language and, therefore, the other entities would not have to change the common OATT language.

As of January 2015, all of the WestConnect jurisdictional entities have executed the Planning Participation Agreement and some of the non-jurisdictional entities have also signed. A 2015 study plan has been completed and committee activities are currently focused on establishing the data for the technical models, production cost models and base system to be used as the reference for the 2015 study work. WestConnect has hired a consultant to complete the single year planning study for 2015 as required in the September 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 has elected the end-user exception to the mandatory clearing requirement. PNM 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

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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. Unbilled revenues are estimated 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.

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 is 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 19 contains information on the impairment testing performed by the Company on goodwill. For 2015, 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, 2015. 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 valu

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es. 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 2015 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.

PNM believes that the WACC and cash flow projections utilized in the 2015 quantitative testing appropriately reflected the fair value of the PNM reporting unit. Since any cash flow projection contains uncertainty, the WACC used by PNM 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, 2015, the fair value of the PNM reporting unit, which had goodwill of $51.6 million, exceeded its carrying value by approximately 25%. 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 18% at April 1, 2015. 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

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. 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. 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 de

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commissioning costs represent approximately 85% 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 $13.1 million at December 31, 2015. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 is currently excluded, but will be included beginning in 2018. 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 $5.0 million at December 31, 2015. 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.

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. These calculations require the use of a number of actuarial assumptions and estimates. The most critical of the actuarial assumptions are the expected long-term rate of return, the discount rate, and projected health care cost trend rates. The Company reviews and evaluates its actuarial assumptions annually and adjusts them as necessary. Changes in the pension and OPEB assets and liabilities associated with these factors are not immediately recognized as net periodic benefit cost or income in results of operations, but are recognized in future years, generally, over the remaining life of the plan. However, these factors could have a significant impact on the financial position of the Company. Note 12 contains additional information about pension and OPEB obligations, including assumptions utilized in the calculations and impacts of changes in certain of those assumptions.

Accounting for Contingencies

The financial results of the Company may be affected by judgments and estimates related to loss contingencies. 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.

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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 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

• 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. During the years ended December 31, 2015 and 2014, PNMR and PNM had no commodity derivative instruments designated as cash flow hedging instruments.

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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 Sheets. 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, 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
Amount realized on contracts delivered during period	(12,050		)
Changes in fair value	6,863
Net mark-to-market change recorded in earnings	(5,187		)
Net change recorded as regulatory liability	217
Net fair value at December 31, 2015	$	4,576

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, 2015



	Settlement Dates
	2016		2017
PNMR and PNM	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—
Prices provided by other external sources	1,954		2,622
Prices based on models and other valuations	—		—
Total	$	1,954	$	2,622

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

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the year ended December 31, 2015, the high, low, and average VaR amounts were $2.6 million, $0.5 million, and $1.4 million. 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. At December 31, 2015 and December 31, 2014, the VaR amounts for the PNM wholesale portfolio were $1.2 million and $1.3 million.

The VaR represents 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 is 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

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market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year. VaR limits were not exceeded during 2015 or 2014.

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, 2015 will mature in less than two years.

Schedule of Credit Risk Exposure

December 31, 2015



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	$	1,211	—	$	—
Non-investment grade	1		—	—
Internal ratings:
Investment grade	6,601		1	5,722
Non-investment grade	8		—	—
Total	$	7,821		$	5,722


⁽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, 2015, PNMR and PNM held $0.1 million of cash collateral to offset their credit exposure.

Net credit risk for PNMR’s and PNM’s largest counterparty as of December 31, 2015 was $7.9 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.

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%, 1.7%, and 3.7%, if interest rates were to decline by 50 basis points from their levels at December 31, 2015. 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 19, 2016, PNMR, PNM, and TNMP had $66.1 million, $46.2 million, and $15.0 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 $50.0 million under the $50.0 million PNM New Mexico Credit Facility at February 19, 2016. The revolving credit facilities, the PNM New Mexico Credit Facility, the $125.0 million PNM Multi-draw Term Loan, the $100.0 million PNMR Term Loan Agreement, the $150.0 million PNMR 2015 Term Loan Agreement, the $150.0 million PNMR Term Loan Agreement, and the $125.0 million BTMU Term Loan Agreement bear interest at variable rates. On February 19, 2016, interest rates on borrowings averaged 1.68% for the PNMR Revolving Credit Facility, 1.33% for the PNMR

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2015 Term Loan Agreement, 1.28% for the PNMR Term Loan Agreement, 3.37% for the BTMU Term Loan Agreement, 1.01% for the PNM Multi-draw Term Loan, 1.56% for the PNM Revolving Credit Facility, 1.56% for the PNM New Mexico Credit Facility, and 1.43% 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 $891.5 million at December 31, 2015, of which 54.4% 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, 2015, the decrease in the fair value of the fixed-rate securities would be 5.6%, or $27.2 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $71.4 million at December 31, 2015, of which 57.7% were fixed-rate debt securities that subject TNMP to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2015, the decrease in the fair value of the fixed-rate securities would be 6.3%, or $2.6 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, 2015. These equity securities expose PNM and TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 34.0% and 26.0% of the securities held by the various PNM and TNMP trusts as of December 31, 2015. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $30.3 million for PNM and $1.9 million for TNMP.

Alternatives Investment Risk

The Company had 14.3% of its pension assets invested in the alternatives asset class as of December 31, 2015. The Company’s target for this class is 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 $8.8 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- 9
Consolidated Statements of Comprehensive Income		B- 10
Consolidated Statements of Cash Flows		B- 11
Consolidated Balance Sheets		B- 13
Consolidated Statements of Changes in Equity		B- 15
Public Service Company of New Mexico and Subsidiaries
Consolidated Statements of Earnings (Loss)		B- 16
Consolidated Statements of Comprehensive Income (Loss)		B- 17
Consolidated Statements of Cash Flows		B- 18
Consolidated Balance Sheets		B- 20
Consolidated Statements of Changes in Equity		B- 22
Texas-New Mexico Power Company and Subsidiaries
Consolidated Statements of Earnings		B- 23
Consolidated Statements of Comprehensive Income		B- 24
Consolidated Statements of Cash Flows		B- 25
Consolidated Balance Sheets		B- 27
Consolidated Statements of Changes in Common Stockholder’s Equity		B- 29
Notes to Consolidated Financial Statements		B- 30
Supplementary Data:
Reports of Independent Registered Public Accounting Firms on Schedules		B- 117
Schedule I - Condensed Financial Information of Parent Company		B- 120
Schedule II - Valuation and Qualifying Accounts		B- 123

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of PNMR’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) 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, 2015.

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 N. Eldred

Charles N. Eldred

Executive Vice President and

Chief Financial Officer

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of PNM’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) 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, 2015.

/s/ Patricia K. Collawn

Patricia K. Collawn,

President and Chief Executive Officer

/s/ Charles N. Eldred

Charles N. Eldred

Executive Vice President and

Chief Financial Officer

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of TNMP’s internal control over financial reporting based on the Internal Control – Integrated Framework (2013) 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, 2015.

/s/ Patricia K. Collawn

Patricia K. Collawn,

Chief Executive Officer

/s/ Charles N. Eldred

Charles N. Eldred

Executive Vice President and

Chief Financial Officer

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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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). PNM Resources, Inc. and subsidiaries 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) 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 PNM Resources, Inc. and subsidiaries as of December 31, 2015 and 2014, 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 three-year period ended December 31, 2015, and our report dated February 26, 2016 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Albuquerque, New Mexico

February 26, 2016

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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, 2015 and 2014, 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 three-year period ended December 31, 2015. 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, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PNM Resources, Inc. and subsidiaries internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Albuquerque, New Mexico

February 26, 2016

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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, 2015 and 2014, and the related consolidated statements of earnings (loss), consolidated statements of comprehensive income (loss), consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the three-year period ended December 31, 2015. 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 Public Service Company of New Mexico and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 26, 2016

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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, 2015 and 2014, 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 three-year period ended December 31, 2015. 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 Texas-New Mexico Power Company and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 26, 2016

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS



	Year Ended December 31,
	2015			2014			2013
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,439,082		$	1,435,853		$	1,387,923
Operating Expenses:
Cost of energy	464,649			471,556			432,316
Administrative and general	179,100			171,111			179,210
Energy production costs	176,752			185,638			175,819
Regulatory disallowances and restructuring costs	167,471			1,062			12,235
Depreciation and amortization	185,919			172,634			166,881
Transmission and distribution costs	69,157			66,571			70,124
Taxes other than income taxes	71,684			67,584			64,496
Total operating expenses	1,314,732			1,136,156			1,101,081
Operating income	124,350			299,697			286,842
Other Income and Deductions:
Interest income	6,498			8,483			10,043
Gains on available-for-sale securities	16,060			10,527			10,612
Other income	26,833			12,048			10,572
Other (deductions)	(12,728		)	(10,481		)	(21,552		)
Net other income and deductions	36,663			20,577			9,675
Interest Charges	114,860			119,627			121,448
Earnings before Income Taxes	46,153			200,647			175,069
Income Taxes	15,075			69,738			59,513
Net Earnings	31,078			130,909			115,556
(Earnings) Attributable to Valencia Non-controlling Interest	(14,910		)	(14,127		)	(14,521		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Net Earnings Attributable to PNMR	$	15,640		$	116,254		$	100,507
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.20		$	1.46		$	1.26
Diluted	$	0.20		$	1.45		$	1.25

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

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

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Net Earnings	$	31,078		$	130,909		$	115,556
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(4,310), $(6,812), and $(10,855)	6,688			10,661			16,564
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $11,181, $5,461, and $4,734	(17,350		)	(8,401		)	(7,222		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $1,726, $6,024 and $(6,781)	(2,679		)	(9,258		)	10,355
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,332), $(2,032) and $(2,524)	3,620			3,120			3,840
Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $(28), $53, and $98	44			(100		)	(181		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $(195), and $(73)	—			363			134
Total Other Comprehensive Income (Loss)	(9,677		)	(3,615		)	23,490
Comprehensive Income	21,401			127,294			139,046
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,910		)	(14,127		)	(14,521		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Comprehensive Income Attributable to PNMR	$	5,963		$	112,639		$	123,997

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,
	2015			2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	31,078		$	130,909		$	115,556
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	222,861			209,867			208,173
Deferred income tax expense	16,451			72,481			60,430
Net unrealized (gains) losses on commodity derivatives	5,188			(6,504		)	(1,866		)
Realized (gains) on available-for-sale securities	(16,060		)	(10,527		)	(10,612		)
Loss on reacquired debt	—			—			3,253
Stock based compensation expense	4,863			5,931			5,320
Regulatory disallowances and restructuring costs	167,471			1,062			12,235
Allowance for equity funds used during construction	(10,430		)	(5,563		)	(4,382		)
Other, net	3,934			4,045			2,735
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(3,298		)	(4,975		)	(7,562		)
Materials, supplies, and fuel stock	(180		)	5,504			(7,580		)
Other current assets	29,370			(30,436		)	8,577
Other assets	2,369			290			(12,801		)
Accounts payable	(32,269		)	(2,311		)	4,484
Accrued interest and taxes	4,957			2,040			91,537
Other current liabilities	2,633			(2,453		)	(19,648		)
Other liabilities	(42,064		)	45,516			(61,262		)
Net cash flows from operating activities	386,874			414,876			386,587
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(558,589		)	(460,658		)	(348,039		)
Proceeds from sales of available-for-sale securities	252,174			117,989			271,140
Purchases of available-for-sale securities	(262,548		)	(127,016		)	(282,000		)
Return of principal on PVNGS lessor notes	21,694			20,758			23,357
Purchase of Rio Bravo	—			(36,235		)	—
Other, net	2,741			(167		)	4,096
Net cash flows from investing activities	(544,528		)	(485,329		)	(331,446		)

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,
	2015			2014			2013
	(In thousands)
Cash Flows From Financing Activities:
Short-term loan	50,000			—			—
Revolving credit facilities borrowings (repayments), net	95,000			(43,600		)	(9,500		)
Long-term borrowings	463,605			355,000			75,000
Repayment of long-term debt	(333,066		)	(125,000		)	(29,468		)
Cash paid in debt exchange	—			—			(13,048		)
Proceeds from stock option exercise	5,619			6,999			4,618
Purchases to satisfy awards of common stock	(17,720		)	(17,319		)	(13,807		)
Dividends paid	(64,251		)	(59,468		)	(51,508		)
Valencia’s transactions with its owner	(17,049		)	(17,610		)	(18,335		)
Other, net	(6,707		)	(2,808		)	(5,545		)
Net cash flows from financing activities	175,431			96,194			(61,593		)
Change in Cash and Cash Equivalents	17,777			25,741			(6,452		)
Cash and Cash Equivalents at Beginning of Year	28,274			2,533			8,985
Cash and Cash Equivalents at End of Year	$	46,051		$	28,274		$	2,533
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	103,382		$	108,741		$	110,768
Income taxes paid (refunded), net	$	(1,890	)	$	(2,597	)	$	(95,327	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(19,080	)	$	(3,089	)	$	(6,006	)
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,
	2015		2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	46,051	$	28,274
Accounts receivable, net of allowance for uncollectible accounts of $1,397 and $1,466	98,699		87,038
Unbilled revenues	52,012		63,719
Other receivables	28,590		39,857
Materials, supplies, and fuel stock	67,386		63,628
Regulatory assets	1,070		47,855
Commodity derivative instruments	3,813		11,232
Income taxes receivable	5,845		6,360
Other current assets	82,104		58,471
Total current assets	385,570		406,434
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	259,042		250,145
Other investments	604		1,762
Non-utility property	3,404		3,406
Total other property and investments	263,050		264,851
Utility Plant:
Plant in service, held for future use, and to be abandoned	6,307,261		5,941,581
Less accumulated depreciation and amortization	2,058,772		1,939,760
	4,248,489		4,001,821
Construction work in progress	204,766		190,389
Nuclear fuel, net of accumulated amortization of $44,455 and $44,507	82,117		77,796
Net utility plant	4,535,372		4,270,006
Deferred Charges and Other Assets:
Regulatory assets	470,664		491,007
Goodwill	278,297		278,297
Commodity derivative instruments	2,622		—
Other deferred charges	73,753		79,642
Total deferred charges and other assets	825,336		848,946
	$	6,009,328	$	5,790,237

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,
	2015			2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	250,600		$	105,600
Current installments of long-term debt	124,979			332,871
Accounts payable	100,419			110,029
Customer deposits	12,216			12,555
Accrued interest and taxes	58,306			53,863
Regulatory liabilities	15,591			1,703
Commodity derivative instruments	1,859			1,209
Dividends declared	17,656			16,063
Other current liabilities	59,494			70,194
Total current liabilities	641,120			704,087
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,966,969			1,629,514
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	877,393			864,728
Regulatory liabilities	467,413			466,143
Asset retirement obligations	111,895			104,170
Accrued pension liability and postretirement benefit cost	73,097			110,738
Commodity derivative instruments	—			477
Other deferred credits	133,692			103,759
Total deferred credits and other liabilities	1,663,490			1,650,015
Total liabilities	4,271,579			3,983,616
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)	1,166,465			1,173,845
Accumulated other comprehensive income (loss), net of income taxes	(71,432		)	(61,755		)
Retained earnings	559,780			609,456
Total PNMR common stockholders’ equity	1,654,813			1,721,546
Non-controlling interest in Valencia	71,407			73,546
Total equity	1,726,220			1,795,092
	$	6,009,328		$	5,790,237

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, 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 (loss)	—			(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
Proceeds from stock option exercise	5,619			—			—			5,619			—			5,619
Purchases to satisfy awards of common stock	(17,720		)	—			—			(17,720		)	—			(17,720		)
Excess tax (shortfall) from stock-based payment arrangements	(142		)	—			—			(142		)	—			(142		)
Stock based compensation expense	4,863			—			—			4,863			—			4,863
Valencia’s transactions with its owner	—			—			—			—			(17,049		)	(17,049		)
Net earnings before subsidiary preferred stock dividends	—			—			16,168			16,168			14,910			31,078
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Total other comprehensive income (loss)	—			(9,677		)	—			(9,677		)	—			(9,677		)
Dividends declared on common stock	—			—			(65,316		)	(65,316		)	—			(65,316		)
Balance at December 31, 2015	$	1,166,465		$	(71,432	)	$	559,780		$	1,654,813		$	71,407		$	1,726,220

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 (LOSS)

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Electric Operating Revenues	$	1,131,195		$	1,147,914		$	1,116,312
Operating Expenses:
Cost of energy	391,131			403,626			374,710
Administrative and general	161,953			152,645			157,144
Energy production costs	176,752			185,638			175,819
Regulatory disallowances and restructuring costs	167,471			1,062			12,235
Depreciation and amortization	115,717			109,524			103,826
Transmission and distribution costs	43,642			43,128			45,936
Taxes other than income taxes	41,149			39,578			37,457
Total operating expenses	1,097,815			935,201			907,127
Operating income	33,380			212,713			209,185
Other Income and Deductions:
Interest income	6,574			8,557			10,182
Gains on available-for-sale securities	16,060			10,527			10,612
Other income	19,347			8,949			7,650
Other (deductions)	(8,493		)	(7,218		)	(6,974		)
Net other income and deductions	33,488			20,815			21,470
Interest Charges	79,950			79,442			79,175
Earnings (Loss) before Income Taxes	(13,082		)	154,086			151,480
Income Taxes (Benefit)	(12,758		)	52,633			48,804
Net Earnings (Loss)	(324		)	101,453			102,676
(Earnings) Attributable to Valencia Non-controlling Interest	(14,910		)	(14,127		)	(14,521		)
Net Earnings (Loss) Attributable to PNM	(15,234		)	87,326			88,155
Preferred Stock Dividends Requirements	(528		)	(528		)	(528		)
Net Earnings (Loss) Available for PNM Common Stock	$	(15,762	)	$	86,798		$	87,627

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 (LOSS)

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Net Earnings (Loss)	$	(324	)	$	101,453		$	102,676
Other Comprehensive Income:
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(4,310), $(6,812), and $(10,855)	6,688			10,661			16,564
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $11,181, $5,461, and $4,734	(17,350		)	(8,401		)	(7,222		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $1,726, $6,024 and $(6,781)	(2,679		)	(9,258		)	10,355
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,332), $(2,032) and $(2,524)	3,620			3,120			3,840
Total Other Comprehensive Income (Loss)	(9,721		)	(3,878		)	23,537
Comprehensive Income (Loss)	(10,045		)	97,575			126,213
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,910		)	(14,127		)	(14,521		)
Comprehensive Income (Loss) Attributable to PNM	$	(24,955	)	$	83,448		$	111,692

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,
	2015			2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings (loss)	$	(324	)	$	101,453		$	102,676
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	150,538			143,303			136,732
Deferred income tax expense	(2,836		)	55,787			50,043
Net unrealized (gains) losses on commodity derivatives	5,188			(6,504		)	(1,866		)
Realized (gains) on available-for-sale securities	(16,060		)	(10,527		)	(10,612		)
Regulatory disallowances and restructuring costs	167,471			1,062			12,235
Allowance for equity funds used during construction	(10,430		)	(5,563		)	(4,382		)
Other, net	2,794			4,172			2,768
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(2,515		)	(5,919		)	(3,021		)
Materials, supplies, and fuel stock	381			5,570			(7,730		)
Other current assets	23,693			(29,146		)	8,556
Other assets	4,194			7,150			(13,363		)
Accounts payable	(31,139		)	212			2,807
Accrued interest and taxes	(5,343		)	(3,599		)	72,740
Other current liabilities	(275		)	(659		)	(27,376		)
Other liabilities	(33,503		)	42,325			(59,753		)
Net cash flows from operating activities	251,834			299,117			260,454
Cash Flows From Investing Activities:
Utility plant additions	(404,840		)	(316,800		)	(239,906		)
Proceeds from sales of available-for-sale securities	252,174			117,989			271,140
Purchases of available-for-sale securities	(262,548		)	(127,016		)	(282,000		)
Return of principal on PVNGS lessor notes	21,694			20,758			23,357
Purchase of Rio Bravo	—			(36,235		)	—
Other, net	2,935			(363		)	3,843
Net cash flows from investing activities	(390,585		)	(341,667		)	(223,566		)

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,
	2015			2014			2013
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	—			(49,200		)	28,100
Short-term borrowings (repayments) - affiliate, net	—			(32,500		)	32,500
Long-term borrowings	313,605			275,000			75,000
Repayment of long-term debt	(214,300		)	(75,000		)	—
Equity contribution from parent	175,000			—			—
Valencia’s transactions with its owner	(17,049		)	(17,610		)	(18,335		)
Dividends paid	(94,968		)	(30,791		)	(155,556		)
Other, net	(5,879		)	(1,890		)	(2,534		)
Net cash flows from financing activities	156,409			68,009			(40,825		)

Change in Cash and Cash Equivalents	17,658			25,459			(3,937		)
Cash and Cash Equivalents at Beginning of Year	25,480			21			3,958
Cash and Cash Equivalents at End of Year	$	43,138		$	25,480		$	21

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	69,936		$	73,787		$	71,306
Income taxes paid (refunded), net	$	(1,450	)	$	(228	)	$	(77,434	)

Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	(17,469	)	$	(1,616	)	$	(7,921	)

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,
	2015		2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	43,138	$	25,480
Accounts receivable, net of allowance for uncollectible accounts of $1,397 and $1,466	78,291		67,622
Unbilled revenues	42,641		54,140
Other receivables	24,725		37,622
Affiliate receivables	15,105		8,853
Materials, supplies, and fuel stock	60,477		60,859
Regulatory assets	—		43,980
Commodity derivative instruments	3,813		11,232
Income taxes receivable	14,577		6,105
Other current assets	74,990		53,095
Total current assets	357,757		368,988
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	259,042		250,145
Other investments	366		397
Non-utility property	96		96
Total other property and investments	259,504		260,176
Utility Plant:
Plant in service, held for future use, and to be abandoned	4,833,303		4,581,066
Less accumulated depreciation and amortization	1,569,549		1,486,406
	3,263,754		3,094,660
Construction work in progress	172,238		169,673
Nuclear fuel, net of accumulated amortization of $44,455 and $44,507	82,117		77,796
Net utility plant	3,518,109		3,342,129
Deferred Charges and Other Assets:
Regulatory assets	342,910		357,045
Goodwill	51,632		51,632
Commodity derivative instruments	2,622		—
Other deferred charges	66,810		73,144
Total deferred charges and other assets	463,974		481,821
	$	4,599,344	$	4,453,114

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,
	2015			2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current installments of long-term debt	$	124,979		$	214,264
Accounts payable	72,386			86,055
Affiliate payables	14,318			18,232
Customer deposits	12,216			12,555
Accrued interest and taxes	33,189			29,298
Regulatory liabilities	15,591			1,703
Commodity derivative instruments	1,859			1,209
Dividends declared	132			132
Other current liabilities	42,251			52,053
Total current liabilities	316,921			415,501
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,455,698			1,268,273
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	696,384			703,396
Regulatory liabilities	434,863			425,481
Asset retirement obligations	111,049			103,182
Accrued pension liability and postretirement benefit cost	66,285			102,850
Commodity derivative instruments	—			477
Other deferred credits	117,275			86,023
Total deferred credits and liabilities	1,425,856			1,421,409
Total liabilities	3,198,475			3,105,183
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)	1,236,776			1,061,776
Accumulated other comprehensive income (loss), net of income tax	(71,476		)	(61,755		)
Retained earnings	152,633			262,835
Total PNM common stockholder’s equity	1,317,933			1,262,856
Non-controlling interest in Valencia	71,407			73,546
Total equity	1,389,340			1,336,402
	$	4,599,344		$	4,453,114

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, 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
Valencia’s transactions with its owner	—		—			—			—			(17,049		)	(17,049		)
Net earnings (loss)	—		—			(15,234		)	(15,234		)	14,910			(324		)
Total other comprehensive income (loss)	—		(9,721		)	—			(9,721		)	—			(9,721		)
Equity contribution from parent	175,000		—			—			175,000			—			175,000
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(94,440		)	(94,440		)	—			(94,440		)
Balance at December 31, 2015	$	1,236,776	$	(71,476	)	$	152,633		$	1,317,933		$	71,407		$	1,389,340

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,
	2015			2014			2013
	(In thousands)

Electric Operating Revenues	$	307,887		$	287,939		$	271,611
Operating Expenses:
Cost of energy	73,518			67,930			57,606
Administrative and general	36,755			36,982			44,635
Depreciation and amortization	56,285			50,056			50,219
Transmission and distribution costs	25,515			23,443			24,188
Taxes other than income taxes	25,781			23,940			22,778
Total operating expenses	217,854			202,351			199,426
Operating income	90,033			85,588			72,185
Other Income and Deductions:
Other income	4,240			2,865			2,377
Other (deductions)	(504		)	(727		)	(458		)
Net other income and deductions	3,736			2,138			1,919
Interest Charges	27,681			27,396			27,393
Earnings Before Income Taxes	66,088			60,330			46,711
Income Taxes	24,125			22,523			17,621
Net Earnings	$	41,963		$	37,807		$	29,090

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,
	2015		2014			2013
	(In thousands)
Net Earnings	$	41,963	$	37,807		$	29,090
Other Comprehensive Income (Loss):
Fair Value Adjustment for Designated Cash Flow Hedge:
Change in fair value, net of income tax (expense) benefit of $0, $53, and $98	—		(100		)	(181		)
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit) of $0, $(195), and $(73)	—		363			134
Total Other Comprehensive Income (Loss)	—		263			(47		)
Comprehensive Income	$	41,963	$	38,070		$	29,043

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,
	2015			2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	41,963		$	37,807		$	29,090
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	57,909			52,847			54,395
Deferred income tax expense	20,883			20,549			20,662
Other, net	18			(10		)	(30		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(783		)	944			(4,542		)
Materials and supplies	(561		)	(66		)	150
Other current assets	3,928			380			(1,137		)
Other assets	(2,310		)	(6,607		)	941
Accounts payable	(1,782		)	2,514			3,709
Accrued interest and taxes	4,317			4,796			(6,713		)
Other current liabilities	1,019			(203		)	(3,197		)
Other liabilities	(9,823		)	3,112			460
Net cash flows from operating activities	114,778			116,063			93,788
Cash Flows From Investing Activities:
Utility plant additions	(124,584		)	(127,191		)	(89,117		)
Net cash flows from investing activities	(124,584		)	(127,191		)	(89,117		)

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,
	2015			2014			2013
	(In thousands)

Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	54,000			5,000			—
Short-term borrowings (repayments) – affiliate, net	(10,900		)	(6,700		)	1,100
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	(33,248		)	(16,336		)	(3,726		)
Other, net	(46		)	(836		)	(2,797		)
Net cash flows from financing activities	9,806			11,128			(4,671		)
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	$	26,216		$	22,803		$	25,436
Income taxes paid, (refunded) net	$	290		$	(355	)	$	4,484

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(5	)	$	854		$	(141	)

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,
	2015		2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	20,408		19,416
Unbilled revenues	9,371		9,579
Other receivables	811		2,063
Materials and supplies	6,909		2,769
Regulatory assets	1,070		3,875
Other current assets	1,053		938
Total current assets	39,623		38,641
Other Property and Investments:
Other investments	238		242
Non-utility property	2,240		2,240
Total other property and investments	2,478		2,482
Utility Plant:
Plant in service and plant held for future use	1,285,727		1,182,112
Less accumulated depreciation and amortization	406,516		375,407
	879,211		806,705
Construction work in progress	16,561		16,538
Net utility plant	895,772		823,243
Deferred Charges and Other Assets:
Regulatory assets	127,754		133,962
Goodwill	226,665		226,665
Other deferred charges	4,847		4,424
Total deferred charges and other assets	359,266		365,051
	$	1,297,139	$	1,229,417

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,
	2015		2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	59,000	$	5,000
Short-term debt – affiliate	11,800		22,700
Accounts payable	16,006		14,203
Affiliate payables	3,681		2,469
Accrued interest and taxes	32,891		28,574
Other current liabilities	2,044		2,271
Total current liabilities	125,422		75,217
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	361,411		361,241
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	232,791		211,547
Regulatory liabilities	32,550		40,662
Asset retirement obligations	695		848
Accrued pension liability and postretirement benefit cost	6,812		7,888
Other deferred credits	4,078		7,349
Total deferred credits and other liabilities	276,926		268,294
Total liabilities	763,759		704,752
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
Retained earnings	129,150		120,435
Total common stockholder’s equity	533,380		524,665
	$	1,297,139	$	1,229,417

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, 2012	$	64	$	390,366	$	(216	)	$	73,600		$	463,814
Net earnings	—		—		—			29,090			29,090
Total other comprehensive income (loss)	—		—		(47		)	—			(47		)
Equity contribution 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
Net earnings	—		—		—			41,963			41,963
Dividends declared on common stock	—		—		—			(33,248		)	(33,248		)
Balance at December 31, 2015	$	64	$	404,166	$	—		$	129,150		$	533,380

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

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Table of Contents

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, 2015, 2014 and 2013


(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 2014 and 2013 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 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 Valencia (Note 9) and, through January 15, 2016, the PVNGS Capital Trust. 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 3.

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 are deferred as regulatory assets that otherwise would be expensed. Likewise, regulatory liabilities are recognized when it is probable that regulators will require refunds through future rates or when revenue is collected for expenditures that have not yet been incurred. GAAP also provides for the recognition of revenue and regulatory assets and liabilities associated with “alternative revenue programs” authorized by regulators. Such programs allow the utility to adjust future rates in response to past activities or completed events, if certain criteria are met, even for programs that do not otherwise qualify for recognition of regulatory assets and liabilities. Regulatory assets and liabilities are amortized into earnings over the authorized recovery period. Accordingly, the Company has defe

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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, 2015, 2014 and 2013

rred 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.

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 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.

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
	2015		2014		2013
PNM
Electric plant	2.27	%	2.26	%	2.27	%
Common, intangible, and general plant	4.66	%	4.64	%	4.87	%
TNMP	3.94	%	3.59	%	3.66	%

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.

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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, 2015, 2014 and 2013

For the years ended December 31, 2015, 2014, and 2013, PNM recorded $7.8 million, $4.2 million, and $3.3 million of allowance for borrowed funds used during construction and $10.4 million, $5.6 million, and $4.4 million of allowance for equity funds used during construction. TNMP recorded $0.5 million, $0.5 million, and $0.4 million of allowance for borrowed funds used during construction and zero, zero, and zero 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%, 6.6%, and 6.9% for 2015, 2014, and 2013. In 2015, 2014, and 2013, capitalized interest was $1.5 million, $1.6 million, and $1.5 million for PNMR consolidated; $0.8 million, $1.1 million, and $1.1 million for PNM; and $0.1 million, $0.1 million, 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. Average cost is equal to net realizable value under the ratemaking process.

Inventories consisted of the following at December 31:



	PNMR				PNM				TNMP
	2015		2014		2015		2014		2015		2014
	(In thousands)
Coal	$	18,356	$	17,525	$	18,356	$	17,525	$	—	$	—
Materials and supplies	49,030		46,103		42,121		43,334		6,909		2,769
	$	67,386	$	63,628	$	60,477	$	60,859	$	6,909	$	2,769

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 was consolidated by PNM. The PVNGS Capital Trust held certain of the lessor notes to their maturities in January 2015 and January 2016. Upon final maturity of the lessor notes, the PVNGS Capital Trust ceased to exist. The PVNGS lessor notes were carried at amortized cost.

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and 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, 2015, 2014, and 2013, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trust of $10.4 million, $4.8 million, and $3.5 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI. The available-for-sale securities are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in PNM’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions.

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 19.

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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, 2015, 2014 and 2013

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 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.

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. See Note 6 for information regarding the adoption of a new accounting standard that requires a change in presentation of unamortized debt issuance costs on the Consolidated Balance Sheets.

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 6 and Note 8.

The Company treats all forward commodity 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

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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, 2015, 2014 and 2013

exception by meeting the definition of a capacity contract. Under this definition, the contract cannot permit net settlement, the seller must have the resources to serve the contract, and the buyer must be a load serving entity. GAAP provides guidance on whether realized gains and losses on derivative contracts not held for trading purposes should be reported on a net or gross basis and concludes such classification is a matter of judgment that depends on the relevant facts and circumstances.

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, 2015, 2014, and 2013, as well as the amounts of environmental liabilities at December 31, 2015 and 2014 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

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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, 2015, 2014 and 2013

tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the NMPRC, FERC, and the PUCT have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The Company recognizes only the impact of tax positions that, based on their merits, are more likely than not to be sustained upon an IRS audit. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets. See Note 11.

The Company makes an estimate of its anticipated effective tax rate for the year as of the end of each quarterly period within its fiscal year. In interim periods, income tax expense is 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. On August 12, 2015, the FASB issued a one-year deferral in the effective date. The Company must now adopt the new standard beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not 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.

Accounting Standards Update 2016-01 – Financial Instruments (Subtopic 825-10) – Recognition and Measurement of Financial Assets and Financial Liabilities

On January 5, 2016, the FASB issued ASU No. 2016-01, which makes targeted improvements to GAAP regarding financial instruments. The new standard eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and now requires those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. The new standard also revises certain presentation and disclosure requirements. Under the new standard, accounting for investments in debt securities remains essentially unchanged. The new standard will be effective for the Company beginning on January 1, 2018. Early adoption of the standard is permitted. The Company is in the process of analyzing the impacts of this new standard.

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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, 2015, 2014 and 2013

Accounting Standards Update 2016-02 – Leases (Topic 842)

On February 25, 2016, the FASB issued ASU No. 2016-02, which will change how lessees account for leases. The ASU will require that a liability be recorded on the balance sheet for all leases based on the present value of future lease obligations. A corresponding right-of-use asset will also be recorded. Amortization of the lease obligation and the right-of-use asset for certain leases, primarily those currently classified as operating leases, will be on a straight-line basis, which is not expected to have a significant impact on the statements of earnings or cash flows, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. The new standard also revises certain disclosure requirements. The new standard will be effective for the Company beginning on January 1, 2019. Early adoption of the standard is permitted. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. Since this ASU was only recently issued, the Company has not yet begun 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.

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.

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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, 2015, 2014 and 2013

PNMR SEGMENT INFORMATION



2015	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Electric operating revenues	$	1,131,195		$	307,887		$	—		$	1,439,082
Cost of energy	391,131			73,518			—			464,649
Margin	740,064			234,369			—			974,433
Other operating expenses	590,967			88,051			(14,854		)	664,164
Depreciation and amortization	115,717			56,285			13,917			185,919
Operating income	33,380			90,033			937			124,350
Interest income	6,574			—			(76		)	6,498
Other income (deductions)	26,914			3,736			(485		)	30,165
Interest charges	(79,950		)	(27,681		)	(7,229		)	(114,860		)
Segment earnings (loss) before income taxes	(13,082		)	66,088			(6,853		)	46,153
Income taxes (benefit)	(12,758		)	24,125			3,708			15,075
Segment earnings (loss)	(324		)	41,963			(10,561		)	31,078
Valencia non-controlling interest	(14,910		)	—			—			(14,910		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	(15,762	)	$	41,963		$	(10,561	)	$	15,640

At December 31, 2015:
Total Assets	$	4,599,344		$	1,297,139		$	112,845		$	6,009,328
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, 2015, 2014 and 2013



2014	PNM			TNMP			Corporate and Other			Consolidated

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

At December 31, 2014:
Total Assets	$	4,453,114		$	1,229,417		$	107,706		$	5,790,237
Goodwill	$	51,632		$	226,665		$	—		$	278,297



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

At December 31, 2013:
Total Assets	$	4,174,261		$	1,151,327		$	101,270		$	5,426,858
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, 2015, 2014 and 2013

Major Customers

No individual customer accounted for more than 10% of the electric operating revenues of PNMR or PNM. Three customers of TNMP accounted for 16% in 2015, 15% in 2014, and 16% in 2013; 13% in 2015, 15% in 2014, and 17% in 2013; and 11% in 2015, 11% in 2014, and 10% in 2013 of TNMP’s electric operating revenues.


(3)	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,
	2015		2014		2013
			(In thousands)
Services billings:
PNMR to PNM	$	90,827	$	86,871	$	92,597
PNMR to TNMP	28,109		28,349		28,937
PNM to TNMP	554		524		562
TNMP to PNMR	41		31		7
Income tax sharing payments:
PNMR to TNMP	—		—		—
PNMR to PNM	1,450		—		77,433
TNMP to PNMR	—		—		3,643
Interest payments:
PNM to PNMR	54		65		4
TNMP to PNMR	276		309		481


(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, 2015, 2014 and 2013



	PNM						TNMP
	December 31,						December 31,
	2015			2014			2015			2014
Assets:	(In thousands)
Current:
FPPAC	$	—		$	43,980		$	—		$	—
Transmission cost recovery factor	—			—			441			2,482
Energy efficiency costs	—			—			629			1,393
	—			43,980			1,070			3,875
Non-Current:
CTC, including carrying charges	—			—			46,147			55,292
Coal mine reclamation costs	28,303			34,224			—			—
Deferred income taxes	66,990			63,645			10,244			10,556
Loss on reacquired debt	23,627			25,439			35,405			36,703
Pension and OPEB	218,743			222,545			23,356			23,803
AMS surcharge	—			—			1,673			—
AMS retirement costs	—			—			8,549			6,453
Renewable energy costs	—			5,263			—			—
Other	5,247			5,929			2,380			1,155
	342,910			357,045			127,754			133,962
Total regulatory assets	$	342,910		$	401,025		$	128,824		$	137,837
Liabilities:
Current:
FPPAC	$	(11,410	)	$	—		$	—		$	—
Other	(4,181		)	(1,703		)	—			—
	(15,591		)	(1,703		)	—			—
Non-Current:
Cost of removal	(284,015		)	(277,148		)	(26,859		)	(29,391		)
Deferred income taxes	(77,502		)	(75,941		)	(3,283		)	(3,923		)
AROs	(33,747		)	(35,834		)	—			—
Renewable energy tax benefits	(23,697		)	(24,854		)	—			—
AMS surcharge	—			—			—			(5,227		)
Nuclear spent fuel reimbursements	(9,214		)	(3,625		)	—			—
Pension and OPEB	—			—			(1,913		)	(2,121		)
Other	(6,688		)	(8,079		)	(495		)	—
	(434,863		)	(425,481		)	(32,550		)	(40,662		)
Total regulatory liabilities	$	(450,454	)	$	(427,184	)	$	(32,550	)	$	(40,662	)

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.

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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, 2015, 2014 and 2013

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, 2015. PNMR funded a cash equity contribution of $175.0 million to PNM in 2015 and $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 2018.

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 $94.4 million, $30.3 million, and $155.0 million in 2015, 2014, and 2013. TNMP paid cash dividends to PNMR of $33.2 million, $16.3 million, and $3.7 million in 2015, 2014, and 2013.

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 current earnings, determined on a rolling four quarter basis, and from equity contributions previously made by PNMR without prior NMPRC approval. The Federal Power Act also imposes certain restrictions on dividends by public utilities. The Company’s revolving credit facilities and term loans 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, 2015, 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 $153 million and TNMP would not be able to distribute amounts in excess of approximately $195 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

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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, 2015, 2014 and 2013

The Company’s financing strategy includes both short-term and long-term borrowings. The Company utilizes short-term revolving credit facilities, as well as cash flows from operations, to provide funds for both construction and operating expenditures. Depending on market and other conditions, the Company will periodically sell long-term debt or enter into term loan arrangements and use the proceeds to reduce borrowings under the revolving credit facilities. Each of the revolving credit facilities and the Company’s term loans 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) and generally include customary covenants, events of default, cross default provisions and change of control provisions.

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.

Financing Activities

PNMR

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, 2013. On December 22, 2014, PNMR entered into another agreement that amended and restated the PNMR Term Loan Agreement extending the maturity date to December 21, 2015. On December 21, 2015, PNMR entered into the Third Amended and Restated PNMR Term Loan Agreement that increased the amount of the PNMR Term Loan Agreement to $150.0 million and extended the maturity date to December 21, 2016.

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.22% at December 31, 2015, and must be repaid on or before March 9, 2018.

In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927% for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018. This hedge is accounted for as a cash-flow hedge and had a fair value gain of $0.1 million at December 31, 2015, 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.

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.

At December 31, 2014, PNMR had an aggregate outstanding principal amount of $118.8 million of its 9.25% Senior Unsecured Notes, Series A, which were due on May 15, 2015. PNMR repaid all of the 9.25% Senior Unsecured Notes, Series A at the scheduled maturity, utilizing proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility.

As discussed in Note 16, NM Capital, a wholly owned subsidiary of PNMR, entered into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as Administrative Agent, as of February 1, 2016. The BTMU Term Loan Agreement has a maturity date of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations. The BTMU Term Loan Agreement and the guarantee include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio and customary events of default consistent with PNMR’s other term loan agreements. In addition, the BTMU Term Loan Agreement has a cross default provision and a change of control provision. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding of $125.0 million to

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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, 2015, 2014 and 2013

a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price of the stock of SJCC.

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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, 2015, 2014 and 2013

PNM

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 $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and BTMU, 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 and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement was repaid on August 12, 2015.

On December 22, 2014, PNM entered into a 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. PNM drew the remaining capacity of $25.0 million on May 8, 2015 resulting in outstanding borrowings at December 31, 2015 of $125.0 million, which are included in current maturities of long-term debt on the Consolidated Balance Sheet. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.99% at December 31, 2015.

At December 31, 2014, PNM had a $39.3 million series of outstanding Senior Unsecured Notes, Pollution Control Revenue Bonds, which have a final maturity of June 1, 2043. These PCRBs were subject to mandatory tender for remarketing on June 1, 2015 and were successfully remarketed on that date. The notes now bear interest at 2.40%, continue to have an outstanding amount of $39.3 million, and are subject to mandatory tender for remarketing on June 1, 2020.

PNM has a shelf registration statement, which will expire in May 2017, with capacity for the issuance of up to $250.0 million of senior unsecured notes.

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. The debt was repaid from the proceeds of the TNMP 2013 Bond Purchase Agreement. TNMP entered into hedging agreements whereby it effectively established fixed interest rates for such borrowing over the life of the debt.

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

On December 9, 2013, TNMP entered into an agreement (the “TNMP 2013 Bond Purchase Agreement”), which 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 a term loan and used the remaining $30.0 million of proceeds to reduce short-term debt.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

On December 17, 2015, TNMP entered into an agreement (the “TNMP 2015 Bond Purchase Agreement”), which provided that TNMP would issue $60.0 million aggregate principal amount of 3.53% first mortgage bonds, due 2026 (the “Series 2016A Bonds”) on or about February 10, 2016, subject to satisfaction of certain conditions. TNMP issued the Series 2016A Bonds on February 10, 2016 and used the proceeds to reduce short-term debt and intercompany debt.

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 or the money-market interest rate if PNMR does not have any short-term borrowings outstanding. As of December 31, 2015 and 2014, TNMP had outstanding borrowings of $11.8 million and $22.7 million from PNMR. At February 19, 2016, TNMP had borrowings of $15.1 million from PNMR. PNM had no outstanding borrowings from PNMR at December 31, 2015 or February 19, 2016.

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 October 2015, the maturity of both of these facilities was extended from October 31, 2019 to October 31, 2020. 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.

On January 8, 2014, PNM entered into a $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, 2015, interest rates on outstanding borrowings were 1.26% for the PNMR Term Loan Agreement (discussed under Financing Activities above), 1.67% for the PNMR Revolving Credit Facility, and 1.29% 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, 2015. Short-term debt outstanding consists of:



	December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	—	$	—
PNM New Mexico Credit Facility	—		—
TNMP Revolving Credit Facility	59,000		5,000
PNMR
PNMR Revolving Credit Facility	41,600		600
PNMR Term Loan Agreement	150,000		100,000
	$	250,600	$	105,600

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.2 million, $3.2 million, and $0.1 million at December 31, 2015 that reduce the available capacity under their respective revolving credit facilities.

At February 19, 2016, PNMR, PNM, and TNMP had $187.7 million, $350.6 million, and $59.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had no availability under the PNM New Mexico Credit Facility. Total availability at February 19, 2016, on a consolidated basis, was $598.2 million for PNMR. At February 19, 2016, PNMR had invested cash of $1.9 million. PNM and TNMP had no invested cash at February 19, 2016.

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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, 2015, 2014 and 2013

Long-Term Debt

Information concerning long-term debt outstanding and unamortized (premiums), discounts, and debt issuance costs is as follows:



	December 31, 2015					December 31, 2014
	Principal		Unamortized Discounts, (Premiums), and Issuance Costs, net			Principal		Unamortized Discounts, (Premiums), and Issuance Costs, net
	(In thousands)
PNM Debt
Senior Unsecured Notes, Pollution Control Revenue Bonds:
4.875% due 2033	$	146,000	$	721		$	146,000	$	807
6.25% due 2038	36,000		251			36,000		262
4.75% due 2040, mandatory tender at June 1, 2017	37,000		82			37,000		138
5.20% due 2040, mandatory tender at June 1, 2020	40,045		190			40,045		233
5.90% due 2040	255,000		2,222			255,000		2,313
6.25% due 2040	11,500		100			11,500		104
2.54% due 2042, mandatory tender at June 1, 2017	20,000		199			20,000		331
4.00% due 2043, mandatory tender at June 1, 2015	—		—			39,300		36
2.40% due 2043, mandatory tender at June 1, 2020	39,300		456			—		—
5.20% due 2043, mandatory tender at June 1, 2020	21,000		96			21,000		118
Senior Unsecured Notes:
7.95% due 2018	350,000		1,718			350,000		2,441
7.50% due 2018	100,025		320			100,025		444
5.35% due 2021	160,000		943			160,000		1,106
3.85% due 2025	250,000		2,874			—		—
PNM Term Loan Agreement due 2015	—		—			175,000		—
PNM Multi-draw Term Loan due 2016	125,000		21			100,000		—
	1,590,870		10,193			1,490,870		8,333
Less current maturities	125,000		21			214,300		36
	1,465,870		10,172			1,276,570		8,297
TNMP Debt
First Mortgage Bonds:
9.50% due 2019, Series 2009A	172,302		2,682			172,302		3,508
6.95% due 2043, Series 2013A	93,198		(19,490		)	93,198		(20,208		)
4.03% due 2024, Series 2014A	80,000		897			80,000		959
	345,500		(15,911		)	345,500		(15,741		)
Less current maturities	—		—			—		—
	345,500		(15,911		)	345,500		(15,741		)
PNMR Debt
PNMR 2015 Term Loan Agreement due 2018	150,000		140			—		—
Senior unsecured notes, 9.25% due 2015	—		—			118,766		159
	150,000		140			118,766		159
Less current maturities	—		—			118,766		159
	150,000		140			—		—
Total Consolidated PNMR Debt	2,086,370		(5,578		)	1,955,136		(7,249		)
Less current maturities	125,000		21			333,066		195
	$	1,961,370	$	(5,599	)	$	1,622,070	$	(7,444	)

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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, 2015, 2014 and 2013

In April 2015, the FASB issued Accounting Standards Update 2015-03 – Interest – Imputation of Interest (Subtopic 835-30) , which, as subsequently amended, requires that debt issuance costs be reflected as a direct reduction of the related debt liability, except for arrangements such as the Company’s revolving credit facilities. As permitted under the ASU, the Company adopted it as of December 31, 2015. The ASU requires that upon adoption it is to be applied retrospectively to prior years. Accordingly, amounts for 2014 that previously were included in other deferred charges are now reflected as reductions of the related debt in the above table and on the Consolidated Balance Sheets. The 2014 amounts reclassified were none for PNMR, less than $0.1 million for PNM, and none for TNMP that reduce current installments of long-term debt and $0.2 million for PNMR, $8.1 million for PNM, and $4.4 million for TNMP that reduce long-term debt.

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



	PNMR		PNM		TNMP		PNMR Consolidated
	(In thousands)
2016	$	—	$	125,000	$	—	$	125,000
2017	—		57,000		—		57,000
2018	150,000		450,025		—		600,025
2019	—		—		172,302		172,302
2020	—		100,345		—		100,345
Thereafter	—		858,500		173,198		1,031,698
Total	$	150,000	$	1,590,870	$	345,500	$	2,086,370


(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, through April 1, 2015, leased 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 initially 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 did 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 were greater than parameters set forth in the leases. The rental payments during the fixed renewal option periods are 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, aggregated $33.0 million for the Unit 1 leases and $23.7 million for the Unit 2 leases prior to the expiration of their original terms. 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.

Following procedures set forth in the PVNGS leases, PNM notified each of the four lessors under the Unit 1 leases and the lessor under the one Unit 2 lease containing the Maximum Option Period provision that it would elect to renew those leases for the Maximum Option Period on the expiration date of the original leases. PNM and each of those lessors entered into amendments to each of the leases setting forth the terms and conditions that would implement the extension of the term of the leases through the agreed upon Maximum Option Period. The four Unit 1 leases now expire on January 15, 2023 and the one Unit 2 lease now

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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, 2015, 2014 and 2013

expires on 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, 2015 shown below includes payments during the renewal periods for those leases that have been extended.

For the three PVNGS Unit 2 leases that did 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. PNM and the lessors under these leases entered into agreements that established the purchase price, representing the fair market value, to be paid by PNM for the assets underlying the leases on January 15, 2016. On January 15, 2016, PNM paid $78.1 million to the lessor under one lease for 31.25 MW of the entitlement from PVNGS Unit 2 and $85.2 million to the lessors under the other two leases for 32.76 MW of the entitlement from PVNGS Unit 2.

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. 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. If such an event had occurred as of December 31, 2015, PNM could have been required to pay the equity participants up to approximately $205.8 million on January 15, 2016 in addition to the scheduled lease payments due on January 15, 2016. 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. Reflecting the asset purchases and lease renewal that were effective on January 15, 2016, if such an event were to occur, amounts payable to equity participants under the circumstances described above would be up to $179.1 million on July 15, 2016 in addition to the scheduled lease payments due on July 15, 2016.

PNM owned 60% of the EIP and leased the other 40%, under a lease that expired on April 1, 2015. The lease provided PNM the option 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. PNM closed on the purchase on April 1, 2015 and recorded the purchase of the assets underlying the lease at that date.

PNMR leased 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 expired on November 30, 2015 and provided for annual rents of $1.9 million, which are included in the operating lease expense table below.

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



	PNMR		PNM		TNMP
	(In thousands)
2015	$	68,652	$	63,558	$	3,688
2014	$	82,756	$	76,745	$	3,932
2013	$	82,882	$	78,306	$	2,663

As discussed under Investments in Note 1, the PVNGS Capital Trust, which was consolidated by PNM through January 15, 2016, acquired the lessor notes that were issued by the PVNGS lessors. Future minimum operating lease payments at December 31, 2015 shown below have been reduced by payments on the PVNGS lessor notes of $9.0 million in 2016 returned in cash to PNM:

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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, 2015, 2014 and 2013



	PNMR		PNM		TNMP
	(In thousands)
2016	$	29,825	$	28,496	$	1,062
2017	26,071		25,413		379
2018	25,240		24,945		15
2019	25,190		24,902		—
2020	25,197		24,902		—
Later years	108,990		108,990		—
Total minimum lease payments	$	240,513	$	237,648	$	1,456


(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. PNM’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. 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, 2015, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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,
	2015			2014
	(In thousands)
PNM and PNMR
Current assets	$	3,813		$	11,232
Deferred charges	2,622			—
	6,435			11,232
Current liabilities	(1,859		)	(1,209		)
Long-term liabilities	—			(477		)
	(1,859		)	(1,686		)
Net	$	4,576		$	9,546

Included in the above table are $3.0 million of current assets and $2.6 million of deferred charges at December 31, 2015 and $3.0 million of current assets at December 31, 2014 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 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, 2015 and 2014.

At December 31, 2015 and 2014, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at December 31, 2015 and 2014, amounts posted as cash collateral under margin arrangements were $2.7 million and $3.8 million for both PNMR and PNM. At December 31, 2015 and 2014, obligations to return cash collateral were $0.1 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 $0.2 million of current liabilities at December 31, 2015 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.

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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, 2015, 2014 and 2013

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,
	2015			2014		2013
	(In thousands)
PNMR and PNM
Electric operating revenues	$	7,156		$	4,491	$	1,727
Cost of energy	(293		)	593		1,109
Total gain	$	6,863		$	5,084	$	2,836

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, 2015
PNMR and PNM	577,481	(3,405,843	)
December 31, 2014
PNMR and PNM	650,000	(1,919,000	)

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

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



Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
December 31, 2015
PNMR and PNM	$	839	$	—	$	839
December 31, 2014
PNMR and PNM	$	1,686	$	—	$	167

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. PNM sells power from its interest in PVNGS Unit 3 at market prices. As of December 31, 2015, PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium. Through hedging arrangements

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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, 2015, 2014 and 2013

that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $26 per MWh, for substantially all of the sales through 2016. There are currently no hedging arrangements in place for the 2017 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 a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 16). At December 31, 2015 and 2014, the fair value of available-for-sale securities included $249.1 million and $244.6 million for the NDT and $9.9 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.



	December 31, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	10,700	$	—	$	8,276
Equity securities:
Domestic value	11,610		44,505		17,418		45,340
Domestic growth	11,163		61,078		21,354		74,053
International and other	1,569		27,961		156		16,599
Fixed income securities:
U.S. Government	178		27,880		903		22,563
Municipals	3,672		58,576		5,851		68,973
Corporate and other	628		28,342		666		14,341
	$	28,820	$	259,042	$	46,348	$	250,145

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 $(4.3) million, $(0.7) million, and $0.6 million for the years ended December 31, 2015, 2014 and 2013.



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Proceeds from sales	$	252,174		$	117,989		$	271,140
Gross realized gains	$	29,663		$	15,162		$	14,308
Gross realized (losses)	$	(9,259	)	$	(3,964	)	$	(4,298	)

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

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

At December 31, 2015, 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	$	3,858	$	8,947	$	8,947
After 1 year through 5 years	24,136		665		—
After 5 years through 10 years	26,401		—		—
After 10 years through 15 years	10,843		—		—
After 15 years through 20 years	10,815		—		—
After 20 years	38,745		—		—
	$	114,798	$	9,612	$	8,947

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, 2015 and 2014.

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.

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, 2015 and 2014 for items recorded at fair value.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
December 31, 2015				(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	10,700		$	10,700	$	—
Equity securities:
Domestic value	44,505			44,505		—
Domestic growth	61,078			61,078		—
International and other	27,961			27,961		—
Fixed income securities:
U.S. Government	27,880			26,608		1,272
Municipals	58,576			—		58,576
Corporate and other	28,342			6,500		21,842
	$	259,042		$	177,352	$	81,690

Commodity derivative assets	$	6,435		$	—	$	6,435
Commodity derivative liabilities	(1,859		)	—		(1,859		)
Net	$	4,576		$	—	$	4,576



				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

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

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013



						GAAP Fair Value Hierarchy
	Carrying Amount			Fair Value		Level 1		Level 2		Level 3
December 31, 2015	(In thousands)
PNMR
Long-term debt	$	2,091,948		$	2,264,869	$	—	$	2,264,869	$	—
Investment in PVNGS lessor notes	$	8,587		$	8,947	$	—	$	—	$	8,947
Other investments	$	604		$	1,269	$	604	$	—	$	665
PNM
Long-term debt	$	1,580,677		$	1,703,209	$	—	$	1,703,209	$	—
Investment in PVNGS lessor notes	$	8,587		$	8,947	$	—	$	—	$	8,947
Other investments	$	366		$	366	$	366	$	—	$	—
TNMP
Long-term debt	$	361,411		$	411,661	$	—	$	411,661	$	—
Other investments	$	238		$	238	$	238	$	—	$	—

December 31, 2014
PNMR
Long-term debt	$	1,962,385	⁽¹⁾	$	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	$	1,482,537	⁽¹⁾	$	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	$	361,241	⁽¹⁾	$	427,356	$	—	$	427,356	$	—
Other investments	$	242		$	242	$	242	$	—	$	—


⁽¹⁾	See Note 6 for an explanation of the adjustments made to the December 31, 2014 carrying value of long-term debt in order to conform to current-year presentation.

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.

On May 2, 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which removed the requirement to categorize investments within the fair value hierarchy for which fair value was measured using a practical expedient provided under GAAP that allows the net asset value per share to be used as fair value for investments in certain entities that do not have readily determinable fair values and are considered to be investment companies. Fair values for alternative investments held by the PNMR Master Trust are valued using this practical expedient. As permitted under the ASU, the Company adopted it as of December 31, 2015. The ASU requires that upon adoption it is to be applied retrospectively to prior years. Accordingly, alternative investments are no longer categorized within the fair value hierarchy and disclosures for December 31, 2014 have been modified to be consistent with 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, 2015, 2014 and 2013

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. Fair values of Level 2 investments in mutual funds are equal to net asset value as of year-end. Level 3 investments are comprised of corporate term loans. Alternative investments 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.

The valuation of Level 3 investments and 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:

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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, 2015, 2014 and 2013



			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, 2015			(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	479,858	$	111,441	$	367,698	$	719
Uncategorized investments	78,461
Total Master Trust Investments	$	558,319

TNMP Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	52,163	$	12,199	$	39,886	$	78
Uncategorized investments	9,968
Total Master Trust Investments	$	62,131

PNM OPEB Plan
Cash and cash equivalents	$	1,512	$	1,512	$	—	$	—
Equity securities:
International funds	10,604		—		10,604		—
Domestic value	9,367		9,367		—		—
Domestic growth	5,894		5,894		—		—
Other funds	28,419		—		28,419		—
Fixed income securities:
Mutual funds	18,343		18,343		—		—
	$	74,139	$	35,116	$	39,023	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	128	$	128	$	—	$	—
Equity securities:
International funds	1,310		—		1,310		—
Domestic value	367		367		—		—
Domestic growth	1,013		1,013		—		—
Other funds	3,397		—		3,397		—
Fixed income securities:
Mutual funds	3,075		3,075		—		—
	$	9,290	$	4,583	$	4,707	$	—

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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, 2015, 2014 and 2013



			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 Investments:
Investments categorized within fair value hierarchy	$	523,142	$	123,668	$	398,819	$	655
Uncategorized investments	64,970
Total Master Trust Investments	$	588,112

TNMP Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	59,320	$	14,823	$	44,425	$	72
Uncategorized investments	9,887
Total Master Trust Investments	$	69,207

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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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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, 2015	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	14,525	$	14,525	$	—	$	—
Equity securities:
International	36,675		—		36,675		—
Domestic value	34,769		34,769		—		—
Domestic growth	25,407		25,407		—		—
Other funds	30,531		—		30,531		—
Fixed income securities:
Corporate	214,218		—		213,421		797
U.S. Government	98,138		48,936		49,202		—
Municipals	16,647		—		16,647		—
Other funds	61,111		3		61,108		—
Total investments categorized within fair value hierarchy	532,021		$	123,640	$	407,584	$	797
Uncategorized investments:
Private equity funds	32,333
Hedge funds	40,731
Real estate funds	15,365
	$	620,450
December 31, 2014
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		—
Total investments categorized within fair value hierarchy	582,462		$	138,491	$	443,244	$	727
Uncategorized investments:
Private equity funds	37,220
Hedge funds	23,876
Real estate funds	13,761
	$	657,319

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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, 2015, 2014 and 2013

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



	Fixed Income - Corporate
PNMR Master Trust	PNM Pension			TNMP Pension			Total Master Trust
	(In thousands)
Balance at December 31, 2013	$	160		$	16		$	176
Actual return on assets sold during the period	—			—			—
Actual return on assets still held at period end	(18		)	(2		)	(20		)
Purchases	546			62			608
Sales	(33		)	(4		)	(37		)
Balance at December 31, 2014	655			72			727
Actual return on assets sold during the period	—			—			—
Actual return on assets still held at period end	(1		)	—			(1		)
Purchases	177			17			194
Sales	(112		)	(11		)	(123		)
Balance at December 31, 2015	$	719		$	78		$	797


(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 (“VIE”). 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, 2015, 2014, and 2013, PNM paid $17.5 million, $19.1 million, and $18.9 million for fixed charges and $1.5 million, $1.2 million, and $1.2 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.

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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, 2015, 2014 and 2013

Summarized financial information for Valencia is as follows:



Results of Operations
	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Operating revenues	$	20,687		$	20,247		$	20,166
Operating expenses	(5,777		)	(6,120		)	(5,645		)
Earnings attributable to non-controlling interest	$	14,910		$	14,127		$	14,521



Financial Position
	December 31,
	2015		2014
	(In thousands)
Current assets	$	2,588	$	2,513
Net property, plant and equipment	69,784		72,321
Total assets	72,372		74,834
Current liabilities	965		1,288
Owners’ equity – non-controlling interest	$	71,407	$	73,546

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) 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. The owner of Valencia subsequently submitted a counter-proposal to PNM in April 2015. PNM is evaluating available options. PNM cannot predict if 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, which initially 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 lease agreements was with a different trust whose beneficial owners were 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. See Note 7 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. At January 15, 2015, the four Unit 1 leases were extended. At January 15, 2016, one of the Unit 2 leases was extended and PNM purchased the assets underlying the other three Unit 2 leases. Prior to their exercise or expiration, the fixed rate renewal options were considered to be variable interests in the trusts and resulted in the trusts being considered variable interest entities under GAAP. Upon execution of documents establishing terms of the asset purchases or lease extensions, the fixed rate renewal options ceased to exist as did PNM’s variable interest in the trusts. PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments and has no other financial obligations or commitments to the trusts or the beneficial owners although PNM is

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

responsible for all decommissioning obligations related to its entire interest in PVNGS both during and after termination of the leases. 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 $18.4 million and $26.0 million at December 31, 2015 and 2014, which are included in other current liabilities on the Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to the renewal and purchase options 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 were 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 had 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.

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 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. Delta had project financing debt, amounting to $14.6 million at closing, which was retired at closing. 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 year ended December 31, 2013, PNM incurred fixed capacity charges of $6.4 million and variable energy charges of $1.8 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, 2015, 2014 and 2013


(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,
	2015		2014		2013
	(In thousands, except per share amounts)
Earnings Attributable to PNMR	$	15,640	$	116,254	$	100,507
Average Number of Common Shares:
Outstanding during year	79,654		79,654		79,654
Vested awards of restricted stock	105		134		191
Average Shares – Basic	79,759		79,788		79,845
Dilutive Effect of Common Stock Equivalents ⁽¹⁾:
Stock options and restricted stock	380		491		586
Average Shares – Diluted	80,139		80,279		80,431
Net Earnings Per Share of Common Stock:
Basic	$	0.20	$	1.46	$	1.26
Diluted	$	0.20	$	1.45	$	1.25
Dividends Declared per Common Share	$	0.820	$	0.755	$	0.680


⁽¹⁾	Excludes out-of-the-money options for 2,100 shares of common stock at December 31, 2015. See Note 13.


(11)	Income Taxes

PNMR

PNMR’s income taxes consist of the following components:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Current federal income tax	$	—		$	(2,015	)	$	—
Current state income tax	(1,376		)	(728		)	(917		)
Deferred federal income tax	5,488			59,814			50,044
Deferred state income tax	12,305			14,831			12,578
Amortization of accumulated investment tax credits	(1,342		)	(2,164		)	(2,192		)
Total income taxes	$	15,075		$	69,738		$	59,513

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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,
	2015			2014			2013
	(In thousands)
Federal income tax at statutory rates	$	16,154		$	70,226		$	61,274
Amortization of accumulated investment tax credits	(1,342		)	(2,164		)	(2,192		)
Flow-through of depreciation items	1,485			1,344			1,132
Earnings attributable to non-controlling interest in Valencia	(5,218		)	(4,945		)	(5,082		)
State income tax, net of federal benefit	(1,781		)	5,723			3,818
Impairment of state net operating loss carryforwards	5,278			3,129			—
Impairment of state production tax credits	3,092			894			3,880
Allowance for equity funds used during construction	(3,650		)	(1,947		)	(1,534		)
Reversal of deferred items related to BART at SJGS	1,826			—			—
Impairment of charitable contribution carryforward	2,042			—			—
Other	(2,811		)	(2,522		)	(1,783		)
Total income taxes	$	15,075		$	69,738		$	59,513
Effective tax rate	32.66		%	34.76		%	33.99		%

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



	December 31,
	2015			2014
	(In thousands)
Deferred tax assets:
Net operating loss	$	161,691		$	153,858
Regulatory liabilities related to income taxes	80,031			78,858
Federal tax credit carryforwards	77,417			54,748
Shutdown of SJGS Units 2 and 3	53,823			—
Other	70,749			68,566
Total deferred tax assets	443,711			356,030
Deferred tax liabilities:
Depreciation and plant related	(1,027,047		)	(914,926		)
Investment tax credit	(56,589		)	(36,790		)
Regulatory assets related to income taxes	(71,054		)	(67,910		)
CTC	(16,151		)	(19,352		)
Pension	(65,226		)	(66,498		)
Other	(85,037		)	(115,282		)
Total deferred tax liabilities	(1,321,104		)	(1,220,758		)
Net accumulated deferred income tax liabilities	$	(877,393	)	$	(864,728	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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, 2015
	(In thousands)
Net change in deferred income tax liability per above table	$	12,665
Change in tax effects of income tax related regulatory assets and liabilities	(1,896		)
Tax effect of mark-to-market adjustments	6,844
Tax effect of excess pension liability	(607		)
Adjustment for uncertain income tax positions	(8,576		)
Reclassification of unrecognized tax benefits	8,576
Other	(555		)
Deferred income taxes	$	16,451

PNM

PNM’s income taxes (benefit) consist of the following components:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Current federal income tax	$	(7,934	)	$	(2,175	)	$	(479	)
Current state income tax	(1,988		)	(979		)	(760		)
Deferred federal income tax	(6,827		)	45,890			42,806
Deferred state income tax	5,333			12,061			9,429
Amortization of accumulated investment tax credits	(1,342		)	(2,164		)	(2,192		)
Total income taxes (benefit)	$	(12,758	)	$	52,633		$	48,804

PNM’s provision for income taxes (benefit) 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:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Federal income tax (benefit) at statutory rates	$	(4,579	)	$	53,930		$	53,018
Amortization of accumulated investment tax credits	(1,342		)	(2,164		)	(2,192		)
Flow-through of depreciation items	1,465			1,325			1,115
Earnings attributable to non-controlling interest in Valencia	(5,218		)	(4,945		)	(5,082		)
State income tax, net of federal benefit	(2,162		)	5,522			6,202
Impairment of state net operating loss carryforwards	3,619			2,145			—
Allowance for equity funds used during construction	(3,650		)	(1,947		)	(1,534		)
Reversal of deferred items related to BART at SJGS	1,826			—			—
Reversal of deferred income taxes accrued at prior tax rates	(737		)	(737		)	(737		)
Other	(1,980		)	(496		)	(1,986		)
Total income taxes (benefit)	$	(12,758	)	$	52,633		$	48,804
Effective tax rate	97.52		%	34.16		%	32.22		%

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



	December 31,
	2015			2014
	(In thousands)
Deferred tax assets:
Net operating loss	$	116,693		$	108,505
Regulatory liabilities related to income taxes	75,889			74,293
Federal tax credit carryforwards	57,928			35,259
Shutdown of SJGS Units 2 and 3	53,823			—
Other	41,210			35,681
Total deferred tax assets	345,543			253,738
Deferred tax liabilities:
Depreciation and plant related	(828,926		)	(733,519		)
Investment tax credit	(56,589		)	(36,790		)
Regulatory assets related to income taxes	(61,018		)	(57,637		)
Pension	(58,070		)	(58,474		)
Other	(37,324		)	(70,714		)
Total deferred tax liabilities	(1,041,927		)	(957,134		)
Net accumulated deferred income tax liabilities	$	(696,384	)	$	(703,396	)

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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, 2015
	(In thousands)

Net change in deferred income tax liability per above table	$	(7,012	)
Change in tax effects of income tax related regulatory assets and liabilities	(1,784		)
Tax effect of mark-to-market adjustments	6,872
Tax effect of excess pension liability	(607		)
Adjustment for uncertain income tax positions	(8,576		)
Reclassification of unrecognized tax benefits	8,576
Other	(305		)
Deferred income taxes	$	(2,836	)

TNMP

TNMP’s income taxes consist of the following components:



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Current federal income tax	$	1,603		$	35		$	(4,957	)
Current state income tax	1,639			1,939			1,916
Deferred federal income tax	20,904			20,577			20,688
Deferred state income tax	(21		)	(28		)	(26		)
Total income taxes	$	24,125		$	22,523		$	17,621

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,
	2015			2014			2013
	(In thousands)
Federal income tax at statutory rates	$	23,131		$	21,115		$	16,349
State income tax, net of federal benefit	1,065			1,257			1,247
Other	(71		)	151			25
Total income taxes	$	24,125		$	22,523		$	17,621
Effective tax rate	36.50		%	37.33		%	37.72		%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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



	December 31,
	2015			2014
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	4,141		$	4,565
Other	6,702			13,429
Total deferred tax assets	10,843			17,994
Deferred tax liabilities:
Depreciation and plant related	(189,322		)	(174,510		)
CTC	(16,151		)	(19,352		)
Regulatory assets related to income taxes	(10,036		)	(10,273		)
Loss on reacquired debt	(12,392		)	(12,846		)
Other	(15,733		)	(12,560		)
Total deferred tax liabilities	(243,634		)	(229,541		)
Net accumulated deferred income tax liabilities	$	(232,791	)	$	(211,547	)

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, 2015
	(In thousands)
Net change in deferred income tax liability per above table	$	21,244
Change in tax effects of income tax related regulatory assets and liabilities	(111		)
Other	(250		)
Deferred income taxes	$	20,883

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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, 2012	$	19,198		$	10,382		$	6,796
Additions based on tax positions related to 2013	(54		)	(54		)	—
Additions (reductions) 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			—
Additions based on tax positions related to 2015	1,214			1,214			—
Additions (reductions) for tax positions of prior years	(9,790		)	(9,790		)	—
Settlement payments	—			—			—
Balance at December 31, 2015	$	6,455		$	3,652		$	—

Included in the balance at December 31, 2015 are $5.9 million and $3.1 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 2016.

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)
2015	$	—	$	—	$	—
2014	$	146	$	148	$	(2	)
2013	$	242	$	251	$	(2	)

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



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2015:
Accumulated accrued interest receivable	$	3,236		$	3,236		$	—
Accumulated accrued interest payable	$	(1,120	)	$	(24	)	$	(120	)
December 31, 2014:
Accumulated accrued interest receivable	$	3,569		$	3,569		$	—
Accumulated accrued interest payable	$	(1,120	)	$	(24	)	$	(120	)

The Company files a federal consolidated and several consolidated and separate state income tax returns. The tax years prior to 2012 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, 2015, the Company has $427.4 million of federal net operating loss carryforwards that expire

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

beginning in 2030 and $77.4 million of federal tax credit carryforwards that expire beginning in 2023. State net operating losses expire beginning in 2016 and vary from federal due to differences between state and federal tax law.

In 2013, New Mexico House Bill 641 reduced 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. 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. 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. Adjustments to deferred income taxes recorded as increases (decreases) in the regulatory liability and income tax expense are as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2015:
Regulatory liability	$	(1,903	)	$	(1,903	)	$	—
Income tax expense	$	(674	)	$	(470	)	$	—
December 31, 2014:
Regulatory liability	$	(5,106	)	$	(5,106	)	$	—
Income tax expense	$	(71	)	$	(312	)	$	—
December 31, 2013:
Regulatory liability	$	23,896		$	23,896		$	—
Income tax expense	$	1,233		$	—		$	—

In 2008, fifty percent bonus tax depreciation was enacted as a temporary two-year stimulus measure as part of the Economic Stimulus Act of 2008. Bonus tax depreciation in various forms has been continuously extended since that time, most recently by the Protecting Americans from Tax Hikes Act of 2015. The 2015 act extends and phases-out bonus tax depreciation through 2019. As a result of the net operating loss carryforwards for income tax purposes created by bonus depreciation, and reduced future income taxes payable resulting from New Mexico House Bill 641, certain tax carryforwards are not expected to be utilized before their expiration. In accordance with GAAP, PNMR and PNM have impaired the tax carryforwards which were not expected to be utilized prior to their expiration. The impairments, net of federal tax benefit, for 2013 through 2015 are as follows:



	PNMR		PNM		TNMP
	(In thousands)
December 31, 2015:
State tax credit carryforwards	$	3,092	$	—	$	—
State net operating loss carryforwards	$	5,278	$	3,619	$	—
Charitable contribution carryforwards	$	2,042	$	—	$	—
December 31, 2014:
State tax credit carryforwards	$	894	$	—	$	—
State net operating loss carryforwards	$	3,129	$	2,145	$	—
December 31, 2013:
State tax credit carryforwards	$	3,880	$	—	$	—

The impairments of unexpired state tax credits, state net operating loss, and charitable contribution carryforwards are reflected as a valuation allowance against deferred tax assets. The reserve balances, after reflecting expiration of carryforwards under applicable tax laws, at December 31, 2015 and 2014 are as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013



	PNMR		PNM		TNMP
	(In thousands)
December 31, 2015:
State tax credit carryforwards	$	6,378	$	—	$	—
State net operating loss carryforwards	$	361	$	248	$	—
Charitable contribution carryforwards	$	659	$	—	$	—
December 31, 2014:
State tax credit carryforwards	$	5,492	$	—	$	—
State net operating loss carryforwards	$	3,129	$	2,145	$	—

PNMR adopted the safe harbor method of accounting for repairs costs on electric generation property under IRS Revenue Procedure 2013-24 on its 2014 corporate income tax return. PNMR had previously adopted similar safe harbor accounting methods for repair costs on electric transmission and distribution property. Additionally, on its 2014 tax return PNMR adopted certain accounting methods required by the IRS tangible property regulations issued in September 2013. The effects of these changes were immaterial, given PNMR’s net operating loss carryforward position.

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 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.

On November 20, 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740) - Balance Sheet Classification of Deferred Taxes, which eliminated the requirement to classify deferred tax assets and liabilities as non-current or current. Under ASU 2015-17, all deferred taxes are treated as non-current. As of December 31, 2015, the Company adopted ASU 2015-17 and elected to apply it retrospectively for all periods presented because it simplifies reporting and makes all presented periods comparable. As a result, amounts previously reported as the current portion of accumulated deferred income taxes in Current Assets on the December 31, 2014 Consolidated Balance Sheets were reclassified to reduce accumulated deferred income taxes in Deferred Credits and Other Liabilities. The amounts reclassified were $26.4 million for PNMR, $12.4 million for PNM, and $6.4 million for TNMP.

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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, 2015, 2014 and 2013


(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 or returned through 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, 2015, 2014 and 2013

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,
	2015			2014			2015			2014
	(In thousands)
PBO at beginning of year	$	657,557		$	599,537		$	72,305		$	66,159
Service cost	—			—			—			—
Interest cost	28,255			30,163			3,043			3,193
Actuarial (gain) loss	(38,151		)	72,524			(5,157		)	8,466
Benefits paid	(49,761		)	(44,667		)	(5,993		)	(5,513		)
PBO at end of year	597,900			657,557			64,198			72,305
Fair value of plan assets at beginning of year	587,909			556,353			69,177			66,118
Actual return on plan assets	(10,225		)	76,223			(1,102		)	8,572
Employer contributions	30,000			—			—			—
Benefits paid	(49,761		)	(44,667		)	(5,993		)	(5,513		)
Fair value of plan assets at end of year	557,923			587,909			62,082			69,177
Funded status – asset (liability) for pension benefits	$	(39,977	)	$	(69,648	)	$	(2,116	)	$	(3,128	)

The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2015.



	PNM Plan						TNMP Plan
	December 31, 2015						December 31, 2015
	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	$	(2,260	)	$	148,212		$	—
Experience loss (gain)	—			11,397			365
Regulatory asset (liability) adjustment	—			(6,610		)	(365		)
Amortization recognized in net periodic benefit cost (income)	405			(6,224		)	—
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(1,855	)	$	146,775		$	—
Amortization expected to be recognized in 2016	$	(405	)	$	5,399		$	—

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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, 2015, 2014 and 2013

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



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
PNM Plan
Service cost	$	—		$	—		$	—
Interest cost	28,255			30,163			28,142
Expected return on plan assets	(39,323		)	(38,044		)	(41,930		)
Amortization of net (gain) loss	14,820			13,020			14,840
Amortization of prior service cost	(965		)	(965		)	76
Net periodic benefit cost	$	2,787		$	4,174		$	1,128
TNMP Plan
Service cost	$	—		$	—		$	—
Interest cost	3,043			3,193			3,087
Expected return on plan assets	(4,420		)	(4,526		)	(4,849		)
Amortization of net (gain) loss	782			665			1,049
Amortization of prior service cost	—			—			—
Net periodic benefit cost (income)	$	(595	)	$	(668	)	$	(713	)

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	2015		2014		2013
Discount rate for determining December 31 PBO	5.29	%	4.48	%	5.27	%
Discount rate for determining net periodic benefit cost (income)	4.48	%	5.27	%	4.30	%
Expected return on plan assets	6.80	%	7.20	%	7.65	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.39	%	4.39	%	5.06	%
Discount rate for determining net periodic benefit cost (income)	4.39	%	5.06	%	4.19	%
Expected return on plan assets	6.80	%	7.20	%	7.65	%
Rate of compensation increase	N/A		N/A		N/A

The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. Changes in discount rates resulted in a decrease in the PNM PBO of $45.9 million at December 31, 2015 and an increase of $50.6 million at December 31, 2014. Changes in discount rates resulted in a decrease in the TNMP PBO of $6.1 million at December 31, 2015 and an increase of $5.1 million at December 31, 2014. Changes in demographic experience resulted in actuarial losses in the PNM PBO of $2.8 million and $0.2 million at December 31, 2015 and 2014. Changes in demographic experience resulted in actuarial losses in the TNMP PBO of $0.9 million at December 31, 2015 and actuarial gains of $0.4 million at December 31, 2014. Changes in other assumptions and experience resulted in actuarial losses in the PNM PBO of $4.9 million at December 31, 2015 and actuarial gains of less than $0.2 million at December 31, 2014. Changes in other assumptions and experience resulted in actuarial losses in the TNMP PBO of less than $0.1 million and $1.3 million at December 31, 2015 and 2014. These changes are reflected as actuarial (gain) loss above.

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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, 2015, 2014 and 2013

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, 2015 and 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 in 2014, 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 2016 net periodic cost to increase $5.4 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 (1.7)% and (1.7)% for the year ended December 31, 2015.

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)
2016	$	49,963	$	5,800
2017	49,681		5,416
2018	48,209		5,697
2019	47,476		5,218
2020	46,474		4,955
2021 – 2025	213,810		23,401

The Company does not expect to make any contributions to the pension plans in 2016-2020, based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These anticipations were developed using current funding assumptions with discount rates of 4.8% to 5.7%. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. PNM and TNMP may make additional contributions at their discretion.

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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, 2015, 2014 and 2013

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,
	2015			2014			2015			2014
	(In thousands)
APBO at beginning of year	$	95,175		$	92,165		$	14,070		$	12,266
Service cost	204			181			247			237
Interest cost	4,089			4,630			608			619
Participant contributions	2,439			2,582			320			366
Actuarial (gain) loss	(6,565		)	4,455			(575		)	1,639
Benefits paid	(10,668		)	(8,838		)	(1,564		)	(1,057		)
APBO at end of year	84,674			95,175			13,106			14,070
Fair value of plan assets at beginning of year	78,175			73,565			10,094			9,601
Actual return on plan assets	(617		)	7,334			(82		)	841
Employer contributions	3,623			3,532			343			343
Participant contributions	2,439			2,582			320			366
Benefits paid	(10,668		)	(8,838		)	(1,564		)	(1,057		)
Fair value of plan assets at end of year	72,952			78,175			9,111			10,094
Funded status – asset (liability)	$	(11,722	)	$	(17,000	)	$	(3,995	)	$	(3,976	)

In the years ended December 31, 2015, actuarial gains of $0.3 million were recorded as adjustments to regulatory assets for the PNM Plan. For the TNMP Plan, actuarial losses of less than $0.1 million were recorded as adjustments to regulatory liabilities.

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



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
PNM Plan
Service cost	$	204		$	181		$	260
Interest cost	4,089			4,630			4,113
Expected return on plan assets	(5,610		)	(5,638		)	(5,043		)
Amortization of net (gain) loss	1,966			2,225			4,242
Amortization of prior service credit	(642		)	(1,343		)	(1,343		)
Net periodic benefit cost	$	7		$	55		$	2,229
TNMP Plan
Service cost	$	247		$	237		$	299
Interest cost	608			619			566
Expected return on plan assets	(520		)	(534		)	(503		)
Amortization of net (gain) loss	—			(122		)	—
Amortization of prior service cost	—			32			57
Net periodic benefit cost	$	335		$	232		$	419

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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, 2015, 2014 and 2013

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	2015		2014		2013
Discount rate for determining December 31 APBO	5.34	%	4.45	%	5.21	%
Discount rate for determining net periodic benefit cost	4.45	%	5.21	%	4.26	%
Expected return on plan assets	7.70	%	8.50	%	8.50	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 APBO	5.34	%	4.45	%	5.21	%
Discount rate for determining net periodic benefit cost	4.45	%	5.21	%	4.26	%
Expected return on plan assets	5.70	%	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 a decrease in the PNM APBO of $7.3 million at December 31, 2015 and an increase of $6.7 million at December 31, 2014. Changes in discount rates resulted in a decrease in the TNMP APBO of $1.3 million at December 31, 2015 and an increase of $1.1 million at December 31, 2014. Changes in claims, contributions, medical trends, and demographic experience resulted in an actuarial loss in the PNM plan of $0.7 million at December 31, 2015 and an actuarial gain of $5.4 million at December 31, 2014. Changes in claims, contributions, and demographic experience resulted in an actuarial losses of $0.7 million change in the TNMP plan at December 31, 2015 and less than $0.1 million at December 31, 2014. These changes are reflected as actuarial (gain) loss above.

The actuarial valuations performed as of December 31, 2015 and 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 in 2014, 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 2016 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 (0.8)% and (0.5)% for the year ended December 31, 2015.

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



	PNM Plan
	December 31,
	2015		2014
Health care cost trend rate assumed for next year	7.0	%	7.0	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	5.0	%	5.0	%
Year that the rate reaches the ultimate trend rate	2024		2023

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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, 2015, 2014 and 2013

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	$	273	$	(235	)
Effect on APBO	$	4,370	$	(3,840	)

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 and are net of participant contributions, are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2016	$	6,568	$	838
2017	6,667		858
2018	6,815		880
2019	6,830		903
2020	6,875		927
2021 - 2025	33,268		4,939

PNM expects to make contributions to the PNM postretirement benefit plan totaling $3.5 million in 2016 and $14.0 million for 2017-2020. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.3 million in 2016 and $1.4 million for 2017-2020.

Executive Retirement Programs

For the executive retirement programs, the following table presents information about the PBO and funded status of the plans:

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2015			2014			2015			2014
	(In thousands)
PBO at beginning of year	$	17,730		$	16,363		$	878		$	823
Service cost	—			—			—			—
Interest cost	760			822			36			39
Actuarial (gain) loss	(908		)	2,040			(26		)	110
Benefits paid	(1,477		)	(1,495		)	(94		)	(94		)
PBO at end of year – funded status	16,105			17,730			794			878
Less current liability	1,519			1,528			93			94
Non-current liability	$	14,586		$	16,202		$	701		$	784

The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2015.



	December 31, 2015
	PNM Plan			TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,602		$	—
Experience loss (gain)	(908		)	26
Regulatory asset (liability) adjustment	526			(26		)
Amortization recognized in net periodic benefit cost (income)	(136		)	—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,084		$	—
Amortization expected to be recognized in 2016	$	108		$	—

The following table presents the components of net periodic benefit:



	Year Ended December 31,
	2015		2014		2013
	(In thousands)
PNM Plan
Service cost	$	—	$	—	$	—
Interest cost	760		822		720
Amortization of net (gain) loss	325		210		232
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	1,085	$	1,032	$	952
TNMP Plan
Service cost	$	—	$	—	$	—
Interest cost	36		39		36
Amortization of net (gain) loss	5		—		—
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	41	$	39	$	36

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.

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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, 2015, 2014 and 2013



	Year Ended December 31,
PNM Plan	2015		2014		2013
Discount rate for determining December 31 PBO	5.29	%	4.48	%	5.27	%
Discount rate for determining net periodic benefit cost	4.48	%	5.27	%	4.30	%
Long-term rate of return on plan assets	N/A		N/A		N/A
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	5.39	%	4.39	%	5.06	%
Discount rate for determining net periodic benefit cost	4.39	%	5.06	%	4.19	%
Long-term rate of return on plan assets	N/A		N/A		N/A
Rate of compensation increase	N/A		N/A		N/A

The assumed discount rate for determining the PBO was determined based on a review of long-term high-grade bonds and management’s expectations. The impacts of changes in assumptions or experience were not significant.

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



	PNM Plan		TNMP Plan
	(In thousands)
2016	$	1,517	$	93
2017	1,499		92
2018	1,477		90
2019	1,453		88
2020	1,426		85
2021 – 2025	6,587		371

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 had been allowed to save on an after-tax basis. This plan has been amended and the after-tax provision was eliminated as of June 30, 2015.

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December 31, 2015, 2014 and 2013

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



	Year Ended December 31,
	2015		2014		2013
	(In thousands)
PNMR
401(k) plan	$	16,725	$	16,703	$	16,785
Non-qualified plan	$	1,436	$	2,257	$	2,204
PNM
401(k) plan	$	12,679	$	12,745	$	12,952
Non-qualified plan	$	1,090	$	1,722	$	1,691
TNMP
401(k) plan	$	4,046	$	3,958	$	3,953
Non-qualified plan	$	346	$	535	$	513


(13)	Stock-Based Compensation

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. Other awards of restricted stock are only subject to time vesting requirements.

Performance Equity Plan

The PEP provides for the granting of non-qualified stock options, restricted stock rights, performance shares, performance units, and stock appreciation rights to officers, key employees, and non-employee board members. Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions 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, 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 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

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December 31, 2015, 2014 and 2013

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 had no impact on the Company.

Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2015, 2014, and 2013 was $4.9 million, $5.9 million, and $5.3 million. Stock compensation expense of $3.6 million, $4.2 million, and $3.8 million was charged to PNM and $1.3 million, $1.7 million, and $1.5 million was charged to TNMP. At December 31, 2015, PNMR had unrecognized compensation expense related to stock awards of $5.7 million, which are expected to be recognized over an average of 1.4 years.

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.

The grant date fair value for restricted stock and stock awards with Company internal performance targets is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end. The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:



	Year Ended December 31,
Restricted Shares and Performance-Based Shares	2015			2014			2013
Expected quarterly dividends per share	$	0.200		$	0.185		$	0.165
Risk-free interest rate	0.92		%	0.62		%	0.34		%

Market-Based Shares
Dividend yield	2.87		%	2.82		%	2.86		%
Expected volatility	18.73		%	25.11		%	25.11		%
Risk-free interest rate	1.00		%	0.64		%	0.36		%

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, 2014	258,770		$	22.31	920,505		$	20.39
Granted	340,020		$	20.34	—		$	—
Exercised	(349,635	)	$	18.61	(280,612	)	$	20.13
Forfeited	(4,061	)	$	24.81	(1,000	)	$	30.50
Expired	—		—		(69,551	)	$	28.02
Outstanding at December 31, 2015	245,094		$	24.81	569,342		$	19.35

PNMR’s stock-based compensation program provides for performance and market targets through 2017. Included as restricted stock granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012

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December 31, 2015, 2014 and 2013

through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “maximum” levels, weighted at 40%, for 2012 through 2014 performance period. Excluded from the above table are 79,619 previously awarded shares that were earned for the 2013 through 2015 performance measurement period and approved by the Board in February 2016 (based upon achieving market targets at “target” levels, weighted at 60%, and performance targets at “threshold” levels, weighted at 40%), as well as maximums of 165,628 and 168,258 shares for the three-year performance periods ending in 2016 and 2017 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, which shares are included as granted and exercised in the above table. 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 that remain unvested 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 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.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement.

At December 31, 2015, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.4 million with a weighted-average remaining contract life of 2.27 years. At December 31, 2015, the exercise price of 2,100 outstanding stock options was 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	2015		2014		2013
Weighted-average grant date fair value	$	20.34	$	21.27	$	20.03
Total fair value of restricted shares that vested (in thousands)	$	6,507	$	4,933	$	4,395

Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—	$	625
Total intrinsic value of options exercised (in thousands)	$	2,350	$	2,473	$	2,721

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December 31, 2015, 2014 and 2013


(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. The Four Corners owners executed amendments to the agreements governing the operations of Four Corners that would extend those agreements until July 2041. The amendments are expected to become effective in July 2016.

PNM’s expenditures for additions to utility plant were $404.8 million in 2015, 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 $124.6 million during 2015. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $558.6 million in 2015.

Joint Projects

Under the agreements for the jointly-owned projects, PNM has an undivided interest in each asset and liability of the project and records its pro-rata share of each item in the corresponding asset and liability account on PNM’s Consolidated Balance Sheets. Likewise, PNM records its pro-rata share of each item of operating and maintenance expenses for its jointly-owned plants within the corresponding operating expense account in its Consolidated Statements of Earnings. PNM is responsible for financing its share of the capital and operating costs of the joint projects.

At December 31, 2015, 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⁾	$	1,083,331	$	(428,684	)	$	20,117	46.30	%
PVNGS (Nuclear) ⁽²⁾	$	562,412	$	(164,549	)	$	38,966	10.20	%
Four Corners Units 4 and 5 (Coal)	$	167,874	$	(102,559	)	$	19,390	13.00	%
Luna (Gas)	$	69,259	$	(23,048	)	$	33	33.33	%

⁽¹⁾

As discussed in Note 16, the NMPRC has approved the shutdown of SJGS Units 2 and 3 as of December 31, 2017. At December 31, 2015, PNM’s carrying value for its current ownership share of SJGS Units 2 and 3 included plant in service of $468.2 million, accumulated depreciation and amortization of $193.3 million, and construction work in progress of $2.2 million for a net undepreciated net book value of $277.1 million, which amounts are included in the table above. At December 31, 2015, PNM recorded a regulatory disallowance of $127.6 million representing its estimate of the portion of the December 31, 2017 net book value of SJGS Units 2 and 3 that will not be recovered from ratepayers, which is reflected as a reduction of plant in service on the Consolidated Balance Sheets.


⁽²⁾	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 MSR, 10.04% by Anaheim, 8.475% by Farmington, 7.2% by Los Alamos, and 7.028% by UAMPS. See Note 16 for additional information about SJGS, including the agreement for restructuring of SJGS ownership. Under the restructuring agreement, PNM would own 64.5% of Unit 4, PNMR Development would own 12.8% of Unit 4, and SCPPA, Tri-State, MSR, and Anaheim would no longer have any ownership interest in SJGS following the December 31, 2017 restructuring. PNMR anticipates that the interest of PNMR Development will be transferred to PNM, as authorized by the NMPRC, prior to the restructuring date.

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 co

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December 31, 2015, 2014 and 2013

ncerning 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. 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.

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:



	2016		2017		2018		2019		2020		Total
					(In millions)
PNM	$	396.4	$	295.1	$	269.3	$	220.3	$	183.7	$	1,364.8
TNMP	114.6		101.1		114.3		117.0		126.3		573.3
Corporate and Other	35.8		18.9		14.1		15.1		15.0		98.9
Total PNMR	$	546.8	$	415.1	$	397.7	$	352.4	$	325.0	$	2,037.0

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 $1.3 million related to environmental upgrades at SJGS to address regional haze and $100.8 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 environmental upgrades at Four Corners estimated to be $88.7 million, and the $163.3 million purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases on January 15, 2016.


(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:

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December 31, 2015, 2014 and 2013



	PNMR			PNM			TNMP
	(In thousands)
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
Liabilities incurred	—			—			—
Liabilities settled	(730		)	(506		)	(224		)
Accretion expense	8,625			8,543			71
Revisions to estimated cash flows⁽²⁾	(170		)	(170		)	—
Liability at December 31, 2015	$	111,895		$	111,049		$	695

⁽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 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.

⁽²⁾

Based on studies to estimate the amount and timing of future ARO expenditures. PNM has an ARO for Four Corners that includes obligations for decommissioning of that facility. In 2015, a new decommissioning study for Four Corners was implemented reflecting updated cash flow estimates. The new study resulted in an increase of $1.0 million to the ARO. In addition, a new decommissioning study for SJGS was implemented in 2015, resulting in a $1.2 million decrease 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 periodically 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 any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable.

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December 31, 2015, 2014 and 2013

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 in each of the years ended December 31, 2015, 2014, and 2013 into the qualified and non-qualified trust funds. The market value of the trusts at December 31, 2015 and 2014 was $249.1 million and $244.6 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. The lawsuits filed by APS alleged that 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, which establishes a process for the payment of claims for costs incurred through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM’s share of settlements under this process were $5.9 million, substantially all of which was credited back to PNM’s customers, for costs incurred from January 2007 through June 2011, which was recorded in the fourth quarter of 2014, and $4.3 million, including $3.1 million credited back to PNM’s customers, for costs incurred from July 2011 through June 2014, which was recorded in the first quarter of 2015. In the second quarter of 2015, PNM recorded claims of $1.3 million, including $0.5 million credited back to PNM’s customers, for costs incurred between July 1, 2014 and June 30, 2015. Thereafter, PNM began recording estimated claims quarterly. The settlement agreement terminates upon payment of costs incurred 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, 2015 and 2014, PNM had a liability for interim storage costs of $12.2 million and $12.3 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 (the “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.

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

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December 31, 2015, 2014 and 2013

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. PNM is unable to predict the outcome of this matter.

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. 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 ruled that BART required to reduce NOx emissions from SJGS was 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.

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. 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.

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December 31, 2015, 2014 and 2013

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013. EPA’s final rules approving the RSIP and withdrawing the FIP became effective on November 10, 2014.

In addition to the SNCR equipment required by the RSIP, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). The requirement to install BDT was made binding and enforceable in the NSR permit issued by NMED 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 entered into a contract for installation of SCRs on SJGS in October 2012. At that time, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, including BDT equipment to assist with compliance with the NAAQS requirements and to eliminate all fugitive boiler emissions. The construction contract was terminated in December 2014 following approval of the RSIP by EPA. 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, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been 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 and entered into contracts for the equipment and installation of SNCRs, including BDT equipment, on SJGS Units 1 and 4. Installation of SNCRs on Unit 1 and BDT equipment on both Units 1 and 4 was completed in 2015 and installation of SNCRs on Unit 4 was completed in January 2016, which dates were within the timeframe contained in the RSIP. PNM’s share of the total costs for SNCRs and BDT equipment was $78.0 million. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 will increase with the installation of SNCR and BDT equipment.

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

PNM’s filing also addressed replacement of the capacity from the shutdown of SJGS Units 2 and 3, which, as proposed, would have reduced PNM’s ownership in SJGS by 340 MW, including possible increase in PNM’s ownership in SJGS Unit 4, the identification of a new 177 MW natural gas-fired generation source, and 40 MW of new utility-scale solar PV. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 17.

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 regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). 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.

On October 1, 2014, PNM and certain intervenors filed a stipulation with the NMPRC that, if approved by the NMPRC, would have settled all matters in PNM’s filing. Statements of opposition were filed by other intervenors. A public hearing in the NMPRC case was held in January 2015. On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommended the NMPRC reject the stipulation as proposed. The certification recommended approvals of certain provisions in the stipulation, as well as modifications or rejections of other provisions. Among other things, the certification cited the lack of final restructuring and post-2017 coal supply agreements for SJGS.

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On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015, which date was subsequently extended to August 1, 2015. On July 1, 2015, PNM filed executed coal supply and related agreements, described under Coal Supply below, with the NMPRC. On July 31, 2015, PNM filed executed restructuring agreements.

In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. On August 13, 2015, as a result of the facilitation process, PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, and the Coalition for Clean Affordable Energy filed a settlement agreement with the NMPRC. NMIEC, Interwest Energy Alliance, and New Mexico Independent Power Producers subsequently joined in this agreement and NEE filed in opposition to the agreement. The stipulating parties agreed that the October 2014 stipulation should be approved, as modified by the settlement agreement (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement:


•	PNM will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% of their undepreciated net book value at that date and earn a regulated return on those costs


•	PNM will be granted an unconditional CCN for 132 MW in SJGS Unit 4, with an initial book value of zero, plus the costs of SNCR and other capital additions


•	PNM will be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (estimated to be approximately $150 million)


•	No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position and supporting testimony in an NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties agree to support this case being decided within six months


•	PNM will be authorized to acquire 65 MW of SJGS Unit 4 as excluded utility plant; PNM and PNMR commit that no further coal-fired merchant plant will be acquired at any time by PNM, PNMR, or any PNM affiliate; PNM is not precluded from seeking a CCN to include the 65 MW or other coal capacity in rate base

•

Beginning January 1, 2020, for every MWh produced by 197 MW of coal-fired generation from PNM’s ownership share of SJGS, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO₂ emission attribute compliant with EPA’s Clean Power Plan; this REC retirement is in addition to what is required to meet the RPS; the cost of these RECs are to be capped at $7.0 million per year and will be recovered in rates; PNM should purchase EPA-compliant RECs from New Mexico renewable generation unless those RECs are more costly


•	PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022; cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case consistent with the Certification of Stipulation


•	Not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	PNM’s 2014 IRP docket will be closed without other NMPRC action

The Hearing Examiner scheduled a hearing on PNM’s application concerning BART for SJGS to begin on October 13, 2015. NEE previously filed motions before the NMPRC requesting that four of the five NMPRC commissioners recuse themselves, alleging they had improper ex-parte communications, were biased, and had pre-judged the outcome of the BART case. Each of the four commissioners declined to recuse themselves. On October 5, 2015, NEE filed a Petition for a Writ of Mandamus and Request for Stay in the NMSC requesting the four commissioners be recused from this case and that PNM’s application be dismissed. On October 9, 2015, the NMSC issued orders that allowed the hearing conducted by the Hearing Examiner to proceed, but ordered that any action by the NMPRC be stayed, pending a decision by the NMSC on NEE’s petition. The hearing on the Stipulated Settlement was held from October 13, 2015 through October 20, 2015. Oral argument on NEE’s petition was held before the NMSC on November 9, 2015. On November 9, 2015, the NMSC denied NEE’s petition.

On November 16, 2015, the Hearing Examiner issued a Certification of Stipulation, essentially adopting the Stipulated Settlement. On December 16, 2015, following oral argument, the NMPRC issued a final order adopting the Certification of Stipulation issued by the Hearing Examiner. The Hearing Examiner’s certification included a non-substantive change to the Stipulated Settlement that required the signatories to the Stipulated Settlement to file their agreement to the change. On December

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22, 2015, PNM filed the Signatories’ Notice of Agreement and Acceptance Regarding Modified Stipulation as Further Modified by Final Order.

At December 31, 2015, PNM’s carrying value for its current ownership share of SJGS Units 2 and 3 included plant in service of $468.2 million, accumulated depreciation and amortization of $193.3 million, and construction work in progress of $2.2 million for a net undepreciated net book value of $277.1 million. PNM estimates the undepreciated net book value of SJGS Units 2 and 3 at December 31, 2017 will be approximately $255.3 million, 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. At December 31, 2015, PNM recorded a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered. The ultimate amount of the disallowance will be equal to the actual December 31, 2017 undepreciated net book values of SJGS Units 2 and 3. Accordingly, the amount initially recorded will be adjusted periodically to reflect changes in the projected December 31, 2017 net book values. A regulatory disallowance of $21.6 million was also recorded at December 31, 2015 for other unrecoverable costs based on the approved Stipulated Settlement. The new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”), described under Coal Supply below, resulted in a $16.5 million increase in the liability recorded for coal mine reclamation. The expense recorded for this increase and the above disallowances, aggregating $165.7 million, is included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss). In addition, the shutdown of SJGS Units 2 and 3 will result in the reversal of certain deferred income tax items. The estimated impact of these tax items resulted in an expense of $1.8 million being recorded at December 31, 2015, which amount in included in income tax expense.

On January 14, 2016, NEE filed, with the NMSC, a Notice of Appeal of the NMPRC’s December 16, 2016 final order. In addition, on February 5, 2016, NEE filed, with the NMPRC, a motion for reconsideration of that final order based on recent developments related to the loan made by NM Capital to facilitate the sale of SJCC, which is described under Coal Supply below. NEE alleges the loan is a transaction that, under the New Mexico Public Utility Act, requires prior NMPRC approval. PNM filed its response to NEE’s motion for reconsideration on February 18, 2016.

SJGS Ownership Restructuring Matters – Currently, 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. In connection with the requirement for SJGS to comply with the CAA, the California participants indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS and expressed the intent to exit their ownership in SJGS no later than July 1, 2022. One other participant also expressed a similar intent to exit ownership in the plant. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and 38.5% of SJGS Unit 4.

The SJGS participants engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. Along with shifts in ownership among participants, the discussions among the SJGS participants regarding restructuring included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

In June 2014, the SJGS participants reached a non-binding agreement that identified 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 agreement provided the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters, 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. Also, in June 2014, a non-binding term sheet was approved by all of the remaining participants that provided the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM stated 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 percentage. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and an aggregate of 58.7% in SJGS Units 1 and 4. These non-binding arrangements recognized that, prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to t

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he economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the June 2014 arrangements, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014. On January 7, 2015, Farmington, which has an ownership interest in SJGS Unit 4, notified the other participants that it would not acquire the additional MWs in Unit 4 contemplated in the June 2014 agreement, leaving 65 MWs in that unit unsubscribed. Farmington’s action resulted in the termination of the Fuel and Capital Funding Agreement.

On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into the Capacity Option and Funding Agreement (“COFA”) that provided PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. The COFA terminated as of the effective date of the SJGS restructuring agreement, which occurred on January 31, 2016 as discussed below.

As indicated under NMPRC Filing above, PNM filed the executed San Juan Project Restructuring Agreement (“RA”) with the NMPRC on July 31, 2015. The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 2014 arrangements. PNMR Development became a party to the RA and will acquire an ownership interest in SJGS Unit 4 when the California owners exit, which is anticipated to be December 31, 2017, but has obligations related to Unit 4 before then. On the exit date, PNM and PNMR Development would acquire 132 MW and 65 MW of the capacity in SJGS Unit 4 from the California owners, as contemplated by the COFA. As discussed under NMPRC Filing above, the Stipulated Settlement would allow PNM to acquire the 65 MW, which the RA contemplates will be acquired by PNMR Development. PNMR currently anticipates that PNMR Development would transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity.

The RA became effective contemporaneously with the effectiveness of the new CSA. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Coal Supply below occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM will acquire the coal inventory of the exiting SJGS participants as of January 1, 2016 and will supply coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers through the FPPAC. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNMR Development’s share of the restructuring fee was recorded at December 31, 2015 and the $3.1 million impact is included in other income on the Consolidated Statements of Earnings.

On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements. FERC approved the application on December 30, 2015.

Other SJGS Matters – 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 BDT equipment, to the SJGS participants in Unit 1 and Unit 4 for approval in 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. PNM subsequently submitted several requests to the owners of Unit 4 requesting approval of certain expenditures critical to comply with the time frame in the RSIP, as well as requests to approve the total forecasted project expenses. The required majority of 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, PNM, as operating agent for SJGS, issued several “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

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Although the RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, 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 Four Corners FIP with a 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 permanently close 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 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 July 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 required the approval of the DOI, as did a related federal rights-of-way grant that culminated in the issuance of a DOI Record of Decision on July 17, 2015. The Record of Decision approves the 25-year site lease extension with the Navajo Nation for Four Corners, authorizes continued mining operations to supply the remaining units at Four Corners, renews transmission line and access road rights-of-way on the Navajo and Hopi Reservations, and accepts the proposed mining plan for the Navajo Mine. The Record of Decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which occurred in July 2015. In addition, installation of SCR control technology at Four Corners required a PSD permit, which APS received in December 2014.

On December 21, 2015, a coalition of environmental groups filed a 60-day notice of intent to sue the OSM, U.S. Fish and Wildlife Service, and other federal agencies alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with the environmental review described above were not in accordance with applicable law. The notice cites violations of the ESA and alleges that certain decisions by the agencies were arbitrary and capricious and not in compliance with the Administrative Procedures Act. The notice states that, if action is not taken within 60 days to remedy the alleged violations, the environmental groups will file a citizens’ suit over the claims. PNM is monitoring this matter but cannot predict the timing or outcome.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of 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 to be up to $94.0 million, including amounts incurred through December 31, 2015 and PNM’s AFUDC, 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.

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Carbon Dioxide Emissions

On August 3, 2015, EPA established final standards to limit CO₂ emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit.

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and requires states to submit initial plans to EPA by September 6, 2016. EPA may grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans must be submitted to EPA by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, the EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation. In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate CO₂ emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA was to determine that it was “not necessary or appropriate”, then the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners. PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation. PNM’s review of the new CO₂ emission reductions standards is ongoing and will depend on the outcome of the judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance.

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 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. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The

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settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule. SJGS and Four Corners SO₂ emissions are below the tonnages set forth in 1) above. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree. The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO₂, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO₂ NAAQS. If NMED chooses the modeling approach that EPA encourages states to adopt, the NMED must submit a modeling protocol for SJGS to EPA by July 1, 2016. NMED must then submit modeling results for SJGS to EPA by January 13, 2017. However, if NMED chooses the monitoring approach, a more relaxed schedule would apply. If SJGS can accept a federally enforceable 2,000 tons per year source-wide limit before January 13, 2017, modeling would not be required by EPA. PNM is currently evaluating the rule to understand its impacts.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO₂emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and 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. The BDT equipment modifications were installed at the same time as the SNCRs, 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 October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. EPA plans to propose rules and guidance over the next year to help states with potential nonattainment areas implement the revised standards. On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control. The proposed rule is timely in light of the new more stringent ozone NAAQS final rule since western states like NM and AZ are particularly subject to elevated background ozone transport from natural local sources such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

As required by the CAA, EPA anticipates making attainment/nonattainment designations for the revised standards by late 2017. Those designations likely will be based on 2014-2016 air quality data. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. NMED would have responsibility for bringing nonattainment counties into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone.

Should San Juan County become non-attainment for ozone, SJGS could be required to install further controls to meet the new ozone NAAQS. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. 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.

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. In May 2011, PNM entered into an

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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 estimated the implementation would increase annual mercury control costs for the entire station from $0.7 million to $6.6 million. Under a stipulated order, PNM was required to repeat a mercury study that would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM 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. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. The NSR permit issued by NMED on May 14, 2015 incorporates this operational parameter as a permit condition.

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 agreed on terms of a settlement. On June 24, 2015, the United States Department of Justice (“DOJ”) lodged the executed consent decree with the United States District Court for the District of New Mexico and published notice of the filing in the Federal Register. On August 17, 2015, the consent decree was entered by the court, marking resolution to the litigation. The settlement resolves claims by the government and environmental plaintiffs that the co-owners violated the CAA by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement requires installation of pollution control technology and implementation of other measures to reduce SO₂ and NOx emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA’s Regional Haze Rule BART requirements. The settlement also requires Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. PNM is responsible for 13% of these costs based on its ownership interest in the units at the time of the alleged violations, which PNM recorded in 2014.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that the owner of the mine does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. The owner of the mine appealed the court’s decision to the Tenth Circuit, where it remains pending. On December 28, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment and finding of no new significant impact, and reissued the permit. This action is subject to possible judicial review and PNM cannot predict the outcome.

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

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for the District of New Mexico. Legal briefing is complete. A stay in this matter has been extended through April 1, 2016 while the parties continue to engage in settlement negotiations. 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 signed its final cooling water intake structures rule on May 16, 2014, 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 (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and 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 schedule of compliance established by the permitting authority.

On August 27, 2015, PNM submitted a request to EPA to terminate the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit. Although SJGS has been a zero discharge facility for several years, EPA had required the plant to maintain a NPDES permit. On September 22, 2015, EPA issued a letter approving the termination request. The cooling water intake structure rule still applies to SJGS as the plant operates under the EPA NPDES Multi-Sector General Stormwater Permit (“MSGP”). On June 4, 2015, the EPA reissued and revised the MSGP. PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS related to cooling water intake structures.

APS is currently in discussions with EPA Region 9, the NPDES 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.

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 offered 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. All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. Requirements governing bottom ash transport water differ depending on which alternative

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EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.

EPA signed the final Steam Electric Effluent Guidelines Rule on September 30, 2015 and released the pre-publication copy. The final rule, which became effective on January 4, 2016, phases in the new, more stringent requirements in the form of effluent limits for arsenic, mercury, selenium, and nitrogen for wastewater discharged from wet scrubber systems and zero discharge of pollutants in ash transport water that must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/revised NPDES permit.

Because SJGS is zero discharge for wastewater and no longer holds an NPDES permit, it is expected that minimal to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment works and holds an NPDES permit. Applicability of the rule will need to be assessed. It is expected that minimum to no requirements will be imposed at Reeves.

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, 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. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations. 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 PNM’s 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.

Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue gasoline remediation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund, which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the Corrective Action Fund is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate or clean up a release.

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. Results of tests conducted by NMED in April 2012 and April 2013 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. 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

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 or landfills. 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. 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.

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 sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria; groundwater monitoring and corrective action; closure requirements and post closure care; and recordkeeping, notification, and internet posting requirements. 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. EPA published the final CCB rule in the Federal Register on April 17, 2015, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect it to have a material impact on operations, financial position, or cash flows.

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 CCB rules. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2016 and will likely be influenced by EPA’s rule. 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. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

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 were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM has control technology on each of the four units at SJGS that provides 99% mercury removal efficiency. The plant is in compliance with the MATS. Therefore, PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.

On June 29, 2015, the United States Supreme Court issued its decision overturning the MATS rule. The justices ruled that EPA should have taken costs to utilities and others in the power sector into consideration before issuing the MATS rule. The case is now remanded to the D.C. Circuit for further proceedings consistent with the opinion. No changes are required at SJGS as a result of the Supreme Court action.

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Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC, which through January 31, 2016 was a wholly owned subsidiary of BHP, under an underground coal sales agreement (“UG-CSA”) to supply processed coal for operation of SJGS through 2017. The parties to the UG-CSA were SJCC, PNM, and Tucson. SJCC holds certain federal, state, and private coal leases. Under the UG-CSA, SJCC was reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and received a return on its investment. BHP Minerals International, Inc. guaranteed the obligations of SJCC under the UG-CSA. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At December 31, 2015 and 2014, prepayments for coal, which are included in other current assets, amounted to $49.0 million and $37.3 million.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. As discussed under SJGS Ownership Restructuring Matters above, the SJGS participants recognized that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017.

Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, agreements were negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new coal supply agreement (“CSA”) and agreements for CCB disposal and mine reclamation services with SJCC on or about January 1, 2016. Effectiveness of the agreements was dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals were necessary for the restructuring of ownership in SJGS to be consummated.

On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new CSA, pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC. In addition, PNM, Tucson, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA. The CSA and related agreements became effective upon the closing of the Stock Purchase Agreement and the effectiveness of the RA. The CSA and related agreements were filed with the NMPRC on July 1, 2015.

The CSA became effective as of 11:59 PM on January 31, 2016, upon the closing under the Stock Purchase Agreement. Upon closing under the Stock Purchase Agreement, Westmoreland’s rights and obligations under the CSA and the agreements for CCB disposal and mine reclamation services were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the CSA.

Pricing under the CSA is primarily fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM has the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. Since substantially all of PNM’s coal costs are passed through the FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners will be passed through to PNM’s customers.

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million to Westmoreland San Juan LLC, a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland (the “Purchaser”), to finance the purchase price of the stock

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of SJCC and San Juan Transportation Company (“SJTC”) under the Stock Purchase Agreement (the “Westmoreland Loan”). NM Capital was able to provide the $125.0 million financing to the Purchaser by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as Administrative Agent. The BTMU Term Loan Agreement is effective as of February 1, 2016, has a maturity date of February 1, 2021, and bears interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, entered into a Guaranty Agreement, dated as of February 1, 2016, with BTMU (the “Guaranty”). The BTMU Term Loan Agreement and the Guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio and customary events of default consistent with PNMR’s other term loan agreements. In addition, the BTMU Term Loan Agreement has a cross default provision and a change of control provision.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, Purchaser, as borrower, SJCC and SJTC, as guarantors, BTMU, as Administrative Agent, and MUFG Union Bank, N.A., as Depository Bank. The Westmoreland Loan is effective as of February 1, 2016, and has a maturity date of February 1, 2021. The Westmoreland Loan initially bears interest at a 7.25% rate plus LIBOR and escalates over time.

The Westmoreland Loan was used by the Purchaser solely to finance the purchase price of the stock of SJCC and SJTC under the Stock Purchase Agreement. The Purchaser must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. In order to assure the reclamation obligations, each of the SJGS owners agreed to fund an irrevocable trust to be maintained for the sole purpose of funding the reclamation of the San Juan mine site (each such trust, a “Reclamation Trust”), as further discussed under Coal Mine Reclamation below.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $161.6 million with the New Mexico Mining and Minerals Division (“NMMMD”). In order to facilitate the posting of reclamation bonds by Zurich American Insurance Company (“Zurich”) on behalf of SJCC, a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) among PNMR, Westmoreland, and SJCC was entered into with Zurich. In connection with the Reclamation Bond Agreement, PNMR used $40.0 million of the available capacity under the PNMR Revolving Credit Facility to support a bank letter of credit arrangement (the “Zurich Letter of Credit”) with Zurich. The Reclamation Bond Agreement provides, among other things, (i) certain obligations for PNMR to provide to Zurich, within 180 days, security interests in the Reclamation Trusts of the Purchaser and the SJGS owners, and (ii) if PNMR is unable to provide security interests in the Reclamation Trusts of certain SJGS owners (the “Base Security Interests”), PNMR, Westmoreland (subject to obtaining certain amendments or consents under its senior debt and credit facilities), and SJCC will be responsible, jointly and severally, to provide additional collateral to support the then outstanding reclamation bond amount, which will remain in place until such time as PNMR is able to provide the Base Security Interests. The Zurich Letter of Credit will be terminated upon PNMR providing security interests in the Reclamation Trusts of all SJGS owners. Also, the Zurich Letter of Credit will be proportionally reduced if PNMR is able to provide, in addition, to the Base Security Interests, security interests in the Reclamation Trusts of some, but not all, of the other SJGS owners or if the initial reclamation bonds amount is reduced. The reclamation bonds may be replaced or otherwise released at any time by SJCC with the concurrence of NMMMD. PNM cannot predict if it will be able to obtain any such security interests or the impacts of not being able to do so.

Four Corners

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 40% in the first year 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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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

Coal Mine Reclamation

In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, an updated coal mine reclamation study was requested by the SJGS participants. In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The 2013 coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, which would reduce the amount of CCBs generated over the remaining life of SJGS and result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. 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.

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. Consistent with the 2013 reclamation study, the 2015 final reclamation cost estimate reflects the proposed shutdown of SJGS Units 2 and 3 and operation of mine through 2053. The 2015 reclamation cost study indicates that the scope and pricing structure of the reclamation service agreement with Westmoreland would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectation, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015 and are included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss). The current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new agreement for coal supply.

Based on the 2015 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $98.2 million for the surface mines at both SJGS and Four Corners and $118.9 million for the underground mine at SJGS as of December 31, 2015. At December 31, 2015 and 2014, liabilities, in current dollars, of $38.8 million and $25.7 million for surface mine reclamation and $11.4 million and $8.6 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 UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable Reclamation Trust, and periodically deposit funding into the Reclamation 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. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. PNM funded $4.3 million in 2015, $1.0 million in 2014, and $0.3 million in 2013. As of December 31, 2015, PNM’s required contributions to its Reclamation Trust fund would be $4.9 million in 2016 and $5.4 million in 2017 based on the existing trust fund balance.

Under the coal supply agreement for Four Corners, which becomes effective on July 7, 2016, PNM is required to fund its ownership share of estimated final reclamation costs in thirteen annual installments, beginning on August 1, 2016, into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM’s anticipated funding level is $1.9 million, $2.0 million, and $2.1 million in 2016, 2017, and 2018.

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 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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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 although the BLM has indicated that final action on the proposed rule is scheduled for April 2016.

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. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC and 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. 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. NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. The parties are engaged in settlement discussions. PNM does not expect the outcome to have a material impact.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity 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 this act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.5 billion per occurrence. Commercial insurance carriers provide $375 million and $13.1 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 $5.8 million, to be adjusted periodically for inflation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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 $5.4 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 certain policy conditions, sublimits, 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. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast long-term weather patterns. Public policy, local, state and federal regulations, and litigation regarding water could also impact PNM operations. To help mitigate these risks, PNM has secured permanent groundwater rights for the existing plants at Reeves Station, Rio Bravo, Afton, Luna, Lordsburg, and La Luz. 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 deliveries) could pose a threat of reduced water availability for these plants.

For SJGS, Four Corners, and related mines PNM and APS have secured supplemental water supplies to accommodate the possibility of inadequate precipitation in coming years. To further mitigate the impacts of severe drought, PNM and APS have entered into agreements with the more senior water rights holders (tribes, municipalities, and agricultural interests) in the San Juan basin to mutually share the impacts of water shortages with tribes and other water users in the San Juan basin. The agreements spread the burden of shortages over all water users in the basin instead of just having the more junior water rights holders (like APS and PNM) bear the entire impact of shortages. The agreements have been extended through 2016.

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 have been set at this time.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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 on 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”). There have been extensive proceedings at FERC on these matters, as well as negotiations among the parties. On August 28, 2015, SPS filed settlement documentation with FERC, including a settlement agreement to which PNM was a party that would resolve all outstanding fuel cost adjustment and rate issues between SPS and PNM. FERC approved the settlement on October 29, 2015. Under the settlement, SPS paid PNM $4.2 million, including interest through December 31, 2014. Of this amount, $2.6 million was passed back to PNM’s customers through its FPPAC.

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 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.

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December 31, 2015, 2014 and 2013

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 allottees’ appeal was dismissed with prejudice. 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 approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On December 2, 2015, the court ruled that PNM could not condemn 2 of the 5 allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM has moved for reconsideration of this ruling.

On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. PNM cannot predict the outcome of these matters.


(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

New Mexico General Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million, effective January 1, 2016. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged the distributed generation charge, as well as other aspects of PNM’s filing. On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. PNM filed exceptions arguing that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for FTY filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the FTY statute. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application and dismissed PNM’s application.

On August 27, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase, including base fuel revenues, of $123.5 million. PNM’s new application is based on a FTY period beginning October 1, 2015, which meets the NMPRC’s May 2015 interpretation of the FTY statute discussed below. The proposed ROE is 10.5%. Similar to the 2014 filing, the primary drivers of PNM’s identified revenue deficiency are infrastructure investments and the recovery of those investment dollars, including depreciation based on an updated depreciation study, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed 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, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. The NMPRC’s designated Hearing Examiner has established a procedural schedule that anticipates a public hearing on the proposed new rates will begin on March 14, 2016. PNM is unable to predict the outcome of this matter.

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December 31, 2015, 2014 and 2013

Proceeding Regarding Definition of Future Test Year

On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagreed with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application.

On June 25, 2015, PNM filed a Notice of Appeal to the NMSC, challenging the NMPRC’s June 3, 2015 written order. On July 31, 2015, PNM and the NMPRC filed a joint motion for a temporary 30-day stay and remand of PNM’s appeal so that the NMPRC could reconsider its FTY order in PNM’s 2014 rate case. The NMSC remanded this matter back to the NMPRC. On November 30, 2015, the NMPRC modified its previous order to provide for a FTY to begin up to 13 months after the filing of a rate case application. On December 9, 2015, the NMPRC filed its revised order with the NMSC. On January 20, 2016, PNM and the NMPRC filed an unopposed stipulation of voluntary dismissal of the appeal and the NMSC dismissed the appeal on February 15, 2016.

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. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 3% distributed generation, and 5% other.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities 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 makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

Included in PNM’s approved procurement plans are the following renewable energy resources:

•

2013 plan – Construction of 20 MW of PNM-owned solar PV facilities, at a cost of $48.9 million; wind and solar REC purchases in 2013; a PPA for the output of the Lightning Dock Geothermal facility; and an additional procurement of 1.5 MW of PNM-owned solar PV facilities 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 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 9 MW of generation capacity.


•	2014 plan – 50,000 MWh of wind generated RECs in 2014; construction of 23 MW of PNM-owned solar PV facilities at a cost of $46.5 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.

•

2015 plan – Construction 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). Under a stipulated settlement, the costs of the 40 MW of solar would be recovered in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the New Mexico General Rate Case discussed above.

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. The NMPRC approved the plan in November 2015, but subsequently vacated the order in response to a rehearing motion regarding the rate treatment of certain non-residential customers eligible for a cap on RPS procurement costs and certain governmental customers exempt from RPS procurement costs. On rehearing, the NMPRC approved the plan in an order issued on February 3, 2016. In this order, the NMPRC deferred the issue related to capped and exempt customers to a new case related to the calculation of PNM’s FPPAC, as discussed in FPPAC Continuation Application below.

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December 31, 2015, 2014 and 2013

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 pending electric 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. PNM made timely filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2014 and 2013. Preliminary calculations indicate PNM’s jurisdictional equity return did not exceed 10.5% in 2015.

PNM recorded revenues from the rider of $41.9 million, $31.9 million, and $21.7 million in 2015, 2014, and 2013. In its 2016 renewable energy procurement plan case, PNM proposed to collect $42.4 million in 2016. The 2016 rider adjustment was approved as part of the final order issued February 3, 2016 on the 2016 renewable energy plan.

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. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider.

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 stipulated settlement on January 30, 2015. After a public hearing, the NMPRC approved the settlement on April 29, 2015. The approval established program budgets and the incentive amounts discussed below.

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. The NMPRC has adopted a rule to implement this act. 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 approved program costs, this amounted to an annual incentive of $1.7 million.

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.

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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

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. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs.

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 April 23, 2014, the NMPRC approved a stipulated agreement resolving this case. The settlement allows PNM to retain 10% of off-system sales margin from July 1, 2013 through December 31, 2016, 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 recover the remaining under-collected balance ($63.5 million as of April 30, 2014) 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 issued a show cause order on February 3, 2016 concerning the rate treatment of large and capped customers in respect to PNM’s RPS procurements to determine whether PNM miscalculated the FPPAC and base fuel costs due to its treatment of renewable energy costs. See the Renewable Portfolio Standard above. PNM cannot predict the outcome of this matter.

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 asked 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 docketed a case to determine whether the IRP complies with applicable NMPRC rules. The order also held 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. The final order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 16 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. Such notice has not yet been issued.

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. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommended rejection of the agreement as proposed, and recommended several modifications to the agreement. On August 13, 2015, PNM and certain parties to the case filed an agreement that, subject to approval by the NMPRC, would modify the stipulation and settle all issues in the case. The NMPRC issued an order approving the modified stipulation on December 16, 2015. On January 14, 2016, NEE filed an appeal of the final order with the NMSC. On February 5, 2016, NEE filed a motion with the NMPRC for reconsideration of the final order based on developments subsequent to the date of the order (Note 16). PNM filed its response to that motion on February 18, 2016. Additional information concerning the NMPRC filing, including a summary of the terms of the modified stipulation, and related proceedings before the NMSC is set forth in Note 16. On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements. FERC issued the requested approvals on December 30, 2015.

Application for Certificate of Convenience and Necessity

On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. PNM estimated the cost of the facility,

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December 31, 2015, 2014 and 2013

which would be located at SJGS, to be $133.2 million. PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party to the SJGS Unit 2 and 3 retirement case filed a motion to consolidate this CCN case with the retirement case, which motion was subsequently withdrawn. PNM is re-evaluating the timing and resource requirements for installation of the natural gas-fired unit requested in the CCN proceeding, including the potential for a smaller unit, along with other possible power resources, taking into consideration PNM’s recently revised lower load forecast and the impacts of the NEC settlement, which is discussed below. On February 12, 2016, PNM filed a motion to withdraw its application and stated that it intends to file either a new application for a gas-fueled resource or a report on the status of the CCN application by April 22, 2016. PNM’s current construction expenditure forecast includes a 85 MW gas-fired unit with an estimated cost of $101.8 million. PNM cannot predict the outcome of this proceeding.

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 notified the NMPRC about receipt of the notice and advised the NMPRC that PNM did not intend to exercise its rights under the ROFR. The ROFR expired unexercised 120 days after the date of EPE’s 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%. FERC accepted PNM’s filing and 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 increased transmission revenues by $2.9 million annually. In addition, the parties agreed that if PNM filed for a formula-based rate change within one year from FERC’s approval of the settlement agreement, no party would 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 have resulted 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. On August 2, 2013, new rates went into effect, subject to refund. In June 2013, May 2014, and March 2015, PNM made additional filings incorporating final 2012, 2013, and 2014 data into the formula rate request. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order

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December 31, 2015, 2014 and 2013

authorizing the interim implementation of settled rates beginning on April 1, 2015, subject to refund. In May 2015, the settlement judge recommended that FERC approve the settlement. There is no required time frame for FERC to act upon the settlement.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended PSA between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue 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 and the amended PSA. In 2015 and 2014, monthly billing demand for power supplied to NEC averaged approximately 54 MW and 55 MW and revenues were $27.1 million and $28.4 million under the PSA.

On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. On May 8, 2015, PNM filed an intervention and protest with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures.

Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC that, subject to FERC approval, would settle this matter. Under the settlement agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements would terminate on December 31, 2016. In 2017, PNM would serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. PNM received approval to bill interim rates, which reflect the settlement, effective November 1, 2015 under the PSA and effective January 1, 2016 under the related contracts. FERC approved the settlement on January 21, 2016.

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, previously 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 September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal, but in March 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 New Mexico General Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million, which PNM recorded in other income during the three months ended June 30, 2015.

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.

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December 31, 2015, 2014 and 2013

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. Subsequently, the Texas District Court dismissed the case on jurisdictional grounds and the complainants appealed to the Texas Third Court of Appeals. The Third Court of Appeals affirmed the dismissal on November 25, 2015. This matter is now concluded.

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 is to be borne by opt-out customers through an initial fee and ongoing monthly charge.

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. On June 20, 2014, the PUCT approved a settlement 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 metering. As of February 19, 2016, 98 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.

On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment is not complete and the total program costs to date are $1.5 million below the original approved forecasts, TNMP is not requesting a change to its monthly surcharge amount. The reconciliation is subject to prudency and reasonableness review by the PUCT. On January 8, 2016, the PUCT staff recommended that the PUCT approve TNMP’s reconciliation without adjustment. The matter is pending before the PUCT. TNMP is unable to predict the outcome of this matter.

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 mandated savings goals). The following sets forth TNMP’s energy efficiency cost recovery factor increases:



Effective Date	Aggregate Collection Amount		Performance Bonus
	(in millions)
January 1, 2013	$	5.2	$	—
March 1, 2014	5.6		0.7
March 1, 2015	5.7		1.5
March 1, 2016	6.0		0.7

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 recent interim transmission cost rate increases:

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December 31, 2015, 2014 and 2013



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
March 16, 2015	27.1		4.4
September 10, 2015	7.0		1.4

On January 29, 2016, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.3 million annually, based on an increase in rate base of $25.8 million. The application is pending before the PUCT.

Periodic Distribution Rate Adjustment

In September 2011, the PUCT approved a rule permitting interim rate adjustments to reflect changes in investments in distribution assets. The rule permits distribution utilities to file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data.

Consolidated Tax Savings Adjustment

On June 14, 2013, the Governor of Texas signed into law a bill eliminating the consolidated tax savings adjustment (“CTSA”) from electric utility ratemaking in Texas. Previously, the CTSA required electric utilities to artificially reduce their respective tax expenses due to the losses incurred by their affiliates. The bill became effective on September 1, 2013.

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December 31, 2015, 2014 and 2013


(18)	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)
	PNM									TNMP			PNMR
	Unrealized Gains on Available-for-Sale Securities			Pension Liability Adjustment			Total			Fair Value Adjustment for Cash Flow Hedges			Fair Value Adjustment for Cash Flow Hedges			Total
	(In thousands)
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	(81,414	)	$	(216	)	$	—		$	(81,630	)
Amounts reclassified from AOCI (pre-tax)	(11,956		)	6,364			(5,592		)	207			—			(5,385		)
Income tax impact of amounts reclassified	4,734			(2,524		)	2,210			(73		)	—			2,137
Other OCI changes (pre-tax)	27,419			17,136			44,555			(279		)	—			44,276
Income tax impact of other OCI changes	(10,855		)	(6,781		)	(17,636		)	98			—			(17,538		)
Net change after income taxes	9,342			14,195			23,537			(47		)	—			23,490
Balance at December 31, 2013	25,748			(83,625		)	(57,877		)	(263		)	—			(58,140		)
Amounts reclassified from AOCI (pre-tax)	(13,862		)	5,152			(8,710		)	558			—			(8,152		)
Income tax impact of amounts reclassified	5,461			(2,032		)	3,429			(195		)	—			3,234
Other OCI changes (pre-tax)	17,473			(15,282		)	2,191			(153		)	—			2,038
Income tax impact of other OCI changes	(6,812		)	6,024			(788		)	53			—			(735		)
Net change after income taxes	2,260			(6,138		)	(3,878		)	263			—			(3,615		)
Balance at December 31, 2014	28,008			(89,763		)	(61,755		)	—			—			(61,755		)
Amounts reclassified from AOCI (pre-tax)	(28,531		)	5,952			(22,579		)	—			—			(22,579		)
Income tax impact of amounts reclassified	11,181			(2,332		)	8,849			—			—			8,849
Other OCI changes (pre-tax)	10,998			(4,405		)	6,593			—			72			6,665
Income tax impact of other OCI changes	(4,310		)	1,726			(2,584		)	—			(28		)	(2,612		)
Net change after income taxes	(10,662		)	941			(9,721		)	—			44			(9,677		)
Balance at December 31, 2015	$	17,346		$	(88,822	)	$	(71,476	)	$	—		$	44		$	(71,432	)

Pre-tax amounts reclassified from AOCI related to Unrealized Gains 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, 2015 and 2014, approximately 22.2% and 24.4% of the amount reclassified were capitalized into construction work in process and approximately 2.4% and 2.0% 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 and capitalized interest. The income tax impacts of all amounts reclassified from AOCI are included in Income Taxes in the Consolidated Statements of Earnings.

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December 31, 2015, 2014 and 2013

(19) 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, 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, 2015, 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, 2015 and 2014 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 25% and 30%. 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 18% and 23% at April 1, 2015 and 2014. The 2015 and 2014 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

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December 31, 2015, 2014 and 2013

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, 2015 and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 2015 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, 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.

(20) Quarterly Operating Results (Unaudited)

Unaudited operating results by quarters for 2015 and 2014 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
2015
Operating revenues	$	332,868	$	352,887	$	417,433	$	335,894
Operating income	49,569		72,414		121,505		(119,138		)	⁽¹⁾
Net earnings	17,852		35,655		64,855		(87,284		)
Net earnings attributable to PNMR	14,340		31,673		61,045		(91,418		)
Net Earnings Attributable to PNMR per Common Share:
Basic	0.18		0.40		0.77		(1.15		)
Diluted	0.18		0.40		0.76		(1.15		)
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
PNM
2015
Operating revenues	$	261,940	$	275,450	$	333,437	$	260,368
Operating income	31,655		47,179		93,710		(139,164		)
Net earnings (loss)	13,502		25,363		53,056		(92,245		)
Net earnings (loss) attributable to PNM	10,122		21,513		49,378		(96,247		)
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
TNMP
2015
Operating revenues	$	70,928	$	77,437	$	83,996	$	75,526
Operating income	17,931		24,729		27,667		19,706
Net earnings	7,694		11,865		13,689		8,715
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

⁽¹⁾Includes an expense of $165.7 million related to the BART determination for SJGS discussed in Note 16.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

PNM Resources, Inc.:

Under date of February 26, 2016, we reported on the consolidated balance sheets of PNM Resources, Inc. and subsidiaries (the Company) as of December 31, 2015 and 2014, 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 three-year period ended December 31, 2015. 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 26, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Public Service Company of New Mexico:

Under date of February 26, 2016, we reported on the consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of earnings (loss), consolidated statements of comprehensive income (loss), consolidated statements of changes in equity, and consolidated statements of cash flows for each of the years in the three-year period ended December 31, 2015. In connection with our audits of the aforementioned consolidated financial statements, we also audited the related consolidated 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 this 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 26, 2016

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder

Texas-New Mexico Power Company:

Under date of February 26, 2016, we reported on the consolidated balance sheets of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2015 and 2014, 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 three-year period ended December 31, 2015. 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 this financial statement schedule based on our audits.

/s/ KPMG LLP

Albuquerque, New Mexico

February 26, 2016

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF EARNINGS



	Year ended December 31,
	2015			2014			2013
	(In thousands)
Operating Revenues	$	—		$	—		$	—
Operating Expenses	1,221			650			941
Operating income (loss)	(1,221		)	(650		)	(941		)
Other Income and Deductions:
Equity in earnings of subsidiaries	27,352			124,543			116,634
Other income	747			622			769
Other deductions	(8,275		)	(13,650		)	(22,825		)
Net other income (deductions)	19,824			111,515			94,578
Earnings Before Income Taxes	18,603			110,865			93,637
Income Tax Expense (Benefit)	2,963			(5,389		)	(6,870		)
Net Earnings	$	15,640		$	116,254		$	100,507

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	15,640		$	116,254		$	100,507
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	509			680			4,192
Deferred income tax expense	(79,526		)	(69,442		)	(51,820		)
Equity in (earnings) of subsidiaries	(27,352		)	(124,543		)	(116,634		)
Loss on reacquired debt	—			—			3,253
Stock based compensation expense	4,863			5,931			5,320
Changes in certain assets and liabilities:
Other current assets	7,664			22,955			28,460
Other assets	69,443			51,644			46,558
Accounts payable	370			(88		)	620
Accrued interest and taxes	4,823			(7,683		)	(9,266		)
Other current liabilities	—			(1,668		)	(146		)
Other liabilities	4,941			28,704			(27,756		)
Net cash flows from operating activities	1,375			22,744			(16,712		)
Cash Flows From Investing Activities:
Utility plant additions	368			(474		)	(960		)
Investments in subsidiaries	(175,000		)	—			(13,800		)
Cash dividends from subsidiaries	127,688			46,599			158,772
Net cash flows from investing activities	(46,944		)	46,125			144,012
Cash Flows From Financing Activities:
Short-term loan	50,000			—			—
Short-term borrowings (repayments), net	41,000			600			(37,600		)
Long-term borrowings	150,000			—			—
Repayment of long-term debt	(118,766		)	—			(29,468		)
Proceeds from stock option exercise	5,619			6,999			4,618
Purchases to satisfy awards of common stock	(17,720		)	(17,319		)	(13,807		)
Dividends paid	(63,723		)	(58,940		)	(50,980		)
Other, net	(782		)	81			—
Net cash flows from financing activities	45,628			(68,579		)	(127,237		)
Change in Cash and Cash Equivalents	59			290			63
Cash and Cash Equivalents at Beginning of Period	382			92			29
Cash and Cash Equivalents at End of Period	$	441		$	382		$	92
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	7,559		$	12,152		$	14,510
Income taxes paid (refunded), net	$	(730	)	$	(2,014	)	$	22,378

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

BALANCE SHEETS



	December 31,
	2015			2014
	(In thousands)
Assets
Cash and cash equivalents	$	441		$	382
Intercompany receivables	102,676			107,619
Income taxes receivable	—			29
Other, net	524			548
Total current assets	103,641			108,578
Property, plant and equipment, net of accumulated depreciation of $11,276 and $10,251	26,707			27,076
Investment in subsidiaries	1,822,593			1,757,650
Other long-term assets	81,168			78,347
Total long-term assets	1,930,468			1,863,073
	$	2,034,109		$	1,971,651
Liabilities and Stockholders’ Equity
Short-term debt	$	191,600		$	100,600
Short-term debt-affiliate	8,819			8,819
Current maturities of long-term debt	—			118,607
Accrued interest and taxes	7,780			2,816
Other current liabilities	18,282			16,320
Total current liabilities	226,481			247,162
Long-term debt	149,860			—
Other long-term liabilities	2,955			2,943
Total liabilities	379,296			250,105
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,166,465			1,173,845
Accumulated other comprehensive income (loss), net of tax	(71,432		)	(61,755		)
Retained earnings	559,780			609,456
Total common stockholders’ equity	1,654,813			1,721,546
	$	2,034,109		$	1,971,651

See Notes 6, 7, 14, and 16 for information regarding commitments, contingencies, and maturities of long-term debt.

See Notes 6 and 11 regarding reclassifications of December 31, 2014 balances related to the adoption of new accounting standards during 2015.

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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:
2013	$	1,751	$	2,849	$	—	$	3,177	$	1,423
2014	$	1,423	$	3,267	$	—	$	3,224	$	1,466
2015	$	1,466	$	3,358	$	—	$	3,427	$	1,397

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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:
2013	$	1,751	$	2,864	$	—	$	3,192	$	1,423
2014	$	1,423	$	3,275	$	—	$	3,232	$	1,466
2015	$	1,466	$	3,344	$	—	$	3,413	$	1,397

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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:
2013	$	—	$	(15	)	$	—	$	(15	)	$	—
2014	$	—	$	(8	)	$	—	$	(8	)	$	—
2015	$	—	$	14		$	—	$	14		$	—

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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, 2015 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, 2015 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, 2015 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, 2015 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Reference is hereby made to “Proposal 1: Elect Nine Directors” in PNMR’s Proxy Statement relating to the annual meeting of stockholders to be held on May 17, 2016 (the “2016 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 2016 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 10, 2015.


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 2016 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 2016 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 2016 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 2016 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2016 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 2015, 2014, and 2013 are omitted for the reason that they are not required or the information is otherwise supplied under Part II, Item 8.

(a) - 3-A.	Exhibits Filed:

Exhibit No		Description

10.1	TNMP	First Amendment to Second Amended and Restated Credit Agreement, dated as of October 30, 2015, among TNMP, the lenders party thereto and Keybank National Association, as administrative agent

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

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

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).

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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

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, supplemental 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

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4.9	Fourth Supplemental Indenture, dated as of May 1, 2003, supplemental 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, supplemental 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, supplemental 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, supplemental 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, supplemental to Indenture dated as of March 11, 1998, 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, supplemental to Indenture dated as of March 11, 1998, 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, supplemental to Indenture dated as of March 11, 1998, between PNM and Union Bank, N.A.(ultimate successor as trustee to The Chase Manhattan Bank), as Trustee	4.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012	1-6986 PNM

4.17	Indenture (for Senior Notes), dated as of August 1, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.1 to PNM’s Registration Statement No. 333-53367	333-53367 PNM

4.18	First Supplemental Indenture, dated August 1, 1998, supplemental to Indenture, dated as of August 1, 1998, between PNM and The Chase Manhattan Bank, as Trustee	4.3 to PNM’s Current Report on Form 8-K Dated August 7, 1998	1-6986 PNM

4.19	Second Supplemental Indenture, dated September 1, 2003, supplemental to Indenture, dated as of August 1, 1998, between PNM and JPMorgan Chase Bank (formerly, The Chase Manhattan Bank), as Trustee	4.7.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003	1-6986 PNM

4.20	Third Supplemental Indenture, dated as of May 13, 2008, supplemental to Indenture dated as of August 1, 1998, 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

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4.22	Fourth Supplemental Indenture, dated as of October 12, 2011, supplemental to 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

4.23	Fifth Supplemental Indenture, dated as of August 11, 2015, supplemental to the Indenture dated as of August 1, 1998, between PNM and MUFG Union Bank, N.A., as Trustee	4.2 to PNM’s Current Report on Form 8-K filed August 11, 2015	1-6986 PNM

TNMP
4.24	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

4.25	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

4.26	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

4.27	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

4.28	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

4.29	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

4.30	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

4.31	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

4.32	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

4.33	Seventh Supplemental Indenture dated as of February 10, 2016 between TNMP and MUFG Union Bank, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed February 10, 2016	2-97230 TNMP

Material Contracts
10.2	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

10.3	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

10.4	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

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10.5	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

10.6	Fourth Amendment to Credit Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent	10.6 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-32462 PNMR

10.7	Third Amended and Restated Term Loan Agreement dated as of December 21, 2015 among PNMR, the lenders identified therein and JPMorgan Chase Bank, N.A., as administrative agent	10.1 to PNMR’s Current Report on Form 8-K filed December 21, 2015	1-32462 PNMR

10.8	Term Loan Agreement, dated as of March 9, 2015, among PNMR, the lenders identified therein and Wells Fargo Bank, National Association, as administrative agent	10.1 to PNMR’s Current Report on Form 8-K filed March 9, 2015	1-32462 PNMR

10.9	First Amendment to Term Loan Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent	10.7 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	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 March 5, 2014 among PNM, the lenders identified therein and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as administrative agent (repaid on August 12, 2015)		10.01 to PNM’s Current Report on Form 8-K filed March 5, 2014		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		First Amendment to Second Amended and Restated Credit Agreement, dated as of October 30, 2015, among TNMP, the lenders party thereto and Keybank National Association, as administrative agent		10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2015	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

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10.19	Bond Purchase Agreement dated December 17, 2015 between TNMP and the purchasers named therein (for $60,000,000 3.53% First Mortgage Bonds, due 2026, Series 2016A)	10.1 to TNMP’s Current Report on Form 8-K filed December 21, 2015		2-97230 TNMP

10.20**	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

10.21**	First Amendment to PNM Resources, Inc. 2014 Performance Equity Plan	99.1 to PNMR’s Current Report on Form 8-K filed December 15, 2015		1-32462 PNMR

10.22**	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

10.23**	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

10.24**	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

10.25**	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

10.26**	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

10.27**	PNM Resources, Inc. 2015 Officer Annual Incentive Plan dated March 20, 2015	10.1 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015		1-32462 PNMR

10.28**	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		1-32462 PNMR

10.29**	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

10.30**	PNM Resources, Inc. 2015 Long-Term Incentive Plan dated March 20, 2015	10.2 to the Company Quarterly Report on Form 10-Q for the quarter ended March 31, 2015		1-32462 PNMR

10.31**	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

10.32**	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

10.33**	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

10.34**	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

10.35**	Special Performance-Based Retention Award Agreement between PNMR and Patricia K. Collawn dated March 29, 2012	10.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012		1-32462 PNMR

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10.36**	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

10.37**	Employee Retention Agreement executed March 4, 2015 between PNMR and Patricia K. Collawn	10.03 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015	1-32462 PNMR

10.38**	Acknowledgement Form for officer restricted stock rights and awards granted under the PNM Resources, Inc. 2014 Performance Equity Plan dated May 15, 2014	10.4 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.39**	2015 Director Compensation Summary (2016 annual retainer is the same as the 2015 annual retainer)	10.1.1 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.40**	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

10.41**	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

10.42**	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

10.43**	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

10.44**	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

10.45**	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

10.46**	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

10.47**	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

10.48**	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

10.49**	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

10.50**	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

10.51**	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

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10.52**	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

10.53**	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

10.54**	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

10.55**	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

10.56**	Third Amendment to the PNMR Officer Life Insurance Plan effective January 1, 2009	10.10 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008	1-32462 PNMR

10.57**	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

10.58**	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

10.59**	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

10.60	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

10.61	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

10.62	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

10.63	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

10.64	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 on Form 10-Q for the quarter ended September 30, 2001	1-6986 PNM

10.65	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

10.66	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

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10.67	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

10.68	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

10.69	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

10.70	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

10.71	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

10.72	Amendment No. 13 to the Arizona Nuclear Power Project Participation Agreement dated April 4, 1990, and effective June 15, 1991	10.8.10 to PNM’s Annual Report on Form 10-K for the fiscal year ended December 31, 1990	1-6986 PNM

10.73	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

10.74	Amendment No. 15 to the Arizona Nuclear Power Project Participation Agreement dated November 29, 2010 and effective January 13, 2011	10.1 to PNM’s Current Report on Form 8-K filed March 1, 2011	1-6986 PNM

10.75	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

10.76	Coal Supply Agreement dated July 1, 2015 between Westmoreland Coal Company and PNM	10.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-6986 PNM

10.77	Underground Coal Sales Agreement Termination and Mutual Release Agreement dated July 1, 2015 among San Juan Coal Company, BHP Billiton New Mexico Coal, Inc., PNM and Tucson Electric Power Company	10.2 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-6986 PNM

10.78	San Juan Project Restructuring Agreement executed as of July 31, 2015 among PNM, Tucson Electric Coal 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, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation	10.3 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-6986 PNM

10.79	Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 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, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation	10.4 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-6986 PNM

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10.80	Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, The Incorporated County of Los Alamos, New Mexico, Utah Associated Municipal Power Systems, and PNMR Development and Management Corporation	10.5 to PNM’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015	1-6986 PNM

10.81	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

10.82	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

10.83	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

10.84	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

10.85*	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

10.86	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

10.87	Facility Lease dated as of December 15, 1986, between The First National Bank of Boston, as Owner Trustee, and PNM (Unit 1 Transaction) together with Amendment No. 1 thereto (refiled)	10.21 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1996	1-6986 PNM

10.88*	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

10.89	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

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10.90	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

10.91	Sale Agreement (PVNGS Unit 2 Lease) dated as of September 18, 2015, between PNM and CGI Capital, Inc.	10.1 to PNM’s Current Report on Form 8-K filed September 22, 2015	1-6986 PNM

10.92	Sale Agreement 136 (PVNGS Unit 2 Lease) dated as of November 20, 2015, between PNM and Cypress Verde LLC	10.1 to PNM’s Current Report on Form 8-K filed November 23, 2015	1-6986 PNM

10.93	Sale Agreement 113 (PVNGS Unit 2 Lease) dated as of November 20, 2015, between PNM and Cypress Second PV Partnership	10.2 to PNM’s Current Report on Form 8-K filed November 23, 2015	1-6986 PNM

10.94	Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station dated March 15, 1996, between PNM 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

10.95	Amendment Number One to the Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station dated January 27, 1997, between PNM 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

10.96	Amendment Number Two to the Master Decommissioning Trust Agreement for Palo Verde Nuclear Generating Station between PNM 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

10.97	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

10.98	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

10.99	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, 2015	1-32462 PNMR

Additional Exhibits
99.1*	Participation Agreement dated as of December 16, 1985, among the Owner Participant named therein, First PV Funding Corporation, The First National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 16, 1985 with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 16, 1985 with the Owner Trustee), and PNM (Unit 1 transaction), including Appendix A definitions, together with Amendment No. 1 dated July 15, 1986 and Amendment No. 2 dated November 18, 1986 (refiled)	99.2 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1995	1-6986 PNM

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99.2	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

99.3	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
99.4	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

99.5	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

99.6	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 26, 2016	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 26, 2016
P. K. Collawn
Chairman, President, and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer	February 26, 2016
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 26, 2016
J. D. Tarry
Vice President, Corporate Controller, and
Chief Information Officer

/s/ A. E. Archuleta	Director	February 26, 2016
A. E. Archuleta

/s/ E. R. Conley	Director	February 26, 2016
E. R. Conley

/s/ A. J. Fohrer	Director	February 26, 2016
A. J. Fohrer

/s/ S. M. Gutierrez	Director	February 26, 2016
S. M. Gutierrez

/s/ M. T. Mullarkey	Director	February 26, 2016
M. T. Mullarkey

/s/ R. R. Nordhaus	Director	February 26, 2016
R. R. Nordhaus

/s/ D. K. Schwanz	Director	February 26, 2016
D. K. Schwanz

/s/ B. W. Wilkinson	Director	February 26, 2016
B. W. Wilkinson

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SIGNATURES



			PUBLIC SERVICE COMPANY OF NEW MEXICO
			(Registrant)

Date:	February 26, 2016	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 26, 2016
P. K. Collawn
President and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 26, 2016
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 26, 2016
J. D. Tarry
Vice President, Corporate Controller, and
Chief Information Officer

/s/ R. N. Darnell	Director	February 26, 2016
R. N. Darnell

/s/ R. E. Talbot	Director	February 26, 2016
R. E. Talbot

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SIGNATURES



			TEXAS-NEW MEXICO POWER COMPANY
			(Registrant)

Date:	February 26, 2016	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 26, 2016
P. K. Collawn
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 26, 2016
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 26, 2016
J. D. Tarry
Vice President and
Controller

/s/ R. N. Darnell	Director	February 26, 2016
R. N. Darnell

/s/ R. E. Talbot	Director	February 26, 2016
R. E. Talbot

/s/ J. N. Walker	Director	February 26, 2016
J. N. Walker

E-3