PNM RESOURCES INC - Annual Report: 2016 (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, 2016



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

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



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

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



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

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



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

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



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

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



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

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

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



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

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

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



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

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

As of February 21, 2017, shares of common stock outstanding were:



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

On June 30, 2016, 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 $35.44 per share reported by The Wall Street Journal, was $2,822,924,435. 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 16, 2017.

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 - 5
CORPORATE AND OTHER			A - 5
SOURCES OF POWER			A - 6
FUEL AND WATER SUPPLY			A - 9
ENVIRONMENTAL MATTERS			A - 10
COMPETITION			A - 10
EMPLOYEES			A - 11
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 - 22
SUPPLEMENTAL ITEM – EXECUTIVE OFFICERS OF PNM RESOURCES, INC.			A - 22
PART II
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER			A - 23
MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA			A - 24
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			A - 27
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 AND FINANCIAL STATEMENT SCHEDULES			D - 1
SIGNATURES			E - 1

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GLOSSARY



Definitions:
ABCWUA		Albuquerque Bernalillo County Water Utility Authority
ABO		Accumulated Benefit Obligation
Afton		Afton Generating Station
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMI		Advanced Metering Infrastructure
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
CIAC		Contributions in Aid of Construction
CO₂		Carbon Dioxide
CSA		Coal Supply Agreement
CTC		Competition Transition Charge
DC 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
EIP		Eastern Interconnection Project
EIS		Environmental Impact Study
EPA		United States Environmental Protection Agency
EPE		El Paso Electric Company
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
Four Corners		Four Corners Power Plant
FPL		FPL Energy New Mexico Wind, LLC
FPPAC		Fuel and Purchased Power Adjustment Clause

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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 2015 Rate Case		Request for a General Increase in Electric Rates Filed by PNM on August 27, 2015
NM 2016 Rate Case		Request for a General Increase in Electric Rates Filed by PNM on December 7, 2016
NM Capital		NM Capital Utility Corporation, an unregulated wholly-owned subsidiary of PNMR
NM Supreme Court		New Mexico Supreme Court
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMMMD		The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department
NMPRC		New Mexico Public Regulation Commission
NOx		Nitrogen Oxides
NOPR		Notice of Proposed Rulemaking
NPDES		National Pollutant Discharge Elimination System
NRC		United States Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NSR		New Source Review
NTEC		Navajo Transitional Energy Company, LLC, an entity owned by the Navajo Nation

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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
PNM		Public Service Company of New Mexico and Subsidiaries
PNM 2014 Term Loan Agreement		PNM’s $175.0 Million Unsecured Term Loan
PNM 2016 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 2016 One-Year Term Loan		PNMR’s $100.0 Million One-Year Unsecured Term Loan
PNMR 2016 Two-Year Term Loan		PNMR’s $100.0 Million Two-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

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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
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 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
US Supreme Court		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
Westmoreland Loan		$125.0 Million of funding provided by NM Capital to WSJ
WSJ		Westmoreland San Juan, LLC, an indirect wholly-owned subsidiary of Westmoreland
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 filed a general rate case in December 2016 that is 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 will not receive information that was not requested and can unsubscribe at any time.

Our corporate Internet addresses are:


•	PNMR: www.pnmresources.com


•	PNM: www.pnm.com


•	TNMP: www.tnmp.com

The PNMR website includes a link to PNMR’s Sustainability Portal, www.pnmresources.com/about-us/sustainability-portal.aspx. This portal provides access to key sustainability information related to the operations of PNM and TNMP and reflects PNMR’s commitment to do business in an ethical, open, and transparent manner.

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. Service to retail electric customers is subject to the jurisdiction of the NMPRC. PNM has decided to stop pursuing wholesale generation contracts although some sales continue to be made to wholesale customers. 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. See Note 17 for additional information on rate cases and other regulatory 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 2.5% of its revenues for the year ended December 31, 2016. 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. On October 1, 2016, PNM implemented a NMPRC order in PNM’s NM 2015 Rate Case that approved an increase in non-fuel base rates of $61.2 million annually. PNM is appealing certain aspects of the NMPRC’s order in the NM Supreme Court. Other parties in that rate case have filed cross-appeals contesting other aspects of the NMPRC ruling. See Note 17.

In December 2016, PNM filed a new general rate case (the “NM 2016 Rate Case”) with the NMPRC. The December 2016 application proposes a revenue increase of $99.2 million above the October 1, 2016 rates to be effective on January 1, 2018. The requested increase is based on a calendar 2018 future test year (“FTY”) and a ROE of 10.125% compared to a ROE of 9.575% authorized in the NM 2015 Rate Case. The primary drivers of PNM’s identified revenue deficiency are the implementation of the plan for SJGS to comply with the CAA (Note 16), including the shutdown of Units 2 and 3 of SJGS, recovery of 50% of the net book value of those units, and the inclusion in retail rates of PVNGS Unit 3 as replacement power. The increase also reflects new infrastructure investments and declines in forecasted energy sales resulting from PNM’s successful energy efficiency programs and other economic factors. PNM also proposes changes to rate design to better align electric rates with the actual costs to serve customers and encourage continued energy efficiency while proposing a rate mechanism that eliminates the disincentives associated with energy efficiency and load management programs.

PNM has a NMPRC-approved rate rider to collect costs for renewable energy procurements that are not otherwise being collected in rates. If PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operation, exceeds the NMPRC-approved rate by 0.5%, the rider provides that PNM would refund the excess to customers during the following year. PNM’s earned return on jurisdictional equity did not exceed the limitation in 2014, 2015, or 2016. The NMPRC has also approved riders designed to allow PNM to bill and collect substantially all of fuel and purchased power costs and costs of approved energy efficiency initiatives.

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FERC Regulated Wholesale Operations

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 PNM’s previous transmission rate case. 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 interim implementation of settled rates beginning on April 1, 2015, subject to refund. On March 17, 2016, FERC approved the settlement.

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 59 MW and 62 MW in 2016 and 2015. No firm-requirements customer of PNM accounted for more than 2.0% of PNM’s revenues for the year ended December 31, 2016.

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. Currently, PNM does not plan to pursue obtaining authority for market-based rates within the PNM balancing authority area.

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. FERC approved the settlement on January 21, 2016. Under the agreement, PNM served all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. The PSA terminated on December 31, 2016. In 2017, PNM will 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 available under short-term market rates at the time of the settlement. In 2016, 2015, and 2014, monthly billing demand for power supplied to NEC averaged approximately 54 MW, 54 MW, and 55 MW and revenues were $20.0 million, $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 provided electricity at wholesale to the City of Aztec, New Mexico under a contract that expired on June 30, 2016. In 2014, PNM entered into a contract with the Jicarilla Apache Nation to provide electricity at wholesale through May 8, 2019, although the customer had the option to terminate the contract upon appropriate notice. In accordance with the contract, the Jicarilla Apache Nation terminated the contract effective December 1, 2016.

PNM’s recently filed general rate cases discussed above include a reallocation of assets and costs among regulatory jurisdictions, primarily to retail customers, reflecting the termination of these contracts. See Results of Operations in MD&A and Note 17.

Operational Information

Weather-normalized retail electric KWh sales decreased by 0.7% in 2016 and 1.4% in 2015. The system peak demands for retail and firm-requirements customers were as follows:

System Peak Demands



	2016	2015	2014
	(Megawatts)
Summer	1,908	1,889	1,878
Winter	1,376	1,433	1,471

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PNM holds long-term, non-exclusive franchise agreements for its electric retail operations, with varying expiration dates. These franchise agreements allow the utility to access public rights-of-way for placement of its electric facilities. Franchise agreements have expired in some areas PNM serves, including Albuquerque, Rio Rancho, and Santa Fe. Because PNM remains obligated under New Mexico state law to provide service to customers in these areas, the expirations should not have a material adverse impact. The Albuquerque, Rio Rancho, and Santa Fe metropolitan areas accounted for 48.1%, 9.9%, and 9.5% of PNM’s 2016 revenues and no other franchise area represents more than 5%. Although PNM is not required to collect or pay franchise fees in some areas it serves, the utility continues to collect and pay such fees in certain parts of its service territory, including Albuquerque, Rio Rancho, and Santa Fe.

As discussed in Note 16, the County Commission of Bernalillo County, New Mexico passed an ordinance on January 28, 2014 that would require PNM and other utilities to enter into a use agreement and pay a yet-to-be-determined fee as a condition for installing, maintaining, and operating facilities on county rights-of-way. PNM and other utilities have filed complaints in federal and state courts challenging the validity of the ordinance. If the challenge to the ordinance is unsuccessful, PNM believes 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 3,200 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 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, which PNM reflected in PNM’s NM 2016 Rate Case filed in December 2016. See Note 16 and Note 17. 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 were credited to retail customers through December 31, 2016, after which date 100% of the margins are credited to customers.

Use of Future Test Year (“FTY”)

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 pending request for a general rate increase is based on a FTY period beginning January 1, 2018. As with any forward looking financial information, utilizing a FTY in a rate filing presents challenges. 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

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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 and incorporated in the State of Texas. TNMP’s predecessor was organized in 1925. 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 3.0% in 2016 and 2.6% in 2015. As of December 31, 2016, 102 active REPs receive transmission and distribution services from TNMP. In 2016, the three largest REP customers of TNMP accounted for operating revenues of 16%, 11%, 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 advanced meters began in September 2011. TNMP completed its mass deployment of AMS in 2016 and has installed more than 242,000 advanced meters.

The PUCT approved interim adjustments to TNMP’s transmission rates of $2.9 million in March 2014, $4.2 million in September 2014, $4.4 million in March 2015, $1.4 million in September 2015, $4.3 million in March 2016, and $1.8 million in September 2016. On January 20, 2017, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.8 million annually. The application is pending before the PUCT. See Note 17.

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. The activities of PNMR Development and NM Capital are also included in Corporate and Other.

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SOURCES OF POWER

PNM

Generation Capacity

As of December 31, 2016, the total net generation capacity of facilities owned or leased by PNM was 2,481 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 Lightning Dock Geothermal facility, which currently has a capacity of 4 MW, and Red Mesa Wind, which has a capacity of 102 MW.

PNM’s capacity in electric generating facilities, which are owned, leased, or under PPAs, in commercial service as of December 31, 2016 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	189
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
			2,791

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. 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, an APS affiliate, SRP, and Tucson and are operated by APS. PNM had no ownership interest in Four Corners Units 1, 2, or 3, which were shut down 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. An affiliate of APS acquired the 7% interest formerly owned by EPE on July 7, 2016. NTEC, an entity owned by the Navajo Nation, has the option to purchase the 7% interest. NTEC provided notice of its intent to exercise the option, but has not yet acquired the 7% interest. See Note 16 for additional information about Four Corners.

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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.

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 information 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 and Note 17 for information about the ratemaking treatment by the NMPRC. 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 and Note 17 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

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. PNM completed the installation of additional PNM-owned solar PV facilities of 21.5 MW at four sites, including expansion of capacity at two of the existing sites, in 2013; 23 MW at three additional sites in 2014; and 40 MW at four additional sites in 2015. As discussed in Note 17, PNMR Development will construct, beginning in 2017, and own 30 MW of new solar capacity that PNM will use to supply power to a new data center being constructed by Facebook Inc. in PNM’s service territory. The NMPRC has approved a voluntary tariff that allows PNM retail customers to buy renewable electricity for a small monthly premium. Power from 1.5 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	2016	2015	2014
SJGS	PNM	76.5%	67.4%	76.5%
Four Corners	APS	62.0%	77.8%	68.1%
PVNGS	APS	91.4%	94.2%	91.8%

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 privately, 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 2022 for SJGS, July 2041 for Four Corners, December 2046 for Luna, and November 2047 for PVNGS. Also, 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 Units 2 and 3 of the four SJGS units will be permanently shut down. See Note 16 for a discussion of the restructuring of SJGS ownership. In December 2013, a new coal supply arrangement for Four Corners that runs through July 6, 2031 was executed. 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.

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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 projects. It is unclear how these factors will enter into discussion and negotiations concerning the status of the joint projects as the expiration of basic operational agreements approaches. PNM can provide no assurance that its participation in the joint projects will continue in the manner that currently exists.

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, New Mexico. 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.

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.

On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expires on May 31, 2017, under which each party will sell the other party 100 MW of capacity and energy on a unit contingent basis. Both the purchases and sales are made at the same market index price. In 2016, PNM sold 482,342 MWh for $12.8 million and purchased 484,632 MWh for $12.9 million under the agreement. The agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM and Tri-State have entered into an additional agreement, under substantially identical terms, for a term of five years beginning June 1, 2017, subject to NMPRC approval. PNM filed an application with the NMPRC for approval of the five-year agreement and a public hearing is scheduled to begin on March 23, 2017. See Note 17.

A summary of purchased power, excluding Rio Bravo and Valencia, is as follows:



	Year Ended December 31,
	2016		2015		2014
Purchased under long-term PPAs
MWh	1,211,852		599,562		492,906
Cost per MWh	$	28.26	$	22.18	$	27.82
Other purchased power
Total MWh	502,893		729,895		1,023,744
Cost per MWh	$	27.78	$	28.94	$	40.30

TNMP

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

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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
2016	54.1	%	$	2.34	31.6	%	$	0.71	11.8	%	$	2.80
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

In 2016, 2015, and 2014, 2.5%, 1.5%, and 1.0% of PNM’s generation was from utility owned solar, which has no fuel cost. The generation mix for 2017 is expected to be 54.8% coal, 28.2% nuclear, 14.8% gas and oil, and 2.2% utility owned solar. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits, and the generally adequate supply of nuclear fuel, PNM believes that adequate sources of fuel are available for its generating stations into the foreseeable future. See Sources of Power – PNM – PPAs for information concerning the cost of purchased power. PNM recovers substantially all of it fuel and purchased power costs through the FPPAC.

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 are being 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 2018 and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM must file its position and supporting testimony in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in its 2017 IRP to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shut down.

In late December 2013, a new fifteen-year coal supply contract for Four Corners, beginning in July 2016, was executed. The average coal price per MMBTU under the new contract was approximately 48% higher in the second half of 2016 than in the second half of 2015. 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 100% of PVNGS’s requirements for uranium concentrates and conversion services through 2018 and 45% of those requirements for 2019-2025. In addition, the participants have contracted for 100% of PVNGS’s enrichment services through 2020 and 20% for 2021-2026. All of PVNGS’s fuel assembly fabrication services are contracted through 2024.

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

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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 DC Circuit ordered the NRC to resume its review of the application with available appropriated funds.

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

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

Water Supply

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

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 Four Corners discussed in Note 16, which aggregate $35.1 million in 2017 and $9.0 million in 2018. 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”


•	Navajo 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,

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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 although PNM has decided to stop pursuing wholesale generation contracts. PNM 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, 2016:



	PNMR	PNM	TNMP
Corporate ⁽¹⁾	427	—	—
PNM	1,027	1,027	—
TNMP	360	—	360
Total	1,814	1,027	360

(1)Represents employees of PNMR Services Company.

As of December 31, 2016, PNM had 530 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 through April 30, 2020. As of December 31, 2016, TNMP had 191 employees represented by IBEW Local 66 covered by a collective bargaining agreement that is in effect through August 31, 2019. The wages and benefits for PNM and TNMP employees who are members of the IBEW are typically included in the rates charged to electric customers and consumers, subject to approval of the NMPRC and PUCT.

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 impacts of the NMPRC order in PNM’s NM 2015 Rate Case, appeals of that order, and PNM’s NM 2016 Rate Case and the impact on service levels for PNM customers if the ultimate outcomes do not provide for the recovery of costs of operating and capital expenditures, as well as other impacts of federal or state regulatory and judicial actions


•	The ability of the Company to successfully forecast and manage its operating and capital expenditures, including aligning expenditures with the revenue levels resulting from the ultimate outcomes in PNM’s NM 2015 Rate Case, including appeals, and NM 2016 Rate Case and supporting forecasts utilized in future test year rate proceedings


•	The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, energy efficiency measures, weather, seasonality, alternative sources of power, and other changes in supply and demand, including the failure to maintain or replace customer contracts on favorable terms


•	The Company’s ability to access the financial markets, including disruptions in the capital or credit markets, actions by ratings agencies, and fluctuations in interest rates, including any negative impacts that could result from the ultimate outcome in PNM’s NM 2015 Rate Case, including appeals, and PNM’s NM 2016 Rate Case


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


•	Uncertainty surrounding counterparty credit risk, including financial support provided to facilitate the new coal supply and ownership restructuring at SJGS

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•	Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects, including the scheduled expiration of the operational and fuel supply agreements for SJGS, as well as the 2018 required NMPRC filing to determine the extent to which SJGS should continue serving PNM’s retail customers beyond mid-2022


•	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


•	Risks related to climate change, including potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG, including the Clean Power Plan


•	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, including the potential impacts of the order in the NM 2015 Rate Case, appeals of that order, and the ultimate outcome of PNM’s NM 2016 Rate Case


•	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


•	State and federal regulatory, legislative, executive, and judicial decisions and actions on ratemaking, tax, including the potential for tax reform, and other matters


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


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


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


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


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


•	The risk that FERC rulemakings or lack of additional capacity during peak hours may negatively impact the operation of PNM’s transmission system


•	The impacts of decreases in the values of marketable securities maintained in trusts to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits, including potential increased volatility resulting from international developments


•	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, many of which are beyond their control, including those set forth below and in MD&A, Note 16, and Note 17. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement contained in this report, see Disclosure Regarding Forward Looking Statements in Item 1. Business. 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 initiatives 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 2017-2021 to be $2,083.1 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


•	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 self-generation energy resources and energy efficiency technology


•	Reduced new sources of demand


•	Unpredictable weather patterns

In 2016 and 2015, PNM experienced decreases in weather-normalized retail sales of 0.7% and 1.4%. The sales decreases reflect a continued sluggish economy in New Mexico. The Albuquerque metropolitan area is beginning to show results from economic development efforts and employment in Albuquerque grew 1.0% in 2016. The economy in New Mexico continues to have mixed indicators and 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.

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 (“FTY”) in establishing rates. As with any forward looking financial information, a FTY 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 FTY 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. In August 2015, PNM filed a new application (the “NM 2015 Rate Case”) with the NMPRC for a general rate increase, including base non-fuel revenues of $121.5 million. The primary drivers of PNM’s identified revenue deficiency were 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 NMPRC issued an order authorizing an increase in non-fuel revenues of $61.2 million effective beginning in October 2016. The NMPRC disallowed recovery of PNM’s capital investment in BDT equipment installed on SJGS Units 1 and 4, which is required by the NSR permit for SJGS (Note 16), and a portion of the acquisition costs for PNM’s January 15, 2016 purchase of 64.1 MW of PVNGS Unit 2, which were previously leased to PNM, as well as the undepreciated costs of capitalized improvements made during the period that capacity was leased. PNM filed an appeal of the disallowances with the NM Supreme Court. Other parties to that rate case have filed cross-appeals in order to appeal other decisions of the NMPRC regarding issues in the rate case.

In December 2016, PNM filed a request (the “NM 2016 Rate Case”) for a general increase in rates of $99.2 million. The primary drivers of PNM’s identified revenue deficiency are implementation of the plan for SJGS to comply with the CAA, including the shutdown of Units 2 and 3 of SJGS, recovery of 50% of the net book value of those units, and the inclusion in retail rates of

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PVNGS Unit 3 as replacement power (Note 16). The increase also reflects new infrastructure investments and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. PNM also proposes changes in rate design to better align electric rates with the actual costs to serve customers and encourage continued energy efficiency while proposing a rate mechanism that eliminates the disincentives associated with energy efficiency and load management programs.

An adverse outcome in the NM 2015 Rate Case, including the pending appeals before the NM Supreme Court, or the NM 2016 Rate Case, could negatively impact PNM’s financial position, 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. The average coal price per MMBTU under the new contract was approximately 48% higher in the second half of 2016 than in the second half of 2015. 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 NM Supreme Court. 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. PNMR has counterparty credit risk in connection with financial support provided to facilitate the new coal supply arrangement for SJGS. Adverse developments from these factors could have a negative impact on the business, financial condition, results of operations, and cash flows of PNM and PNMR.

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 shutdown of SJGS Units 2 and 3 by December 31, 2017. NEE, an intervenor in the NMPRC proceeding regarding the approval of the plan, has appealed the BART Approval to the NM Supreme Court. NEE has also filed a complaint with the NMPRC against PNM regarding the financing provided 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. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC to investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. The NMPRC has taken no action on this matter. 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, expires on July 1, 2022 and the new CSA for coal supply at SJGS described in Note 16 expires 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 to the miner 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. As discussed in Note 17, PNM is required to file its 2017 IRP by July 3, 2017. The 2017 IRP will address a 20-year planning period, from 2017 through 2036, and will include an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. To facilitate the 2018 filing discussed above, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down.

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 has an arrangement with a bank under which the bank has issued $30.3 million of letters of credit in favor of sureties in order for the sureties to post reclamation bonds that are required under the mine’s operating permit. See Note 6 and 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 into PNM’s service territory, or whether the cost of

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obtaining those resources would be reasonable. Furthermore, there can be no assurance that the NMPRC would approve PNM’s recovery of its undepreciated investment in SJGS through rates charged to customers. 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 business 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, which may impose significant compliance costs and 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 in Item 7.

EPA, other federal and state agencies, environmental advocacy groups, and other organizations have been 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 under Climate Change Issues, this type of 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 such non-compliance is 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. The Company is unable to estimate these costs due to the many uncertainties associated with, among other things, the nature and extent of future regulations, and changes in existing regulations, including the potential for changes in regulatory policy generally as a result of the 2017 changes in the United States federal administration. 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

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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. The significant level of regulation imposes restrictions on the operations of the Company and causes the incurrence of substantial compliance costs. 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. Failure to comply with any applicable rules, regulations or decisions may lead to customer refunds, fines, penalties, and other payments, which could materially and adversely affect the results of operations and financial condition of PNMR and its subsidiaries.

Operational Factors

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

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


•	Rates charged by PNM and TNMP


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


•	Energy efficiency initiatives


•	Availability and cost of alternative sources of power


•	National, regional, or local economic conditions

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

PNM’s and TNMP’s service territories include several military bases and federally funded national laboratories, as well as large industrial customers that have significant direct and indirect impacts on the local economies where they operate. The Company does not directly provide service to any of the military bases or national laboratories, but does provide service to large industrial customers. The Company’s business could be hurt from the impacts on the local economies associated with these customer groups, as well as directly from the large industrial customers, for a number of reasons, including:


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


•	Closure of industrial facilities or significant curtailment of their activities

Another factor that could negatively impact the Company is that proposals are periodically advanced in various localities to municipalize, or otherwise take over PNM’s facilities, which PNM believes would require state legislative action to implement, or to establish new municipal utilities in areas currently served by PNM. 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.

Advances in technology could make our electric generating facilities less competitive.

Research and development activities are ongoing for new technologies that produce power or reduce power consumption. These technologies include renewable energy, customer-oriented generation, energy storage, and energy efficiency. The Company generates power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become increasingly cost competitive. It is possible that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, the Company’s energy sales could be eroded, and the value of the Company’s generating facilities could be reduced. Advances in technology could also change the channels through which electric customers purchase or use power, which could reduce sales and revenues or increase expenses.

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

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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 reclamation of the mines that supply coal to the coal-fired power plants. Likewise, other owners or participants are responsible for their shares of the decommissioning and reclamation 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, reclamation, and restoration. The NMPRC has established a cap on the amount of 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. In addition, the NMPRC’s order in the NM 2015 Rate Case (Note 17) disallows recovery of future contributions for the decommissioning of certain portions of PVNGS. PNM has appealed the decision of the NMPRC and the appeal is pending before the NM Supreme Court. An adverse outcome of the appeal could negatively impact PNM’s future results of operations, cash flows, and liquidity.

PNM maintains trust funds designed to provide adequate financial resources for decommissioning PVNGS and for reclamation of the coal mines serving SJGS and Four Corners at the end of their expected lives. However, if the PVNGS units are decommissioned before their planned date or the coal mines are shut down sooner than expected, these funds may prove to be insufficient.

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, cybersecurity attacks, disruptions in the supply, quality, and delivery of fuel and water supplies, and other factors could result in PNM’s load requirements being larger than available system generation capacity. Assured supplies of water are important for PNM’s generating plants. Water in the southwestern United States is limited and there are conflicting claims regarding water rights. In addition, the “four corners” region where two of PNM’s power plants are located is prone to drought conditions, which could potentially affect the plants’ water supplies. 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 cybersecurity attacks, both threatened and actual, against generation facilities, transmission and distribution infrastructure used to transport power, 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. Despite steps the Company may take to detect, mitigate and/or eliminate cybersecurity threats and respond to data security incidents, the techniques used by those who wish to obtain unauthorized access, and possibly disable or sabotage systems and/or abscond with confidential information and data, change frequently and the Company may not be able to protect against such actions.

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 cybersecurity attack. Although the Company has implemented security measures, critical infrastructure, including information and operational technology systems, are vulnerable to disability, failures,

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or unauthorized access, which could occur as a result of hacking, employee error, and/or employee misconduct. A successful physical or cybersecurity 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. Moreover, a breach of the Company’s information technology systems could also lead to the loss and destruction of confidential and proprietary data, customer and employee data (which may include personally identifiable information such as names, addresses, phone numbers, email addresses and payment account information), trade secrets, intellectual property and supplier data, and could disrupt business operations which could harm the Company’s reputation and financial results, as well as potential increased regulatory oversight, litigation, fines, and other remedial action. The costs incurred to investigate and remediate a physical or cybersecurity attack could be significant. A physical or cybersecurity 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 (see above)


•	Securing the facilities against possible terrorist attacks


•	Unscheduled outages due to equipment failures

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. 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.

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.

PNM 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.

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

PNM is obligated to supply power to retail customers and certain wholesale customers. At peak times, power demand could exceed PNM’s available generation capacity. Market forces, competitive forces, or adverse regulatory actions may require PNM to purchase capacity on the open market or build additional generation capabilities. Regulators or market conditions may not permit PNM to pass all of these purchases or construction costs on to customers. If that occurs, PNM may not be able to fully recover these costs. Or, there may be a lag between when costs are incurred and when regulators permit recovery in customers’ rates. These situations could have negative impacts on results of operations and cash flows.

General Economic and Weather Factors

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

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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 SJGS and Four Corners participate in 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


•	Decisions of the NMPRC and PUCT in various regulatory cases currently pending or that may be docketed in the future


•	Conditions imposed by the NMPRC or PUCT


•	The effect of federal regulatory decisions and legislative acts


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


•	Future growth plans and the related capital requirements


•	Other business considerations

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

PNMR and its subsidiaries rely on access to both short-term and longer-term capital markets as sources of liquidity for any capital requirements, 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 2017-2021 to be $2,083.1 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 and mine reclamation trusts 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 and mine reclamation trusts are typically invested in marketable equity securities. Declines in market values could result in increased funding of the trusts, the recognition of losses as impairments for the NDT and mine reclamation trusts, 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.

The Company annually evaluates recorded goodwill for impairment. See Note 18 and Critical Accounting Policies and Estimates section of MD&A in Item 7. Long-lived assets are also assessed whenever indicators of impairment exist. Factors that affect the long-term value of these assets, as well as other economic and market conditions could result in impairments. Significant impairments could adversely affect the Company’s business, financial position, liquidity, and results of operations.

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

The “Events of Loss” generally relate to casualties, accidents, and other events at PVNGS, including the occurrence of specified nuclear events, which would severely adversely affect the ability of the operating agent, APS, to operate, and the ability of PNM to earn a return on its interests in PVNGS. The “Deemed Loss Events” consist primarily of legal and regulatory changes (such as issuance by the NRC of specified violation orders, changes in law making the sale and leaseback transactions illegal, or

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changes in law making the lessors liable for nuclear decommissioning obligations). PNM believes that the probability of such “Events of Loss” or “Deemed Loss Events” occurring is remote for the following reasons: (1) to a large extent, prevention of “Events of Loss” and some “Deemed Loss Events” is within the control of the PVNGS participants through the general PVNGS operational and safety oversight process; and (2) other “Deemed Loss Events” would involve a significant change in current law and policy. PNM is unaware of any proposals pending or being considered for introduction in Congress, or in any state legislative or regulatory body that, if adopted, would cause any of those events. See Note 7.

Governance Factors

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

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


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


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


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

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

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, 2016, PNM owned, or jointly owned, 3,200 circuit miles of electric transmission lines (including the EIP), 6,060 miles of distribution overhead lines, 5,789 cable miles of underground distribution lines (excluding street lighting), and 269 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 on April 1, 2015 at fair market value. See Note 9 for additional information about 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, 2016, TNMP owned 978 circuit miles of overhead electric transmission lines, 7,111 pole miles of overhead distribution lines, 1,209 circuit miles of underground distribution lines, and 115 substations. Substantially all of TNMP’s property is pledged to secure its first mortgage bonds. See Note 6.

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ITEM 3.	LEGAL PROCEEDINGS

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

Note 16


•	The Clean Air Act – Regional Haze – SJGS


•	The Clean Air Act – Regional Haze – Four Corners – Four Corners Federal Agency Lawsuit


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


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


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Santa Fe Generating Station


•	Continuous Highwall Mining Royalty Rate


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication


•	Rights-of-Way Matter


•	Navajo Nations Allottee Matters

Note 17


•	PNM – New Mexico General Rate Cases


•	PNM – Renewable Portfolio Standard


•	PNM – Renewable Energy Rider


•	PNM – Energy Efficiency and Load Management


•	PNM – Integrated Resource Plan


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


•	PNM – Application for Certificate of Convenience and Necessity


•	PNM – Advanced Metering Infrastructure Application


•	PNM – Formula Transmission Rate Case


•	TNMP – Energy Efficiency


•	TNMP – Transmission Cost of Service Rates


ITEM 4.	MINE SAFETY DISCLOSURES

Not Applicable.

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 24, 2017 and offices held with PNMR for the past five years are as follows:



Name	Age	Office	Initial Effective Date
P. K. Collawn	58	Chairman, President, and Chief Executive Officer	January 2012
C. N. Eldred	63	Executive Vice President and Chief Financial Officer	July 2007
P. V. Apodaca	65	Senior Vice President, General Counsel, and Secretary	January 2010
R. E. Talbot ⁽¹⁾	56	Senior Vice President and Chief Operating Officer	January 2012
R. N. Darnell	59	Senior Vice President, Public Policy	January 2012
J. D. Tarry	46	Vice President, Finance and Controller	February 2017
		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
C. M. Olson	59	Vice President, Utility Operations	December 2016
		Vice President, Generation – PNM	November 2012
		Vice President, Power and Energy – Corval Group	June 2008

⁽¹⁾On January 3, 2017, R. E. Talbot resigned as Senior Vice President and Chief Operating Officer of the Company. Mr. Talbot’s duties were reassigned.

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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 2016 and 2015, by quarters, are as follows:



Quarter Ended	Range of Sales Prices				Dividends Declared Per Share
	High		Low		Dividends Declared Per Share
2016
March 31	$	34.07	$	29.22	$	0.2200
June 30	35.46		30.62		0.2200
September 30	36.15		31.20		0.2200
December 31	34.53		30.95		0.2425
Fiscal Year	36.15		29.22		0.9025
2015
March 31	$	31.18	$	27.06	$	0.2000
June 30	29.78		24.49		0.2000
September 30	28.17		24.42		0.2000
December 31	31.23		26.56		0.2200
Fiscal Year	31.23		24.42		0.8200

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 $0.20 per share in July 2015 and $0.22 per share in July 2016, 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 $0.20 per share in September 2015 and $0.22 per share in September 2016, which are reflected as being in the third quarter above. On February 24, 2017, the Board declared a quarterly dividend of $0.2425 per share. PNMR targets a long-term dividend payout ratio of 50% to 60% of ongoing earnings, which is a non-GAAP financial measure that excludes from earnings determined in accordance with GAAP certain non-recurring, infrequent, and other items that are not indicative of fundamental changes in the earnings capacity of the Company’s operations. PNMR uses ongoing earnings to evaluate the operations of the Company and to establish goals, including those used for certain aspects of incentive compensation, for management and employees.

On February 21, 2017, there were 11,712 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 2016 and 2015. 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.



PNM RESOURCES, INC. AND SUBSIDIARIES
	2016			2015			2014			2013			2012
	(In thousands except per share amounts and ratios)
Total Operating Revenues	$	1,362,951		$	1,439,082		$	1,435,853		$	1,387,923		$	1,342,403
Net Earnings	$	131,896		$	31,078		$	130,909		$	115,556		$	120,125
Net Earnings Attributable to PNMR	$	116,849		$	15,640		$	116,254		$	100,507		$	105,547
Net Earnings Attributable to PNMR per Common Share
Basic	$	1.47		$	0.20		$	1.46		$	1.26		$	1.32
Diluted	$	1.46		$	0.20		$	1.45		$	1.25		$	1.31
Cash Flow Data
Net cash flows from operating activities	$	415,454		$	386,874		$	414,876		$	386,587		$	281,349
Net cash flows from investing activities	$	(699,375	)	$	(544,528	)	$	(485,329	)	$	(331,446	)	$	(285,895	)
Net cash flows from financing activities	$	242,392		$	175,431		$	96,194		$	(61,593	)	$	(1,560	)
Total Assets	$	6,471,080		$	6,009,328		$	5,790,237		$	5,426,858		$	5,356,411
Long-Term Debt, including current installments	$	2,392,712		$	2,091,948		$	1,962,385		$	1,730,749		$	1,656,118
Common Stock Data
Market price per common share at year end	$	34.30		$	30.57		$	29.63		$	24.12		$	20.51
Book value per common share at year end	$	21.04		$	20.78		$	21.61		$	21.01		$	20.19
Tangible book value per share at year end	$	17.55		$	17.28		$	18.12		$	17.52		$	16.70
Average number of common shares outstanding – diluted	80,132			80,139			80,279			80,431			80,417
Dividends declared per common share	$	0.9025		$	0.8200		$	0.7550		$	0.6800		$	0.5800
Capitalization
PNMR common stockholders’ equity	41.1		%	44.0		%	46.6		%	49.0		%	49.1		%
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.3			0.3			0.3			0.3
Long-term debt	58.6			55.7			53.1			50.7			50.6
	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2016			2015			2014		2013		2012
	(In thousands)
PNM Revenues
Residential	$	395,490		$	427,958		$	411,412	$	411,579	$	409,005
Commercial	394,150			437,279			428,085		415,621		413,332
Industrial	56,650			75,308			73,002		74,552		78,637
Public authority	23,174			26,202			25,278		25,745		25,495
Economy service	31,121			35,132			39,123		32,909		25,354
Transmission	34,267			33,216			38,284		38,228		39,373
Firm-requirements wholesale	22,497			31,263			38,313		42,370		39,390
Other sales for resale	70,375			63,195			82,508		67,538		47,321
Mark-to-market activity	(1,645		)	(5,270		)	5,996		293		892
Other	9,834			6,912			5,913		7,477		13,465
Total PNM Revenues	$	1,035,913		$	1,131,195		$	1,147,914	$	1,116,312	$	1,092,264
TNMP Revenues
Residential	$	124,462		$	120,771		$	114,826	$	111,373	$	103,255
Commercial	103,174			102,956			99,701		95,098		88,258
Industrial	17,427			16,316			15,049		13,084		13,405
Other	81,975			67,844			58,363		52,056		45,222
Total TNMP Revenues	$	327,038		$	307,887		$	287,939	$	271,611	$	250,140



PNM MWh Sales
Residential	3,189,527	3,185,363	3,169,071	3,304,350	3,323,544
Commercial	3,831,295	3,800,472	3,874,292	3,954,774	4,022,184
Industrial	875,109	957,308	984,130	1,041,160	1,136,011
Public authority	249,860	246,496	251,187	266,368	279,169
Economy service	805,733	796,430	758,629	719,342	635,305
Firm-requirements wholesale	429,345	444,495	527,597	654,135	651,972
Other sales for resale	2,899,322	2,110,947	2,271,480	2,061,851	1,652,225
Total PNM MWh Sales	12,280,191	11,541,511	11,836,386	12,001,980	11,700,410
TNMP MWh Sales
Residential	2,933,938	2,912,019	2,802,768	2,796,661	2,714,511
Commercial	2,742,366	2,654,102	2,583,664	2,472,979	2,374,805
Industrial	2,976,800	2,804,919	2,708,151	2,576,762	2,705,456
Other	98,596	100,999	102,118	104,516	103,856
Total TNMP MWh Sales	8,751,700	8,472,039	8,196,701	7,950,918	7,898,628

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2016		2015		2014		2013		2012
PNM Customers
Residential	462,921		459,353		455,907		453,218		450,507
Commercial	56,357		56,107		55,853		55,447		54,953
Industrial	247		250		249		251		250
Economy service	1		1		1		1		1
Other sales for resale	36		39		39		34		36
Other	887		908		911		928		952
Total PNM Customers	520,449		516,658		512,960		509,879		506,699
TNMP Consumers
Residential	204,744		202,359		199,963		196,799		193,550
Commercial	39,817		39,014		38,033		37,460		36,819
Industrial	66		70		70		70		70
Other	1,993		2,018		2,044		2,070		2,037
Total TNMP Consumers	246,620		243,461		240,110		236,399		232,476
PNMR Generation Statistics
Net Capability – MW, including PPAs	2,791		2,787		2,707		2,572		2,537
Coincidental Peak Demand – MW	1,908		1,889		1,878		2,008		1,948
Average Fuel Cost per MMBTU	$	1.821	$	2.168	$	2.415	$	2.237	$	2.308
BTU per KWh of Net Generation	9,975		10,456		10,422		10,308		10,289

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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 767,000 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 three key 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 employee safety, plant performance, and system reliability


•	Delivering a superior customer experience


•	Demonstrating environmental stewardship 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 two key factors: fair and timely regulatory treatment for its utilities and the utilities’ 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.

Fair and timely rate treatment from regulators is crucial to PNM and TNMP in earning their allowed returns and critical for PNMR to achieve its strategic goals. PNMR believes that earning allowed returns 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. Additional information about rate filings is provided in Note 17.

State Regulation

New Mexico Rate Cases – On September 28, 2016, the NMPRC issued an order that authorizes PNM to implement an increase in base non-fuel rates of $61.2 million for New Mexico retail customers, effective for bills sent after September 30, 2016. This order was on PNM’s application for a general increase in retail electric rates (the “NM 2015 Rate Case”) filed in August 2015. PNM’s application requested an increase in base non-fuel revenues of $121.5 million based on a future test year (“FTY”) beginning October 1, 2015. The primary drivers of the revenue deficiency were infrastructure investments and declines in forecasted energy sales due to successful energy efficiency programs and other economic factors. PNM also proposed changes to rate design to provide fairer pricing across rate classes and better align cost recovery with cost causation.

Following public hearings, the Hearing Examiner in the case issued a recommended decision (“RD”) in August 2016 proposing an increase in non-fuel revenues of $41.3 million. The NMPRC’s order approved many aspects of the RD, including the determination that PNM was imprudent in purchasing the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. However,

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the order also made certain significant modifications to the RD. Major components of the difference between the increase in non-fuel revenues approved in the order and PNM’s request, include:


•	A ROE of 9.575%, compared to the 10.5% requested by PNM

•

Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, totaling 64.1 MW, of PVNGS Unit 2 (Note 7) at an initial rate base value of $83.7 million, compared to PNM’s request for recovery of the fair market value purchase price of $163.3 million; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which costs totaled $43.8 million when the order was issued


•	Disallowance of the recovery of any future contribution for PVNGS decommissioning costs related to the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016 and the 114.6 MW of the leased capacity in PVNGS Units 1 and 2 that were extended for eight years beginning January 15, 2015 and 2016 (Note 7)

•

Disallowance of recovery of the costs associated with converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS (Note 16), but allows recovery of avoided operating and maintenance expenses of $0.3 million annually related to BDT; PNM’s share of the costs of installing the BDT equipment was $52.3 million, $40.0 million of which PNM requested be included in rate base in the NM 2015 Rate Case;


•	Disallowance of recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges

The order continues the renewable energy rider and approves certain aspects of PNM’s proposals regarding rate design, but does not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The order also proposed changes in the methods of recovering certain costs through PNM’s FPPAC and renewable energy rider. The order credits retail customers with 100% of the New Mexico jurisdictional portion of revenues from refined coal (a third-party pre-treatment process) at SJGS. The order approves PNM’s proposals for revised depreciation rates (with certain exceptions), the inclusion of CWIP in rate base, and the ratemaking treatment of the prepaid pension asset.

On September 30, 2016, PNM filed a Notice of Appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which states PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. Specifically, PNM’s statement indicated it is appealing the following elements of the NMPRC’s order:


•	Disallowance of recovery of the full fair market value purchase price of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016


•	Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM


•	Disallowance of recovery of future contributions for PVNGS decommissioning attributable to 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases


•	Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT

The issues that are being appealed by the various cross-appellants are:


•	The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2


•	The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners


•	The revised method to collect PNM’s fuel and purchased power costs under the FPPAC


•	The final rate design


•	The NMPRC allowing PNM to include the pre-paid pension asset in rate base

NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. Otherwise, the court has taken no action with respect to the appeals. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule is anticipated to be completed by June 7, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals.

PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the

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issues, those issues would be remanded back to the NMPRC for further action. PNM estimates that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. Accordingly, PNM recorded a pre-tax regulatory disallowance of $11.3 million representing 15 months of capital cost recovery on its investments that the order disallowed, as well as amounts recorded as regulatory assets and deferred charges that the order disallowed and which PNM did not challenge in its appeal.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. PNM believes it is reasonably possible that its appeals will be successful, but cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record additional pre-tax losses related to any unsuccessful issues. The December 31, 2016 book values of PNM’s investments that the order disallowed, after considering the loss recorded in 2016, were $76.9 million for the 64.1 MW of purchased capacity in PVNGS Unit 2, $39.9 million for the PVNGS Unit 2 disallowed capital improvements, and $50.0 million for the BDT equipment.

PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $155.6 million at December 31, 2016 (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and prepaid pension asset in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM.

PNM is unable to predict the outcome of this matter.

On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates (the “NM 2016 Rate Case”). PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request in the NM 2016 Rate Case are:


•	An increase in base non-fuel revenues of $99.2 million


•	Based on a FTY beginning January 1, 2018


•	ROE of 10.125%


•	Drivers of revenue deficiency


◦	Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (see below and Note 16)


◦	Infrastructure investments


◦	Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors


◦	Updates in the FERC/retail jurisdictional allocations


•	Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation


◦	Increased customer and demand charges


◦	A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs

Hearings are scheduled to begin on June 5, 2017. The NMPRC also ordered that a settlement conference should be held and that any resulting stipulation should be filed by March 27, 2017. The settlement conference has been scheduled for March 7, 2017.

PVNGS Unit 3 – 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. PVNGS Unit 3 is included as a jurisdictional resource in PNM’s NM 2016 Rate Case.

Rate Riders and Interim Rate Relief – 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. This permits more timely recovery of investments. The PUCT has also approved riders that allow TNMP to recover amounts related to AMS, energy efficiency, third-party transmission

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costs, and the CTC. 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.

TNMP General Rate Case – TNMP’s last general rate case was filed in 2010 with new rates becoming effective on February 1, 2011. In connection with TNMP’s deployment of its AMS , TNMP has committed to file a general rate case no later than September 1, 2018.

FERC Regulation

In 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 wholesale generation 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 generation contracts. Consequently, PNM has decided to stop pursuing wholesale generation contracts.

Navopache Electric Cooperative, Inc. – PNM had a PSA, which contained an expiration date in 2035, to supply power to NEC that 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. FERC approved the settlement in January 2016. Under the agreement, PNM served all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those provided under the PSA. In 2016, PNM served all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC paid certain third-party transmission costs that it did not pay in 2014 and only partially paid in 2015. The PSA terminated on December 31, 2016. In 2017, PNM will 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 available under short-term market rates at the time of the settlement. In 2016, 2015 and 2014, revenues were $20.0 million, $27.1 million, and $28.4 million under the PSA. Although the settlement agreement will negatively impact results of operations in 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’s NM 2016 Rate Case discussed above proposes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

Transmission Service Formula Rate Mechanism – PNM filed a request with FERC for 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 FERC approved on March 17, 2016. The settlement reflects a ROE of 10% and resulted in an annualized increase in rates of $1.3 million above the rates approved in the previous case.

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 of their investment in the Company’s business. PNMR’s current target is 7% to 8% earnings growth through 2019. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that excludes from earnings determined in accordance with GAAP certain non-recurring, infrequent, and other items that are not indicative of fundamental changes in the earnings capacity of the Company’s operations. PNMR uses ongoing earnings to evaluate the operations of the Company and to establish goals, including those used for certain aspects of incentive compensation, for management and employees.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. PNMR expects to provide above industry-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue

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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%
December 2016		10%

Maintaining Solid Investment Grade Credit Ratings

The Company is committed to maintaining solid 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. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade with a stable outlook.

Business Focus

PNMR strives to create enduring value for customers, communities, and shareholders. 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 the focus of PNMR’s utilities 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 service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and supporting economic growth. When contemplating expanding or relocating their operations, 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. 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.

Advanced Metering

In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its Texas service area. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters. 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, 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.

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asks the NMPRC to authorize the recovery, in future ratemaking proceedings, of the cost of the project, up to $87.2 million, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million and the costs of customer education and severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. In August 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. The NMPRC approved the motion and a hearing on the AMI application began on February 27, 2017. PNM cannot predict the outcome of this matter.

Utility Plant Investments

During the 2014 to 2016 period, PNM and TNMP together invested $1,541.4 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. PNM began construction on the 40 MW natural gas-fired

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La Luz peaking generating station located near Belen, New Mexico in April 2015 and the facility went into service in December 2015. In 2015, PNM also completed installation of SNCR and BDT equipment on SJGS Units 1 and 4, as well as the addition of 40 MW of PNM-owned solar PV facilities. In addition, on January 15, 2016, PNM completed the $163.3 million acquisition of 64.1 MW of capacity in PVNGS Unit 2 that had previously been leased to PNM.

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 energy demand with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities.

PNM has begun its process for the 2017 IRP that is to be filed by July 3, 2017. In the NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 16, PNM is required to make a filing in 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down.

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

SJGS

Regional Haze Rule Compliance Plan – On December 16, 2015, PNM received NMPRC approval for the plan to comply with the EPA regional haze rule at SJGS that minimizes the cost impact to customers while still achieving broad environmental benefits. Under the approved plan, the installation of SNCRs on SJGS Units 1 and 4 was completed in early 2016 and Units 2 and 3 will be retired by the end of 2017. The plan provides for similar visibility improvements, but at a lower cost to PNM customers than a previous EPA ruling that would have required the installation of more expensive SCRs on all four units at SJGS. The plan has the added advantage of reducing other emissions in addition to NOx, including SO₂, particulate matter, CO₂, and mercury, as well as reducing water usage. Additional information is contained in Note 16.

Under the key provisions of the order approving the compliance plan, PNM:


•	Will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) by December 31, 2017 and recover, over 20 years, 50% (currently estimated to be approximately $128.6 million) of their undepreciated net book value at that date and earn a regulated return on those costs


•	Is granted a CCN to acquire an additional 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 (see New Mexico Rate Cases above and Note 17)


•	Is 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 (currently estimated to be approximately $151 million)


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


•	Will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022


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


•	Will acquire and 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)


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

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At December 31, 2015, PNM recorded pre-tax losses aggregating $165.7 million to reflect the write-off of the 50% of the estimated December 31, 2017 net book value of SJGS Units 2 and 3 that will not be recovered, the other unrecoverable costs, and the increase in the estimated liability recorded for coal mine reclamation resulting from the new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”). In 2016, PNM recorded additional pre-tax losses of $3.7 million resulting from revised estimates of these items. Additional information about the CSA is discussed below and in Note 16. On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On March 31, 2016, NEE filed a complaint against PNM with the NMPRC regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter.

SJGS Ownership Restructuring – In connection with 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 negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items.

The San Juan Project Restructuring Agreement (“RA”) sets forth the agreement among the SJGS owners regarding ownership restructuring. Key provisions of the RA include:

•

Capacity acquisition – On December 31, 2017, PNM will acquire 132 MW of the exiting owners’ capacity in SJGS Unit 4 and PNMR Development agreed to 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. As ordered by the NMPRC, PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates.


•	Coal inventory – The RA also sets forth the terms under which PNM acquired 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 provides economic benefits that are being passed on to PNM’s customers through the FPPAC.

•

Coal supply – 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 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 Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland Coal Company to finance the purchase price. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement with a commercial bank. PNMR guarantees NM Capital’s obligations to the bank. The Westmoreland Loan has a maturity date of February 1, 2021 and initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. WSJ 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. As of February 21, 2017, the balance of the Westmoreland Loan was $85.4 million.

•

Coal mine reclamation – Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs 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, which currently aggregate $118.7 million, with the NMMMD. PNMR has arrangements under which a bank has issued $30.3 million in letters of credit to facilitate posting of the required reclamation bonds. See Note 16.

Other SJGS Environmental Matters – 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. Implementation of the Clean Power Plan, which was published by EPA in October 2015, is currently stayed by order of the US Supreme Court pending further proceedings before the DC Circuit. Oral argument was heard by the DC Circuit in September 2016, but the court has taken no action. PNM estimates that implementation of the BART plan at SJGS, which is discussed above, 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.

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 46%, SO₂ by 78%, particulate matter by 75%, and mercury by 98%.

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Water Conservation and Solid Waste Reduction

PNM continues its efforts to reduce the amount of fresh water used to make electricity (about 20% more efficient than in 2007). 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 to replace SJGS Units 2 and 3 starting in 2018, when water consumption at that plant will be reduced 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. In 2016, 19 of the Company’s 23 facilities met the waste diversion goal of a 60% diversion rate, while recycling at least the same number of waste streams as 2015. The Company expects to continue to do well in this area 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, 2016, PNM had 107 MW of utility-owned solar capacity, including 40 MW completed in 2015. The NM 2015 Rate Case discussed above includes recovery of the costs associated with the 40 MW solar facilities. As discussed in Note 17, PNMR Development will construct and own 30 MW of new solar capacity that PNM will use to supply power to a new data center being constructed by Facebook Inc. in PNM’s service territory. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 62.7 MW at December 31, 2016. 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 was one of the first combinations of battery storage and PV energy in the nation and involved extensive research and development of advanced grid concepts. The facility also 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 geothermal facility is 4 MW. PNM also purchases RECs as necessary to meet the RPS.

The majority of these renewable resources are key means for PNM to meet the RPS and related regulations that 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’s 2017 renewable energy procurement plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017, but will be within the RCT in 2018. The NMPRC approved the plan on November 23, 2016. The NMPRC found that a variance regarding the RCT is not required. PNM will continue to procure renewable resources while balancing the impact to customers’ bills in order to meet New Mexico’s escalating RPS requirements.

Energy Efficiency

Energy efficiency also plays a significant role in helping to keep customers’ electricity costs low while meeting their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2016, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 74 GWh. This is equivalent to the annual consumption of approximately 11,000 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 2016 resulted in energy savings totaling an estimated 22 GWh. This is equivalent to the annual consumption of approximately 2,250 homes in TNMP’s service territory. In April 2016, TNMP was recognized by Energy Star for TNMP’s successful energy efficiency efforts. TNMP received the “Partner of the Year Energy Efficiency Delivery Award” for its High-Performance Homes Program.

Customer, Stakeholder, and Community Engagement

The Company strives to deliver a superior customer experience. Through outreach, collaboration, and various community-oriented programs, the Company has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, intervenors, legislators, and shareholders. Beginning in 2013, PNM refocused its efforts to improve the customer experience through customer service improvements, including billing and payment options, strategic customer engagement, and improved communications. These efforts are supported by market research to understand the varying needs of its customers, identifying and establishing valued services and programs, and proactively communicating and engaging with

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customers at regional and community levels. PNM’s focus on the customer experience has resulted in increasing scores in the JD Power Electric Utility Residential Customer Satisfaction Study.

The Company has leveraged a number of new communications channels and strategic content to better serve and engage its many stakeholders. PNM’s website, www.pnm.com, provides the details of major regulatory filings, including general rate 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.

With reliability being the primary role of a transmission and distribution service provider in Texas' deregulated market, TNMP continues to focus on keeping end-users updated about interruptions and to encourage customer preparation when severe weather is forecasted.

Local relationships and one-on-one communications remain two of the most valuable ways both PNM and TNMP connect with their stakeholders. Both companies maintain long-standing relationships with governmental representatives and key customers to ensure that these stakeholders are updated on company investments and initiatives. Key stakeholders also have dedicated contacts within PNMR that support their important service needs.

PNMR has a long tradition of supporting the communities it serves in New Mexico and Texas. Through the PNMR Foundation and widespread employee volunteerism, as well as PNM’s low income program, the Company demonstrates its core value of caring. In addition to the extensive engagement both PNM and TNMP have with nonprofits organizations in their communities, the PNM Resources Foundation provides more than $1 million each year across New Mexico and Texas. These Foundation grants help nonprofits become more energy efficient and support community projects ranging from creating public gathering spaces to revitalizing neighborhood parks to building a youth sports field as well as providing employee matching and volunteer grants.

PNM provides support for nonprofits in New Mexico focused in the areas of economic development, education, and environmental giving. During 2016, PNM provided $1.0 million to support these areas in communities within New Mexico. One of PNM’s most important outreach programs is tailored for low income customers. In 2016, PNM hosted 41 community events throughout its service territory to connect low-income customers with nonprofit community service providers offering support and help with such needs as water and gas utility bills, food, clothing, medical programs, services for seniors, and weatherization. Additionally, through its Good Neighbor Fund, PNM provided $0.5 million of assistance with electric bills to 3,770 families in 2016 and offered financial literacy training to further support customers.

Volunteerism is an important facet of the PNMR culture. In 2016, more than 750 PNM and TNMP employees and retirees contributed approximately 9,000 volunteer hours serving their local communities. Company volunteers also actively participate on nonprofit boards, in educational, economic, and environmental forums, as well as safety seminars. PNMR employees are, in large part, responsible for the success of the Company’s customer, stakeholder, and community outreach.

Economic Factors

PNM – In 2016 and 2015, PNM experienced decreases in weather-normalized retail load of 0.7% and 1.4% primarily due to decreased industrial sales. The sales decreases reflect a continued sluggish economy in New Mexico. The Albuquerque metropolitan area is beginning to show results from economic development efforts with some recent announcements of businesses moving operations into PNM’s service territory, including the selection of a site in New Mexico for a data center by Facebook Inc. There also have been some expansions of existing businesses, particularly in healthcare, education, and professional services. The employment growth in the Albuquerque metro area has been improving with growth of 1.0% for the rolling twelve months ended in December 2016. The economy in New Mexico continues to have mixed indicators and 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, particularly in the Albuquerque metropolitan area and Santa Fe, as the state deals with budget shortfalls.

A large industrial customer of PNM has announced a restructuring initiative, but has not formally announced what impacts, if any, the restructuring would have on its operations in PNM’s service territory. Accordingly, PNM is unable to predict if there will be any impact to its operations.

TNMP – In 2016 and 2015, TNMP experienced increases in volumetric weather normalized retail load of 3.0% and 2.6%. Most of TNMP’s industrial and larger commercial customers are billed based on their peak demand. The Texas economy continues to grow, primarily due to its diverse base, which helps compensate for the weakness in the energy sector. The decline in oil prices

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impacted the economy, particularly in the Houston area although it seems to have passed the worst of the economic downturn. Oil prices have leveled out, drilling rig counts are going up, and TNMP is adding new transmission customers in its West Texas service territory where oil and gas production continues to grow.

Results of Operations

Net earnings attributable to PNMR were $116.8 million, or $1.46 per diluted share in the year ended December 31, 2016 compared to $15.6 million, or $0.20 per diluted share in 2015 primarily resulting from higher regulatory disallowances in 2015, primarily resulting from the NMPRC order approving the shutdown of SJGS Units 2 and 3 to enable SJGS to comply with the CAA (Note 16). Among other things, earnings in 2016 benefited from additional revenues due to the rate increase approved in the NM 2015 Rate Case at PNM, rate increases and increased load at TNMP, reduced rent expense under the PVNGS leases and plant maintenance costs at PNM, higher interest income, 2015 impairments of income tax carryforwards, and greater earnings and realized gains on securities held in decommissioning and reclamation trusts compared to the prior year. These increases were offset by lower sales prices for power from PVNGS Unit 3, lower revenue from NEC, lower equity AFUDC, milder weather at TNMP, a 2015 refund under a FERC tariff for gas transportation agreements, the 2015 SPS settlement, and increased depreciation, property tax, interest, and employee and retiree related expenses. Additional information on factors impacting results of operation for each segment is discussed under Results of Operations below.

Liquidity and Capital Resources

PNMR and PNM have revolving credit facilities that expire in October 2021. The PNMR and PNM facilities have capacities of $300.0 million and $400.0 million through October 2020 and $290.0 million and $360.0 million from November 2020 through October 2021. Both facilities provide for short-term borrowings 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 $607.6 million at February 21, 2017. 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 $2,472.1 million for 2017-2021. The construction expenditures include estimated amounts for environmental upgrades at SJGS and Four Corners, the 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc. (Note 17), and a 40 MW gas-fired peaking generating facility to be completed in 2020. 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 2017-2021 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

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.

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



	Year Ended December 31,						Change
	2016		2015		2014		2016/2015		2015/2014
	(In millions, except per share amounts)

Net earnings	$	116.8	$	15.6	$	116.3	$	101.2	$	(100.7	)
Average diluted common and common equivalent shares	80.1		80.1		80.3		—		(0.2		)
Net earnings per diluted share	$	1.46	$	0.20	$	1.45	$	1.26	$	(1.25	)

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



	Change
	2016/2015			2015/2014
	(In millions)
PNM	$	92.7		$	(102.6	)
TNMP	(0.3		)	4.2
Corporate and Other	8.9			(2.2		)
Net change	$	101.2		$	(100.7	)

Information regarding the factors impacting PNMR’s operating results by segment are set forth below.

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.

PNM

PNM’s utility margin is defined as electric operating revenues less cost of energy, which consists primarily of fuel and purchase power costs. PNM believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all fuel and purchase power costs are offset in revenues as those costs are passed through to customers under PNM’s FPPAC. In 2016, fuel and purchased power costs passed through the FPPAC were $41.3 million less than in 2015, which reduced both revenue and cost of energy. The decreases reflect lower coal costs at SJGS beginning in 2016 under the new CSA. See Note 16. In 2015, PNM also was recovering an under-collection of fuel costs that resulted from a prior regulatory proceeding, which amount was fully recovered as of December 31, 2015. See Note 17.

The following table summarizes the operating results for PNM:



	Year Ended December 31,									Change
	2016			2015			2014			2016/2015			2015/2014
	(In millions)
Electric operating revenues	$	1,035.9		$	1,131.2		$	1,147.9		$	(95.3	)	$	(16.7	)
Cost of energy	299.7			391.1			403.6			(91.4		)	(12.5		)
Utility margin	736.2			740.1			744.3			(3.9		)	(4.2		)
Operating expenses	414.7			591.0			422.1			(176.3		)	168.9
Depreciation and amortization	133.4			115.7			109.5			17.7			6.2
Operating income	188.1			33.4			212.7			154.7			(179.3		)
Other income (deductions)	32.2			33.5			20.8			(1.3		)	12.7
Interest charges	(87.5		)	(80.0		)	(79.4		)	(7.5		)	(0.6		)
Segment earnings (loss) before income taxes	132.9			(13.1		)	154.1			146.0			(167.2		)
Income (taxes) benefit	(40.9		)	12.8			(52.6		)	(53.7		)	65.4
Valencia non-controlling interest	(14.5		)	(14.9		)	(14.1		)	0.4			(0.8		)
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings (loss)	$	76.9		$	(15.8	)	$	86.8		$	92.7		$	(102.6	)

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The following table shows GWh sales, including the impacts of weather, by customer class and average number of customers:



	Year Ended December 31,			Change
	2016	2015	2014	2016/2015		2015/2014
	(Gigawatt hours, except customers)
Residential	3,189.5	3,185.4	3,169.1	4.1		16.3
Commercial	3,831.3	3,800.5	3,874.3	30.8		(73.8	)
Industrial	875.1	957.3	984.1	(82.2	)	(26.8	)
Public authority	249.9	246.5	251.2	3.4		(4.7	)
Economy energy service ⁽¹⁾	805.7	796.4	758.6	9.3		37.8
Firm-requirements wholesale	429.3	444.5	527.6	(15.2	)	(83.1	)
Other sales for resale ⁽²⁾	2,899.3	2,110.9	2,271.5	788.4		(160.6	)
	12,280.2	11,541.5	11,836.4	738.6		(294.9	)
Average retail customer (thousands)	518.6	514.9	511.2	3.7		3.7

⁽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 2016 and 2015, revenue decreased due to lower market prices.


⁽²⁾	Increase in 2016 includes the hazard sharing agreement with Tri-State (Note17)

Operating Results – 2016 Compared to 2015

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2016
		Change
Utility margin:		(In millions)

	Customer usage/load – PNM’s weather normalized retail KWh sales decreased 0.7%; decreased industrial sales were offset by increases in residential and commercial customer sales, who pay a higher price per KWh	$	1.1
	Rate relief – Additional revenue due to the rate increase and certain fuel costs being passed through the FPPAC	19.6
	Weather – Milder weather; heating degree days were lower by 3.9% and cooling degree days were lower by 2.2% in 2016	(0.9		)
	Transmission – Higher revenues under formula transmission rates and lower cost of third party transmission	3.2
	Wholesale contracts – Primarily lower revenues from NEC (Note 17)	(5.8		)
	Unregulated margin – Lower market prices for PVNGS Unit 3 sales	(12.1		)
	Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges	(6.3		)
	Net unrealized economic hedges – Primarily related to hedges of PVNGS Unit 3 power sales	3.6
	Settlements – 2015 refunds under FERC tariff for gas transportation agreement and SPS settlement (Note 16)	(5.4		)
	Other	(0.9		)
	Net Change	$	(3.9	)

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The following tables summarize the primary drivers for operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:



		Year Ended December 31, 2016
		Change
Operating expenses:		(In millions)

	Regulatory disallowance due to the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 17)	$	11.3
	Regulatory disallowances associated with the SJGS BART determination and ownership restructuring (Note 16)	(162.0		)
	2015 regulatory disallowance of rate case expenses resulting from the NMPRC dismissal of the 2014 general rate case	(1.5		)
	Lower rent expense associated with PVNGS leases (Note 7)	(21.7		)
	Lower rent expense due to the termination of the EIP lease on April 1, 2015	(0.7		)
	Lower plant maintenance costs at SJGS and gas-fired plants, partially offset by increased costs at Four Corners plant	(8.5		)
	Higher labor, pension, benefits, and OPEB costs	6.6
	Implementation of process improvement initiatives associated with reducing future costs	3.7
	Higher property taxes due to increases in utility plant in service	2.3
	Lower costs associated with rate riders, which are offset in utility margin	1.8
	Lower environmental expenses	(1.0		)
	2015 costs associated with exploring alternative fuel supply for SJGS	(2.2		)
	Other	(4.4		)
	Net Change	$	(176.3	)



Depreciation and amortization:

	Purchase of assets underlying PVNGS Unit 2 leases (Note 7)	$	4.8
	Higher depreciation rates approved in the NM 2015 Rate Case	3.3
	Other additions to utility plant in service, including PNM-owned solar PV facilities and environmental upgrades at SJGS	9.6
	Net Change	$	17.7



Other income (deductions):

	Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts	$	3.5
	Interest income from IRS, net of expenses (Note 11)	2.9
	Sale of substations and associated transmission facilities in 2015	(1.1		)
	Higher interest income and lower trust expenses related to available-for-sale securities in the NDT and coal mine reclamation trusts	1.5
	Lower equity AFUDC as a result of lower construction spending	(6.3		)
	Lower income from refined coal (a third-party pre-treatment process at SJGS), due to the decision in the NM 2015 Rate Case directing that such income be passed through to customers	(1.0		)
	Other	(0.8		)
	Net Change	$	(1.3	)

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		Year Ended December 31, 2016
		Change
Interest charges:		(In millions)

	Issuance of $250.0 million of long-term debt on August 11, 2015	$	(5.5	)
	Lower debt AFUDC as a result of lower construction spending	(2.2		)
	Other	0.2
	Net Change	$	(7.5	)



Income taxes:

	Increase due to higher segment earnings before income taxes	$	(57.1	)
	Impacts of decrease in equity AFUDC	(2.4		)
	Impacts of phased-in reduction in New Mexico corporate income tax rates	(1.3		)
	Reversal of deferred income tax items related to the BART determination for SJGS in 2015	1.8
	Allowed regulatory recovery of 2014 impairment of state net operating loss carryforward (net of amortization)	1.9
	Impairments of state net operating loss carryforwards in 2015	3.6
	Other	(0.2		)
	Net Change	$	(53.7	)

Operating Results – 2015 Compared to 2014

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2015
		Change
Utility margin:		(In millions)

	Customer usage/load – PNM’s weather normalized retail KWh sales decreased 1.4%, primarily resulting from a sluggish economy in New Mexico	$	(8.7	)
	Weather – 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	2.1
	Transmission – Lower transmission margin, primarily resulting from expiration of long term contracts	(5.1		)
	Wholesale contracts – Primarily due to the expiration of the Gallup contract(Note 17)	(3.4		)
	Rio Bravo Purchase – Termination of the PPA on July 17, 2014 (Note 9)	3.6
	Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges	8.2
	Settlements – Refund under FERC tariff for gas transportation agreement and SPS settlement (Note 16)	5.4
	Net unrealized economic hedges – Primarily related to hedges of PVNGS Unit 3 power sales	(11.7		)
	Other	5.4
	Net Change	$	(4.2	)

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The following tables summarize the primary drivers for operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:



		Year Ended December 31, 2015
		Change
Operating expenses:		(In millions)

	2015 pre-tax write-off associated with the BART determination and ownership restructuring of SJGS (Note 16)	$	165.7
	Higher plant maintenance costs, primarily at SJGS and PVNGS	8.9
	Higher employee medical expenses, primarily due to unfavorable claims experience, including an unusually high number of large dollar claims	4.6
	Higher costs associated with rate riders, which are usually offset in utility margin	2.7
	Costs associated with exploring alternative fuel supply for SJGS	2.2
	Lower rent expense due to the termination of the EIP lease on April 1, 2015 (Note 7)	(2.1		)
	Lower rental costs related to renewal of the PVNGS Unit 1 leases on January 1, 2015 (Note 7)	(16.0		)
	Other	2.9
	Net Change	$	168.9



Depreciation and amortization:

	Increase primarily due to additions to utility plant in service, including PNM-owned solar PV facilities and the Rio Bravo purchase	$	6.2



Other income (deductions):

	Higher pre-tax gains, net of impairments, on available-for-sale securities in the NDT and coal mine reclamation trusts	$	5.5
	Higher fees and taxes related to available-for-sale securities in the NDT and coal mine reclamation trusts	(2.0		)
	Higher income from refined coal (a third-party pre-treatment process, which began in November 2014) at SJGS	4.0
	Higher equity AFUDC due to increased levels of construction	5.0
	Sale of substations and associated transmission facilities	1.1
	Other	(0.9		)
	Net Change	$	12.7



Interest charges:

	Issuance of $250.0 million of long-term debt on August 11, 2015	$	(4.1	)
	Higher debt AFUDC as a result of increased construction spending	3.6
	Other	(0.1		)
	Net Change	$	(0.6	)

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		Year Ended December 31, 2015
		Change
Income taxes:		(In millions)

	Decrease due to lower earnings before income taxes	$	65.8
	Impact of decrease in equity AFUDC	1.9
	Settlement of IRS Exam in 2014	1.1
	Impairments of state net operating loss carryforwards	(1.5		)
	Reversal of deferred income tax items related to the BART determination for SJGS in 2015	(1.8		)
	Other	(0.1		)
	Net Change	$	65.4

TNMP

TNMP’s utility margin is defined as electric operating revenues less cost of energy, which consists of costs charged by third-party transmission providers. TNMP believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since all third-party transmission costs are passed through to customers through a transmission cost recovery factor.

The following table summarizes the operating results for TNMP:



	Year Ended December 31,									Change
	2016			2015			2014			2016/2015			2015/2014
	(In millions)
Electric operating revenues	$	327.0		$	307.9		$	287.9		$	19.1		$	20.0
Cost of energy	80.9			73.5			67.9			7.4			5.6
Utility margin	246.2			234.4			220.0			11.8			14.4
Operating expenses	93.4			88.1			84.4			5.3			3.7
Depreciation and amortization	61.1			56.3			50.1			4.8			6.2
Operating income	91.6			90.0			85.6			1.6			4.4
Other income (deductions)	3.2			3.7			2.1			(0.5		)	1.6
Interest charges	(29.3		)	(27.7		)	(27.4		)	(1.6		)	(0.3		)
Segment earnings before income taxes	65.5			66.1			60.3			(0.6		)	5.8
Income (taxes)	(23.8		)	(24.1		)	(22.5		)	0.3			(1.6		)
Segment earnings	$	41.7		$	42.0		$	37.8		$	(0.3	)	$	4.2

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The following table shows total GWh sales, including the impacts of weather, by retail tariff consumer class and average number of consumers:



	Year Ended December 31,			Change
	2016	2015	2014	2016/2015		2015/2014
	(Gigawatt hours)
Residential	2,933.9	2,912.0	2,802.8	21.9		109.2
Commercial	2,742.4	2,654.1	2,583.7	88.3		70.4
Industrial	2,976.8	2,804.9	2,708.2	171.9		96.7
Other	98.6	101.0	102.1	(2.4	)	(1.1	)
	8,751.7	8,472.0	8,196.7	279.7		275.2
Average retail consumers (thousands) ⁽¹⁾	245.3	241.6	238.2	3.7		3.4


⁽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.

Operating results – 2016 compared to 2015

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2016
		Change
Utility margin:		(In millions)

	Rate relief – Transmission cost of service rate increases in March and September of 2016 and 2015 (See Note 17)	$	4.5
	Customer usage/load – 3.0% increase in weather normalized retail KWh sales, primarily related to the residential and commercial classes; higher demand-based revenues for large commercial and industrial retail customers; and increased wholesale transmission load in 2016; the average number of retail customers increased 1.5%	5.7
	Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor, which are partially offset in operating expenses, depreciation and amortization, and interest charges	3.3
	Weather – Milder weather in 2016; heating degree days were 19.6% lower and cooling degree days were 1.3% higher compared to 2015	(1.8		)
	Energy efficiency program – Higher incentive bonus in 2016	0.1
	Net Change	$	11.8

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The following tables summarize the primary drivers for operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:



		Year Ended December 31, 2016
		Change
Operating expenses:		(In millions)

	Increased property taxes due to increases in utility plant in service and higher assessed values	$	1.2
	Lease abandonment costs associated with building consolidation efforts	1.0
	Higher pension and benefit expense	0.9
	Higher rate rider related costs, which are offset in utility margin	0.8
	Higher labor	0.8
	Other	0.6
	Net Change	$	5.3



Depreciation and amortization:

	Increase due to AMS deployment and CTC amortization	$	2.0
	Increase due to increases in utility plant in service	2.8
	Net Change	$	4.8



Other income (deductions):

	Decrease primarily due to lower contributions in aid of construction, partially offset by higher equity AFUDC and interest income from IRS (Note 17)	$	(0.5	)



Interest charges:

	Increase primarily due to the issuance of $60.0 million of long-term debt on February 10, 2016, partially offset by debt AFUDC	$	(1.6	)



Income taxes:

	Decrease primarily due to lower segment earnings before income taxes	$	0.3

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Operating Results – 2015 compared to 2014

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2015
		Change
Utility margin:		(In millions)

	Rate relief – Transmission cost of service rate increases in March and September of 2015 and 2014 (See Note 17)	$	8.0
	Customer usage/load – 2.6% increase in weather normalized retail KWh sales primarily related to the residential class; higher demand-based revenues for large commercial and industrial retail customers; partially offset by decreased wholesale transmission load in 2015, the average number of retail customers increased 1.5%	3.0
	Rate riders – Impacts of rate riders, including the AMS surcharge, CTC surcharge, energy efficiency rider, and transmission cost recovery factor, which are partially offset in operating expenses, depreciation and amortization, and interest charges	4.4
	Weather – Milder weather in 2015; heating degree days were 12.2% lower and cooling degree days were 6.4% higher compared to 2014	(0.2		)
	Energy efficiency program – Lower incentive bonus in 2015	(0.8		)
	Net Change	$	14.4

The following tables summarize the primary drivers for operating expenses, depreciation and amortization, other income (deductions), interest charges, and income taxes:



		Year Ended December 31, 2015
		Change
Operating expenses:		(In millions)

	Higher employee medical expenses, primarily due to unfavorable claims experience, including an unusually high number of large dollar claims	$	2.4
	Increased property taxes due to increases in utility plant in service and higher assessed values	1.4
	Higher rate rider related costs, which are offset in utility margin	0.4
	Higher capitalization of administrative and general expenses due to the mix of transmission and distribution construction expenditures	(0.9		)
	Other	0.4
	Net Change	$	3.7



Depreciation and amortization:

	Increase due to AMS deployment and CTC amortization	$	3.7
	Increase due to increases in utility plant in service	2.5
	Net Change	$	6.2



Other income (deductions):

	Increase primarily due to higher contributions in aid of construction	$	1.6

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		Year Ended December 31, 2015
		Change
Interest charges:		(In millions)

	Increase 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	$	(0.3	)



Income taxes:

	Increase primarily due to higher segment earnings before income taxes	$	(1.6	)

Corporate and Other

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



	Year Ended December 31,									Change
	2016			2015			2014			2016/2015			2015/2014
				(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—
Utility margin	—			—			—			—			—
Operating expenses	(12.8		)	(14.9		)	(14.5		)	2.1			(0.4		)
Depreciation and amortization	14.5			13.9			13.1			0.6			0.8
Operating income (loss)	(1.7		)	0.9			1.4			(2.6		)	(0.5		)
Other income (deductions)	10.4			(0.6		)	(2.4		)	11.0			1.8
Interest charges	(11.8		)	(7.2		)	(12.8		)	(4.6		)	5.6
Segment earnings (loss) before income taxes	(3.2		)	(6.9		)	(13.8		)	3.7			6.9
Income (taxes) benefit	1.5			(3.7		)	5.4			5.2			(9.1		)
Segment earnings (loss)	$	(1.7	)	$	(10.6	)	$	(8.4	)	$	8.9		$	(2.2	)

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP under shared services agreements. The amounts allocated include certain expenses shown as depreciation and amortization and other income (deductions) in the table above. The change in depreciation expense primarily relates to 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.

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Operating results – 2016 compared to 2015

The following tables summarize the primary drivers for other income (deductions), interest charges, and income taxes:



		Year ended December 31, 2016
		Change
Other income (deductions):		(In millions)

	Interest income on the $125.0 million Westmoreland Loan (Note 16) beginning February 1, 2016	$	11.3
	Losses recorded in 2015 on items included in other investments related to a former PNMR subsidiary that ceased operations in 2008	1.1
	Interest income from IRS, net of related expenses (Note 11)	0.8
	PNMR Development’s share of the fee resulting from the ownership restructuring of SJGS recorded at December 31, 2015 (Note 16)	(3.1		)
	Other	0.9
	Net Change	$	11.0



Interest charges:

	Issuance of the $125.0 million BTMU Term Loan Agreement on February 1, 2016 (Note 6)	$	(4.6	)
	Issuance of the $150.0 million PNMR 2015 Term Loan Agreement on March 9, 2015	(1.5		)
	Maturity of $118.8 million of long-term debt on May 15, 2015	4.3
	Higher short term borrowings	(2.6		)
	Other	(0.2		)
	Net Change	$	(4.6	)



Income taxes:

	Reduction in benefit due to change in segment earnings (loss) before income taxes	$	(1.4	)
	Impairment of wind energy production tax credits recorded in 2015	3.1
	Impairment of state net operating loss recorded in 2015	1.7
	Impairment of charitable contributions carry forward recorded in 2015	2.0
	Other	(0.2		)
	Net Change	$	5.2

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Operating Results – 2015 compared to 2014

The following tables summarize the primary drivers for other income (deductions), interest charges, and income taxes:



		Year ended December 31, 2015
		Change
Other income (deductions):		(In millions)

	PNMR Development’s share of the fee resulting from the ownership restructuring of SJGS recorded December 31, 2015 (Note 16)	$	3.1
	Losses recorded in 2015 on items included in other investments related to a former PNMR subsidiary that ceased operations in 2008	(1.1		)
	Other	(0.2		)
	Net Change	$	1.8



Interest charges:

	Issuance of the $150.0 million PNMR 2015 Term Loan Agreement on March 9, 2015	$	(1.4	)
	Maturity of $118.8 million of long-term debt on May 15, 2015	7.0
	Net Change	$	5.6



Income taxes:

	Reduction in benefit due to change in segment earnings (loss) before income taxes	$	(2.7	)
	Impairment of wind energy production tax credits	(2.2		)
	Impairment of state net operating loss	(0.7		)
	Impairment of charitable contributions carry forward recorded in 2015	(2.0		)
	Settlement of IRS examination in 2014	(1.3		)
	Other	(0.2		)
	Net Change	$	(9.1	)

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

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



	Year Ended December 31,									Change
	2016			2015			2014			2016/2015			2015/2014
	(In millions)
Net cash flows from:
Operating activities	$	415.5		$	386.9		$	414.9		$	28.6		$	(28.0	)
Investing activities	(699.4		)	(544.5		)	(485.3		)	(154.9		)	(59.2		)
Financing activities	242.4			175.4			96.2			67.0			79.2
Net change in cash and cash equivalents	$	(41.5	)	$	17.8		$	25.7		$	(59.3	)	$	(7.9	)

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. PNMR made contributions to the PNM and TNMP pension and other postretirement benefit plans of $4.5 million in 2016 compared to $35.5 million in 2015 and $5.4 million in 2014.

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The changes in PNMR’s cash flows from investing activities include increases in plant additions of $41.5 million in 2016 compared to 2015 and $97.9 million in 2015 compared to 2014. At PNM, total utility plant additions were $40.6 million higher in 2016 compared to 2015, including the $163.3 million purchase of assets underlying three of the leases for capacity in PVNGS Unit 2 (Note 7) on January 15, 2016 and higher nuclear fuel purchases of $0.6 million, offset by decreases in other generation additions of $68.5 million and lower transmission and distribution additions of $54.8 million. PNM’s total utility plant additions were $88.0 million higher in 2015 compared to 2014, including increased generation of $47.0 million, renewables of $34.4 million, transmission and distribution of $3.8 million, and nuclear fuel of $2.8 million. TNMP utility plant additions decreased $2.1 million in 2016 compared to 2015, including decreases in distribution additions of $19.3 million and AMS additions of $4.6 million offset by an increase in transmission additions of $21.8 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. Corporate and other plant additions were $2.9 million higher in 2016 compared to 2015, including an increase in computer and hardware and software additions of $10.0 million, offset by a decrease in PNMR Development utility plant additions of $7.1 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. Construction expenditures were funded primarily through cash flows from operating activities and short-term borrowings. Investing activities also include the $122.3 million Westmoreland Loan, offset by $30.0 million in payments received (Note 16) on that loan, $2.6 million received from the sale of Gallup assets in 2015, and $36.2 million paid for the acquisition of Rio Bravo in 2014 (Note 9).

The changes in PNMR’s cash flows from financing activities include a decrease in net short-term borrowings of $108.5 million in 2016 compared to 2015. Long-term borrowings in 2016 include $122.5 million under the BTMU Term Loan Agreement. NM Capital used the proceeds of the BTMU Term Loan Agreement to provide funds for the Westmoreland Loan. Borrowings also include the $100.0 million PNMR One-Year Term Loan (included in short-term borrowings) and the $100.0 million PNMR Two-Year Term Loan, which were used to repay $150.0 million outstanding under the PNMR Term Loan Agreement and other short-term borrowings. In 2016, PNM entered into the $175.0 million PNM 2016 Term Loan Agreement and used a portion of the proceeds to repay $125.0 million outstanding under the PNM Multi-Draw Term Loan. In 2016, PNM also successfully refunded $146.0 million of PCRBs. In 2016, TNMP issued $60.0 million of 3.53% first mortgage bonds and used the funds to reduce short-term debt and intercompany debt. 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 of the PNMR 2015 Term Loan Agreement 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. 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 a PNM term loan 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 a TNMP term loan and other short-term borrowings.

Financing Activities

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


•	Ability to earn a fair return on equity


•	Results of operations


•	Ability to obtain required regulatory approvals


•	Conditions in the financial markets


•	Credit ratings

Each of the Company’s revolving credit facilities and term loans contains one financial covenant, which requires the maintenance of debt-to-capital ratios of less than or equal to 65%, and generally include customary covenants, events of default, cross default provisions, and change of control provisions.

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.

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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. 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, which aggregated 3.64% at December 31, 2016. The principal balance outstanding under the BTMU Term Loan Agreement was $92.2 million at December 31, 2016 and $82.8 million at February 21, 2017. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. NM Capital utilized the proceeds of the BTMU Term Loan Agreement to provide funding for the $125.0 million Westmoreland Loan to a ring-fenced, bankruptcy-remote, special-purpose entity, which is a subsidiary of Westmoreland, to finance the purchase price of the stock of SJCC.

On May 20, 2016, PNM entered into a $175.0 million term loan agreement (the “PNM 2016 Term Loan Agreement”). The PNM 2016 Term Loan Agreement bears interest at a variable rate and has a maturity date of November 17, 2017. PNM used a portion of the proceeds of the PNM 2016 Term Loan Agreement to prepay without penalty the $125.0 million outstanding under the PNM Multi-draw Term Loan, which had a scheduled maturity of June 21, 2016.

On September 27, 2016, PNM participated in the issuance and sale of an aggregate of $146.0 million of PCRBs by the City of Farmington, New Mexico. The proceeds from the sale were utilized to refund an aggregate of $146.0 million of outstanding PCRBs previously issued by the City of Farmington. The arrangements governing the PCRBs result in PNM reflecting the bonds as debt on its financial statements. The PCRBs bear interest at a rate of 1.875% for the period from September 27, 2016 through September 30, 2021, have a mandatory tender for remarketing on October 1, 2021, and a final maturity on April 1, 2033.

On October 21, 2016, PNMR entered into letter of credit arrangements with JPMorgan Chase Bank, N.A. (the “JPM LOC Facility”) under which letters of credit aggregating $30.3 million were issued to replace letters of credit previously issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit facilitate the posting of reclamation bonds, which SJCC is required to post in connection with permits relating to the operation of the San Juan mine (Note 16).

On December 21, 2016, PNMR entered into two term loan agreements: (1) a $100.0 million term loan agreement (the “PNMR 2016 One-Year Term Loan”) among PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as administrative agent, that matures on December 21, 2017; and (2) a $100.0 million term loan agreement (the “PNMR 2016 Two-Year Term Loan”) among PNMR and JPMorgan Chase Bank, N.A., as lender and administrative agent, that matures on December 21, 2018. The proceeds of the term loans were used to repay the $150.0 million twelve-month PNMR Term Loan Agreement and to reduce borrowings under the PNMR Revolving Credit Facility.

At December 31, 2016, interest rates on outstanding borrowings were 1.55% for the PNMR 2015 Term Loan Agreement, 1.60% for the PNMR 2016 One-Year Term Loan, 1.69% for the PNMR 2016 Two-Year Term Loan, and 1.36% for the PNM 2016 Term Loan Agreement. PNMR has 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.

Capital Requirements

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


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


•	Expanding the electric transmission and distribution systems


•	Purchasing nuclear fuel

Projected capital requirements for 2017-2021 are:



	2017		2018-2021		Total
	(In millions)
Construction expenditures	$	517.3	$	1,565.8	$	2,083.1
Dividends on PNMR common stock	77.3		309.1		386.4
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	595.1	$	1,877.0	$	2,472.1

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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 environmental upgrades of $44.2 million at Four Corners, $46.9 million for 30 MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc. (Note 17), and $43.7 million for a 40 MW gas-fired peaking generating facility to be completed in 2020. Expenditures for environmental upgrades are estimated to be $35.5 million in 2017. 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, 2016, 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. As indicated above, the $125.0 million PNM Multi-draw Term Loan was repaid prior to its June 21, 2016 maturity and $146.0 million of PNM PCRBs were refunded in September 2016. The $175.0 million PNM 2016 Term Loan Agreement matures in November 2017 and $57.0 million of PNM PCRBs are subject to mandatory tender for remarketing in June 2017. In addition, NM Capital is required to make quarterly payments of at least $5.0 million under the BTMU Term Loan Agreement. However, NM Capital must also utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $42.0 million on the BTMU Term Loan Agreement in the year ended December 31, 2017, including $9.4 million paid on February 1, 2017. Note 6 contains additional information about the maturities of long-term debt. 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, the PNM Revolving Credit Facility, and the TNMP Revolving Credit Facility. 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 in January 2018. In November 2016, PNMR and PNM entered into agreements to extend the maturity of the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility from October 31, 2020 to October 31, 2021. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitment beyond October 31, 2020. Unless one or more of the other current lenders or a new lender assumes the commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021. The TNMP Revolving Credit Facility expires in September 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 $40.0 million to $179.5 million, zero to $45.3 million, and zero to $21.1 million during the years ended December 31, 2016, 2015, and 2014. Such borrowings ranged from $121.9 million to $179.5 million during the three months ended December 31, 2016. Borrowings under the PNM Revolving Credit Facility ranged from zero to $135.0 million, zero to $48.4 million, and zero to $82.0 million during the years ended December 31, 2016, 2015, and 2014. Such borrowings ranged from $14.4 million to $51.5 million during the three months ended December 31, 2016. Borrowings under the PNM New Mexico Credit Facility ranged from zero to $50.0 million, zero to $20.0 million, and zero to $25.0 million during the years ended December 31, 2016, 2015 and 2014. Such borrowings ranged from $6.0 million to $26.0 million during the three months ended December 31, 2016. Borrowings under the TNMP Revolving Credit Facility ranged from zero to $70.0 million, zero to $64.0 million, and zero to $30.0 million during the years ended December 31, 2016, 2015, and 2014. There were no borrowings under the TNMP Revolving Credit Facility during the three months ended December 31, 2016. At December 31, 2016,

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the interest rates on outstanding borrowings were 1.98% for the PNMR Revolving Credit Facility, 1.82% for the PNM Revolving Credit Facility, and 1.81% for the PNM New Mexico Credit Facility.

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 2008 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 2017-2021 period. This could include new debt issuances and/or new equity.

PNMR retired its 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. As of February 21, 2017, 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

Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade. Both S&P and Moody’s have PNMR, PNM, and TNMP on a stable outlook. However, the ultimate outcome from PNM’s NM 2015 Rate Case, including the pending appeal before the NM Supreme Court, and the outcome of PNM’s NM 2016 Rate Case, as discussed in Note 17, could affect both the outlook and credit ratings. Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements as of February 21, 2017 is as follows:



	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
			(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0
Amounts outstanding as of February 21, 2017:
Revolving credit facility	$	144.3	$	31.3	$	8.0	$	183.6
PNM New Mexico Credit Facility	—		25.0		—		25.0
Letters of credit	6.2		2.5		0.1		8.8
Total short-term debt and letters of credit	150.5		58.8		8.1		217.4
Remaining availability as of February 21, 2017	$	149.5	$	391.2	$	66.9	$	607.6
Invested cash as of February 21, 2017	$	1.5	$	—	$	—	$	1.5

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In addition to the above, PNMR had $30.3 million of letters of credit outstanding under the JPM LOC Facility. The above table excludes intercompany debt. As of February 21, 2017, TNMP had $7.4 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. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers.

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 with higher revenue requirements in the initial years that decline over the life of the plant as depreciation occurs. By contrast, the revenue requirements for 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 and Note 7 for additional information.

The future lease payments for the PVNGS leases are shown below.



	PVNGS Units 1&2
	(In thousands)
2017	$	18,131
2018	18,131
2019	18,131
2020	18,131
2021	18,131
Thereafter	28,833
Total	$	119,488

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.

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Commitments and Contractual Obligations

The following table sets forth PNMR’s long-term contractual obligations as of December 31, 2016. See Note 7 for further details about the Company’s significant leases:



	Payments Due
Contractual Obligations	2017		2018-2019		2020-2021		2022 and Thereafter		Total
	(In thousands)
Long-term debt^(a)	$	274,025	$	892,337	$	436,517	$	785,698	$	2,388,577
Interest on long-term debt^(b)	118,526		168,590		99,351		565,650		952,117
Operating leases ^(c)	27,873		50,868		50,002		84,462		213,205
Transmission reservation payments	10,867		23,880		10,398		6,454		51,599
Coal contracts^(d)	211,047		217,101		214,817		418,798		1,061,763
Coal mine decommissioning^{(e) (f)}	9,765		21,188		23,443		204,837		259,233
Nuclear decommissioning funding requirements^(f)	2,637		5,274		5,274		17,458		30,643
Outsourcing	2,287		1,737		—		—		4,024
Pension and retiree medical^(g)	1,946		3,811		3,671		—		9,428
Construction expenditures ^(h)	517,343		829,561		736,192		—		2,083,096
Total⁽ⁱ⁾	$	1,176,316	$	2,214,347	$	1,579,665	$	2,083,357	$	7,053,685


^(a)	Represents total long-term debt, excluding unamortized discounts, premiums, and issuance costs (Note 6);


^(b)	Represents interest payments during the period


^(c)	The operating lease amounts include payments under the PVNGS leases through the expiration of the leases; see Off-Balance Sheet Arrangements above, Note 7 and Note 9


^(d)	Represents only certain minimum payments that may be required under the coal contracts in effect on December 31, 2016 if no deliveries are taken


^(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; the Company only forecasts capital expenditures for the next five years; see Capital Requirements above and Note 14

⁽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 $6.8 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, TNMP Revolving Credit Facility, and the PNMR 2015 Term Loan Agreement 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 other term loans, each contain a covenant requiring the maintenance of debt-to-capital ratios of not more than 65%. 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.

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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 natural 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. The Company believes its financing arrangements are sufficient to meet the requirements of the contingent provisions.

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

Capital Structure

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



	December 31,
PNMR	2016		2015
PNMR common equity	41.1	%	44.0	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	58.6	%	55.7	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	46.0	%	45.3	%
Preferred stock	0.4	%	0.4	%
Long-term debt	53.6	%	54.3	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	58.5	%	59.6	%
Long-term debt	41.5	%	40.4	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2016, GHG associated with PNM’s interests in its generating plants included approximately 6.9 million metric tons of CO₂, which comprises the vast majority of PNM’s GHG. By comparison, the total GHG in the United States in 2014, the latest year for which EPA has published this data, were approximately 6.9 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 owned 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, in January 2015, began purchasing the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW. PNM has a 20-year PPA for the output of Lightning Dock Geothermal, which began

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providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. Additionally, PNM has a customer distributed solar generation program that represented 62.7 MW at December 31, 2016. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 136 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a budget of $26.0 million for the 2017 program year. PNM estimates these programs saved approximately 74 GWh of electricity in 2016. 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.

For the past several years, management has identified multiple risks and opportunities related to climate change, including potential environmental regulation, technological innovation, and availability of fuel and water for operations, as among the most significant risks facing the Company. Accordingly, these risks are overseen by the full Board in order to facilitate more integrated risk and strategy oversight and planning. Board oversight includes understanding of the various challenges and opportunities presented by these risks, including the financial consequences that might result from potential federal and/or state regulation of GHG; plans to mitigate the risks; and the impacts these risks may have on the Company’s strategy. In addition, the Board approves certain PNM investments in environmental equipment and grid modernization technologies.

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

As of December 31, 2016, approximately 70.7% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 16, PNM received approval for the December 31, 2017 shutdown of SJGS Units 2 and 3 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.

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.

PNM’s generating stations are located in the arid southwest. Access to water for cooling for some of these facilities is critical to continued operations. Forecasts for the impacts of climate change on water supply in the southwest range from reduced precipitation to changes in the timing of precipitation. In either case, PNM’s facilities requiring water for cooling will need to mitigate the impacts of climate change through adaptive measures. Current measures employed by PNM generating stations such as air cooling, use of grey water, improved reservoir operations, and shortage sharing arrangements with other water users will continue to be important to sustain operations.

PNM’s service areas occasionally 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 Company-owned facilities, which disrupts the ability to transmit and/or distribute energy, weather and other events of nature can temporarily reduce customers’ usage and demand for energy.

Changes in the climate are generally not expected to have material consequences to the Company in the near-term. The Company cannot anticipate or predict the potential long-term effects of climate change on its assets and operations.

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EPA Regulation

In April 2007, the US Supreme Court held that EPA has the authority to regulate GHG under the CAA. This decision heightened the importance of this issue for the energy industry. In December 2009, EPA released its endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO₂, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the “Tailoring Rule”) to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered 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 DC 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 US Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The US Supreme Court limited its review to the question of whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA’s determination was unlawful as it violates Congressional intent.

On June 23, 2014, the US Supreme Court issued its opinion in the above case and reversed the DC Circuit. First, the US Supreme Court found the CAA does not compel or permit EPA to adopt an interpretation of the act that requires a source to obtain a PSD or Title V permit on the sole basis of its potential GHG. Second, the US Supreme Court rejected EPA’s position 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. Third, the US Supreme Court found EPA lacked authority to “tailor” the CAA’s unambiguous numerical thresholds of 100 or 250 tons per year. Fourth, the US Supreme Court found that it would be reasonable for EPA to interpret the CAA to limit the PSD program for GHGs to “anyway” sources – those sources that have to comply with the PSD program for other non-GHG pollutants. The US Supreme Court said that EPA needed to establish a de minimis level below which BACT would not be required for “anyway” sources. In response to the US Supreme Court decision, EPA released a proposed rule on October 3, 2016, to revise the permitting rules for GHG under the CAA. Among other things, the proposed rule would set the Significant Emissions Rate (“SER”) for GHGs under the major source permitting program at 75,000 tons of CO₂ equivalent per year for new and modified sources that are already subject to NSR based on emission of other pollutants. If finalized as proposed, the rule would require a new major source or major modification that triggers PSD permitting for other criteria pollutants like NOx to undergo a BACT review for GHG if the potential to emit GHG exceeds the 75,000 tons per year. Comments on the proposed rule were due on December 16, 2016.

On June 25, 2013, former President Obama announced his Climate Action Plan which outlined how his administration planned 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 proposed actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The former President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum established a timeline for the re-proposal and issuance of a GHG NSPS for new sources under section 111(b) of the CAA 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 directed 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 the standards are developed and implemented in a manner that provides for reliable and affordable energy. Presidential Memorandum required EPA 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 former 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

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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 from new, modified, and reconstructed power plants 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 are 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 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, the Clean Power Plan compliance schedule required states to make initial plan submissions to EPA by September 6, 2016. EPA could then choose to grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension were to submit an update to EPA in 2017 and final plans by September 2018. States not requesting an extension were to submit their final plans by September 2016. 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 (“CEIP”) 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. On June 30, 2016, EPA published proposed design details of the CEIP. Comments were due to EPA on November 1, 2016. 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 indicated that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explained 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 an 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 indicated that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule offered both

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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.

Multiple states, utilities, and trade groups filed petitions for review and motions to stay in the DC Circuit. On January 21, 2016, the DC 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, briefing on all issues was to be 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 US Supreme Court asking the court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court granted the applications to stay the Clean Power Plan pending judicial review of the rule. The US Supreme Court 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 US Supreme Court 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 and may still have six more months to prepare initial plans and 2.5 years for final plans (if an extension is granted by EPA). The DC Circuit heard oral arguments on the merits of the states’ case on September 27, 2016. The arguments were made in front of a 10-judge panel. There is no mandatory deadline for the DC Circuit to make a decision on the case and a decision is not expected until sometime later in 2017. The stay will remain in effect pending US Supreme Court 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 existing 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 PNM’s 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 GHG reduction from coal and gas-fired power plants 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 BART plan 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 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 in Congress of legislation imposing a new or enhanced regulatory program to address climate change are unlikely in 2017. Instead, EPA is the primary vehicle for GHG regulation in the near future, especially for coal-fired EGUs. The US Supreme Court’s decision to stay the Clean Power Plan puts into question the viability of that rule. In addition, President Trump’s administration is expected to take action to roll back the rule. Even if Clean Power Plan is upheld by the courts, EPA could, in theory, rescind or revise the rule through notice-and-comment rulemaking.

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. PNM has begun its process for the 2017 IRP that is to be filed by July 3, 2017. In the current IRP PNM will present resource portfolio plans for scenarios that assume SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assume SJGS

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will cease operations by the end of 2022. PNM has been meeting with customers and stakeholders as part of a public advisory process since June 2016. The materials presented in the process are available at www.pnm.com\irp.

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

On August 2, 2012, thirty-three New Mexico organizations representing public health, business, environmental, consumers, Native American, and other interested parties filed a petition for rulemaking with the NMPRC. The petition asked the NMPRC to issue a NOPR regarding the implementation of an Optional Clean Energy Standard for electric utilities located in New Mexico. The proposed standard would have utilities that elect to participate reduce their CO₂ emissions by 3% per year. Utilities that opt into the program would be assured recovery of their reasonable compliance costs. On October 4, 2012, the NMPRC held a workshop to discuss the proposed standard and whether it has authority to proceed with the NOPR. On August 28, 2013, the petitioners amended the August 2, 2012 petition and requested that the NMPRC issue a NOPR to implement a “Carbon Risk Reduction Rule” for electric utilities in New Mexico. The proposed rule would require affected utilities to demonstrate a 3% per year CO₂ emission reduction from a three-year average baseline period between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than one metric ton of CO₂per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was 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 to the UNFCCC, 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, 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 to negotiate by 2015 an international agreement involving commitments by all nations to begin reducing carbon emissions by 2020. On December 12, 2015, the Paris Agreement was finalized during the 2015 COP. The agreement, which was agreed to by more than 190 nations, requires that countries submit Nationally Determined Contributions (“NDCs”). NDCs reflect national targets and actions that arise out of national policies, and elements relating to oversight, guidance and coordination of actions to reduce emissions by all countries. In November 2014, former President Obama announced the United States’ commitment to reduce GHG, on an economy-wide basis, by 26%-28% from 2005 levels by the year 2025. The United States NDC is part of an overall effort by the Obama administration to have the United States achieve economy-wide reductions of around 80% by 2050. As part of the process for developing the new global climate agreement, the United States set forth this reduction commitment in its intended NDC. As part of the Paris Agreement, initial NDCs have been submitted by 189 nations, including the United States and the European Union. Thresholds for the number of countries necessary to ratify or accede to the Paris Agreement and total global GHG percentage were achieved on October 5, 2016, and the Paris Agreement entered into force on November 4, 2016. To date, 127 countries have ratified the Paris Agreement. PNM will continue to monitor the United States’ participation in international accords. The Obama administration’s GHG reduction target for the electric utility industry is a key element of its NDC and is based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources. With the change in federal administrations, the United States’ continued participation in the Paris Agreement is now uncertain. PNM believes that implementation of the BART plan for SJGS (Note 16) should provide a significant step towards compliance with the Clean Power Plan, should it prevail, or other GHG reduction requirements.

Assessment of Legislative/Regulatory Impacts

The Company 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 specific GHG limits; the timing of implementation of these limits; the possibility of a market-based trading program, including the associated costs and the availability of emission credits or allowances; the development of emission reduction and/or renewable energy technologies; 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

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assumptions are, at best, preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation or regulation 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 too preliminary and speculative at this time for a meaningful prediction of financial impact.

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 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.

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 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.

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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; long-term 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 18 contains information on the impairment testing performed by the Company on goodwill. For 2016, the Company utilized a quantitative analysis for both the PNM and TNMP reporting units. No impairments were indicated in the Company’s annual goodwill testing, which was performed as of April 1, 2016. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. The annual testing was based on certain critical estimates and assumptions. Changes in the estimates or the use of different assumptions could affect the determination of fair value and the conclusion of impairment for each reporting unit.

Application of the 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

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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 2016 quantitative testing appropriately reflected the fair value of both the PNM and TNMP reporting units. Since any cash flow projection contains uncertainty, the WACC used by each of PNM and TNMP 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, 2016, 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, 2016. The April 1, 2016 quantitative evaluation of fair value of the TNMP reporting unit, which had goodwill of $226.7 million, exceeded its carrying value by approximately 32%. 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 TNMP’s fair value over carrying value to approximately 21% at April 1, 2016. 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 decommissioning costs represent approximately 86% 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 $14.3 million at December 31, 2016. 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 recognizes an expense and a corresponding liability for ultimate decommissioning of PVNGS. See Note 17 for information concerning the treatment of nuclear decommissioning in the NMPRC’s order in PNM’s NM 2015 Rate Case and PNM’s appeal of that order.

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 $5.6 million at December 31, 2016. 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 reclamation costs.

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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 loss events that are both probable of occurring and can be reasonably estimated based upon current available information. However the actual outcomes can vary from any amounts accrued which could have a material effect on the results of operations and financial position of the Company. See Note 16 and Note 17.

Income Taxes

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

Market Risk

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

MD&A FOR PNM

RESULTS OF OPERATIONS

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

MD&A FOR TNMP

RESULTS OF OPERATIONS

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


ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages the scope of its various forms of market 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

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•	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


•	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, 2016 and 2015, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

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



	PNMR and PNM
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
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
Amount realized on contracts delivered during period	(316		)
Changes in fair value	(1,261		)
Net mark-to-market change recorded in earnings	(1,577		)
Net change recorded as regulatory liability	(114		)
Net fair value at December 31, 2016	$	2,885

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, 2016



	Settlement Dates
	2017
PNMR and PNM	(In thousands)
Economic hedges
Prices actively quoted	$	—
Prices provided by other external sources	2,885
Prices based on models and other valuations	—
Total	$	2,885

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PNM is exposed to changes in the market prices of electricity and natural gas for the positions in its wholesale portfolio (not covered by the FPPAC). The Company manages risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options, and swaps. PNM uses such instruments to hedge its exposure to changes in the market prices of electricity and natural gas. PNM also uses such instruments under an NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC.

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, 2016, the high, low, and average VaR amounts were $1.3 million, $0.3 million, and $0.6 million. 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. At December 31, 2016 and December 31, 2015, the VaR amounts for the PNM wholesale portfolio were $0.6 million and $1.2 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 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 2016 or 2015.

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 wholesale counterparties, all of which will mature in less than two years.

Schedule of Credit Risk Exposure

December 31, 2016



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	$	1,967	—	$	—
Non-investment grade	225		—	—
Split ratings	40		—
Internal ratings:
Investment grade	8,928		2	7,829
Non-investment grade	133		—	—
Total	$	11,293		$	7,829


⁽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.

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⁽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, 2016, PNMR and PNM held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of December 31, 2016 was $5.9 million.

As discussed in Note 16, PNMR’s subsidiary, NM Capital, entered into the Westmoreland Loan to facilitate the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, and PNMR has arranged for letters of credit to be issued to support the coal mining operations of SJCC. PNMR is exposed to credit risk under these arrangements in the event of default by WSJ. As of December 31, 2016, remaining required principal payments under the Westmoreland Loan are $38.4 million in 2017 (including $9.6 million paid on February 1, 2017), $3.6 million in 2018, $8.6 million in 2019, $23.3 million in 2020, and $21.1 million in 2021. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations, the value of which PNMR believes approximates the amount outstanding under the Westmoreland Loan. Furthermore, PNMR considers the possibility of loss under the letters of credit to be remote as discussed in Note 9. Accordingly, PNMR does consider its credit risk under these arrangements to be material.

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 1.7%, 1.5%, and 3.5%, if interest rates were to decline by 50 basis points from their levels at December 31, 2016. 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 21, 2017, PNMR, PNM, and TNMP had $144.3 million, $31.3 million, and $8.0 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 $25.0 million under the $50.0 million PNM New Mexico Credit Facility at February 21, 2017. The revolving credit facilities, the PNM New Mexico Credit Facility, the $150.0 million PNMR 2015 Term Loan Agreement, the $100.0 million PNMR 2016 One-Year Term Loan Agreement, the $100.0 million PNMR 2016 Two-Year Term Loan Agreement, the $175.0 million PNM 2016 Term Loan Agreement, and the $125.0 million BTMU Term Loan Agreement bear interest at variable rates. On February 21, 2017, interest rates on borrowings averaged 2.04% for the PNMR Revolving Credit Facility, 1.68% for the PNMR 2015 Term Loan Agreement, 3.79% for the BTMU Term Loan Agreement, 1.63% for the PNMR 2016 One-Year Term Loan Agreement, 1.73% for the PNMR 2016 Two-Year Term Loan Agreement, 1.90% for the PNM Revolving Credit Facility, 1.91% for the PNM New Mexico Credit Facility, 1.38% for the PNM 2016 Term Loan Agreement, and 1.78% 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 $890.5 million at December 31, 2016, of which 56.1% 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, 2016, the decrease in the fair value of the fixed-rate securities would be 5.2%, or $25.9 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $69.4 million at December 31, 2016, of which 56.9% 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, 2016, the decrease in the fair value of the fixed-rate securities would be 6.0%, or $2.4 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. However, as described in Note 17, the NMPRC has ruled that PNM would not be able to include future contributions made by PNM for decommissioning of PVNGS, to the extent applicable to certain capacity previously leased by PNM, in rates charged to retail customers. PNM has appealed the NMPRC’s ruling to the NM Supreme Court. 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.

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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, 2016. These equity securities expose PNM and TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 30.5% and 25.0% of the securities held by the various PNM and TNMP trusts as of December 31, 2016. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $27.1 million for PNM and $1.7 million for TNMP.

Alternatives Investment Risk

The Company had 14.1% of its pension assets invested in the alternatives asset class as of December 31, 2016. 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 $8.5 million.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX



		Page
Management’s Annual Reports on Internal Control Over Financial Reporting		B - 2
Reports of Independent Registered Public Accounting Firm		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 - 119
Schedule I - Condensed Financial Information of Parent Company		B - 122
Schedule II - Valuation and Qualifying Accounts		B - 125

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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, 2016.

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, 2016.

/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, 2016.

/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, 2016, 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, 2016, 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, 2016 and 2015, 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, 2016, and our report dated February 28, 2017 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2017

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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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, 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, 2016, 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 28, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2017

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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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2017

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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, 2016 and 2015, 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, 2016. 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, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Albuquerque, New Mexico

February 28, 2017

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS



	Year Ended December 31,
	2016			2015			2014
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,362,951		$	1,439,082		$	1,435,853
Operating Expenses:
Cost of energy	380,596			464,649			471,556
Administrative and general	191,514			179,100			171,111
Energy production costs	146,187			176,752			185,638
Regulatory disallowances and restructuring costs	15,011			167,471			1,062
Depreciation and amortization	209,110			185,919			172,634
Transmission and distribution costs	66,227			69,157			66,571
Taxes other than income taxes	76,321			71,684			67,584
Total operating expenses	1,084,966			1,314,732			1,136,156
Operating income	277,985			124,350			299,697
Other Income and Deductions:
Interest income	22,293			6,498			8,483
Gains on available-for-sale securities	19,517			16,060			10,527
Other income	17,796			26,833			12,048
Other (deductions)	(13,784		)	(12,728		)	(10,481		)
Net other income and deductions	45,822			36,663			20,577
Interest Charges	128,633			114,860			119,627
Earnings before Income Taxes	195,174			46,153			200,647
Income Taxes	63,278			15,075			69,738
Net Earnings	131,896			31,078			130,909
(Earnings) Attributable to Valencia Non-controlling Interest	(14,519		)	(14,910		)	(14,127		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Net Earnings Attributable to PNMR	$	116,849		$	15,640		$	116,254
Net Earnings Attributable to PNMR per Common Share:
Basic	$	1.47		$	0.20		$	1.46
Diluted	$	1.46		$	0.20		$	1.45

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,
	2016			2015			2014
	(In thousands)
Net Earnings	$	131,896		$	31,078		$	130,909
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(304), $(4,310), and $(6,812)	474			6,688			10,661
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $8,639, $11,181, and $5,461	(13,500		)	(17,350		)	(8,401		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $7,219, $1,726, and $6,024	(11,282		)	(2,679		)	(9,258		)
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,148), $(2,332), and $(2,032)	3,356			3,620			3,120
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $341, $(28), and $53	(533		)	44			(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(298), $0, and $(195)	466			—			363
Total Other Comprehensive Income (Loss)	(21,019		)	(9,677		)	(3,615		)
Comprehensive Income	110,877			21,401			127,294
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,519		)	(14,910		)	(14,127		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Comprehensive Income Attributable to PNMR	$	95,830		$	5,963		$	112,639

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,
	2016			2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	131,896		$	31,078		$	130,909
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	242,033			222,861			209,867
Deferred income tax expense	63,805			16,451			72,481
Net unrealized (gains) losses on commodity derivatives	1,577			5,188			(6,504		)
Realized (gains) on available-for-sale securities	(19,517		)	(16,060		)	(10,527		)
Stock based compensation expense	5,634			4,863			5,931
Regulatory disallowances and restructuring costs	15,011			167,471			1,062
Allowance for equity funds used during construction	(4,949		)	(10,430		)	(5,563		)
Other, net	3,060			3,934			4,045
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	2,543			(3,298		)	(4,975		)
Materials, supplies, and fuel stock	(4,169		)	(180		)	5,504
Other current assets	(2,469		)	29,370			(30,436		)
Other assets	(42,864		)	2,369			290
Accounts payable	3,159			(32,269		)	(2,311		)
Accrued interest and taxes	3,345			4,957			2,040
Other current liabilities	(12,509		)	2,633			(2,453		)
Other liabilities	29,868			(42,064		)	45,516
Net cash flows from operating activities	415,454			386,874			414,876
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(600,076		)	(558,589		)	(460,658		)
Proceeds from sales of available-for-sale securities	522,601			252,174			117,989
Purchases of available-for-sale securities	(538,383		)	(262,548		)	(127,016		)
Return of principal on PVNGS lessor notes	8,547			21,694			20,758
Purchase of Rio Bravo	—			—			(36,235		)
Investment in Westmoreland Loan	(122,250		)	—			—
Principal repayments on Westmoreland Loan	30,000			—			—
Other, net	186			2,741			(167		)
Net cash flows from investing activities	(699,375		)	(544,528		)	(485,329		)

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,
	2016			2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term loan	100,000			50,000			—
Repayment of short-term loan	(150,000		)	—			—
Revolving credit facilities borrowings (repayments), net	86,500			95,000			(43,600		)
Long-term borrowings	603,500			463,605			355,000
Repayment of long-term debt	(303,793		)	(333,066		)	(125,000		)
Proceeds from stock option exercise	7,028			5,619			6,999
Awards of common stock	(15,451		)	(17,720		)	(17,319		)
Dividends paid	(70,623		)	(64,251		)	(59,468		)
Valencia’s transactions with its owner	(17,006		)	(17,049		)	(17,610		)
Other, net	2,237			(6,707		)	(2,808		)
Net cash flows from financing activities	242,392			175,431			96,194
Change in Cash and Cash Equivalents	(41,529		)	17,777			25,741
Cash and Cash Equivalents at Beginning of Year	46,051			28,274			2,533
Cash and Cash Equivalents at End of Year	$	4,522		$	46,051		$	28,274
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	115,043		$	103,382		$	108,741
Income taxes paid (refunded), net	$	(307	)	$	(1,890	)	$	(2,597	)

Supplemental schedule of noncash investing and financing activities:
(Increase) decrease in accrued plant additions	$	18,345		$	(19,080	)	$	(3,089	)

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,
	2016		2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,522	$	46,051
Accounts receivable, net of allowance for uncollectible accounts of $1,209 and $1,397	87,012		98,699
Unbilled revenues	58,284		52,012
Other receivables	28,245		28,590
Current portion of Westmoreland Loan	38,360		—
Materials, supplies, and fuel stock	73,027		67,386
Regulatory assets	3,855		1,070
Commodity derivative instruments	5,224		3,813
Income taxes receivable	6,066		5,845
Other current assets	73,444		82,104
Total current assets	378,039		385,570
Other Property and Investments:
Long-term portion of Westmoreland Loan	56,640		—
Available-for-sale securities	272,977		259,042
Other investments	547		604
Non-utility property	3,404		3,404
Total other property and investments	333,568		263,050
Utility Plant:
Plant in service, held for future use, and to be abandoned	6,944,534		6,307,261
Less accumulated depreciation and amortization	2,334,938		2,058,772
	4,609,596		4,248,489
Construction work in progress	208,206		204,766
Nuclear fuel, net of accumulated amortization of $43,905 and $44,455	86,913		82,117
Net utility plant	4,904,715		4,535,372
Deferred Charges and Other Assets:
Regulatory assets	501,223		470,664
Goodwill	278,297		278,297
Commodity derivative instruments	—		2,622
Other deferred charges	75,238		73,753
Total deferred charges and other assets	854,758		825,336
	$	6,471,080	$	6,009,328

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,
	2016			2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	287,100		$	250,600
Current installments of long-term debt	273,348			124,979
Accounts payable	86,705			100,419
Customer deposits	11,374			12,216
Accrued interest and taxes	61,871			58,306
Regulatory liabilities	3,609			15,591
Commodity derivative instruments	2,339			1,859
Dividends declared	19,448			17,656
Other current liabilities	59,314			59,494
Total current liabilities	805,108			641,120
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,119,364			1,966,969
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	940,650			877,393
Regulatory liabilities	455,649			467,413
Asset retirement obligations	127,519			111,895
Accrued pension liability and postretirement benefit cost	125,844			73,097
Other deferred credits	140,545			133,692
Total deferred credits and other liabilities	1,790,207			1,663,490
Total liabilities	4,714,679			4,271,579
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)	1,163,661			1,166,465
Accumulated other comprehensive income (loss), net of income taxes	(92,451		)	(71,432		)
Retained earnings	604,742			559,780
Total PNMR common stockholders’ equity	1,675,952			1,654,813
Non-controlling interest in Valencia	68,920			71,407
Total equity	1,744,872			1,726,220
	$	6,471,080		$	6,009,328

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
										Total PNMR Common Stockholder’s Equity
	Common Stock			AOCI			Retained Earnings			Total PNMR Common Stockholder’s Equity						Total Equity
	(In thousands)
Balance at December 31, 2013	$	1,178,369		$	(58,140	)	$	553,340		$	1,673,569		$	77,029		$	1,750,598
Net earnings before subsidiary preferred stock dividends	—			—			116,782			116,782			14,127			130,909
Total other comprehensive income (loss)	—			(3,615		)	—			(3,615		)	—			(3,615		)
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—			—			(60,138		)	(60,138		)	—			(60,138		)
Proceeds from stock option exercise	6,999			—			—			6,999			—			6,999
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		)
Balance at December 31, 2014	1,173,845			(61,755		)	609,456			1,721,546			73,546			1,795,092
Net earnings before subsidiary preferred stock dividends	—			—			16,168			16,168			14,910			31,078
Total other comprehensive income (loss)	—			(9,677		)	—			(9,677		)	—			(9,677		)
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—			—			(65,316		)	(65,316		)	—			(65,316		)
Proceeds from stock option exercise	5,619			—			—			5,619			—			5,619
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		)
Balance at December 31, 2015	1,166,465			(71,432		)	559,780			1,654,813			71,407			1,726,220
Net earnings before subsidiary preferred stock dividends	—			—			117,377			117,377			14,519			131,896
Total other comprehensive income (loss)	—			(21,019		)	—			(21,019		)	—			(21,019		)
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—			—			(71,887		)	(71,887		)	—			(71,887		)
Proceeds from stock option exercise	7,028			—			—			7,028			—			7,028
Awards of common stock	(15,451		)	—			—			(15,451		)	—			(15,451		)
Excess tax (shortfall) from stock-based payment arrangements	(15		)	—			—			(15		)	—			(15		)
Stock based compensation expense	5,634			—			—			5,634			—			5,634
Valencia’s transactions with its owner	—			—			—			—			(17,006		)	(17,006		)
Balance at December 31, 2016	$	1,163,661		$	(92,451	)	$	604,742		$	1,675,952		$	68,920		$	1,744,872

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,
	2016			2015			2014
	(In thousands)
Electric Operating Revenues	$	1,035,913		$	1,131,195		$	1,147,914
Operating Expenses:
Cost of energy	299,714			391,131			403,626
Administrative and general	169,209			161,953			152,645
Energy production costs	146,187			176,752			185,638
Regulatory disallowances and restructuring costs	15,011			167,471			1,062
Depreciation and amortization	133,447			115,717			109,524
Transmission and distribution costs	39,657			43,642			43,128
Taxes other than income taxes	44,598			41,149			39,578
Total operating expenses	847,823			1,097,815			935,201
Operating income	188,090			33,380			212,713
Other Income and Deductions:
Interest income	10,173			6,574			8,557
Gains on available-for-sale securities	19,517			16,060			10,527
Other income	12,088			19,347			8,949
Other (deductions)	(9,539		)	(8,493		)	(7,218		)
Net other income and deductions	32,239			33,488			20,815
Interest Charges	87,469			79,950			79,442
Earnings (Loss) before Income Taxes	132,860			(13,082		)	154,086
Income Taxes (Benefit)	40,922			(12,758		)	52,633
Net Earnings (Loss)	91,938			(324		)	101,453
(Earnings) Attributable to Valencia Non-controlling Interest	(14,519		)	(14,910		)	(14,127		)
Net Earnings (Loss) Attributable to PNM	77,419			(15,234		)	87,326
Preferred Stock Dividends Requirements	(528		)	(528		)	(528		)
Net Earnings (Loss) Available for PNM Common Stock	$	76,891		$	(15,762	)	$	86,798

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,
	2016			2015			2014
	(In thousands)
Net Earnings (Loss)	$	91,938		$	(324	)	$	101,453
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(304), $(4,310), and $(6,812)	474			6,688			10,661
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $8,639, $11,181, and $5,461	(13,500		)	(17,350		)	(8,401		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $7,219, $1,726, and $6,024	(11,282		)	(2,679		)	(9,258		)
Reclassification adjustment for amortization of experience (gains)losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,148), $(2,332), and $(2,032)	3,356			3,620			3,120
Total Other Comprehensive Income (Loss)	(20,952		)	(9,721		)	(3,878		)
Comprehensive Income (Loss)	70,986			(10,045		)	97,575
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(14,519		)	(14,910		)	(14,127		)
Comprehensive Income (Loss) Attributable to PNM	$	56,467		$	(24,955	)	$	83,448

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,
	2016			2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings (loss)	$	91,938		$	(324	)	$	101,453
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	166,047			150,538			143,303
Deferred income tax expense	53,119			(2,836		)	55,787
Net unrealized (gains) losses on commodity derivatives	1,577			5,188			(6,504		)
Realized (gains) on available-for-sale securities	(19,517		)	(16,060		)	(10,527		)
Regulatory disallowances and restructuring costs	15,011			167,471			1,062
Allowance for equity funds used during construction	(4,163		)	(10,430		)	(5,563		)
Other, net	3,046			2,794			4,172
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	4,769			(2,515		)	(5,919		)
Materials, supplies, and fuel stock	(3,924		)	381			5,570
Other current assets	1,127			23,693			(29,146		)
Other assets	(23,880		)	4,194			7,150
Accounts payable	5,614			(31,139		)	212
Accrued interest and taxes	(9,601		)	(5,343		)	(3,599		)
Other current liabilities	(12,136		)	(275		)	(659		)
Other liabilities	20,119			(33,503		)	42,325
Net cash flows from operating activities	289,146			251,834			299,117
Cash Flows From Investing Activities:
Utility plant additions	(445,464		)	(404,840		)	(316,800		)
Proceeds from sales of available-for-sale securities	522,601			252,174			117,989
Purchases of available-for-sale securities	(538,383		)	(262,548		)	(127,016		)
Return of principal on PVNGS lessor notes	8,547			21,694			20,758
Purchase of Rio Bravo	—			—			(36,235		)
Other, net	171			2,935			(363		)
Net cash flows from investing activities	(452,528		)	(390,585		)	(341,667		)

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,
	2016			2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	61,000			—			(49,200		)
Short-term borrowings (repayments) - affiliate, net	—			—			(32,500		)
Long-term borrowings	321,000			313,605			275,000
Repayment of long-term debt	(271,000		)	(214,300		)	(75,000		)
Equity contribution from parent	28,142			175,000			—
Valencia’s transactions with its owner	(17,006		)	(17,049		)	(17,610		)
Dividends paid	(4,670		)	(94,968		)	(30,791		)
Other, net	3,102			(5,879		)	(1,890		)
Net cash flows from financing activities	120,568			156,409			68,009

Change in Cash and Cash Equivalents	(42,814		)	17,658			25,459
Cash and Cash Equivalents at Beginning of Year	43,138			25,480			21
Cash and Cash Equivalents at End of Year	$	324		$	43,138		$	25,480

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	82,514		$	69,936		$	73,787
Income taxes paid (refunded), net	$	(967	)	$	(1,450	)	$	(228	)

Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	22,433		$	(17,469	)	$	(1,616	)

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

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

	December 31,
	2016		2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	324	$	43,138
Accounts receivable, net of allowance for uncollectible accounts of $1,209 and $1,397	65,003		78,291
Unbilled revenues	48,289		42,641
Other receivables	25,514		24,725
Affiliate receivables	8,886		15,105
Materials, supplies, and fuel stock	64,401		60,477
Regulatory assets	3,442		—
Commodity derivative instruments	5,224		3,813
Income taxes receivable	25,807		14,577
Other current assets	67,355		74,990
Total current assets	314,245		357,757
Other Property and Investments:
Available-for-sale securities	272,977		259,042
Other investments	316		366
Non-utility property	96		96
Total other property and investments	273,389		259,504
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,359,211		4,833,303
Less accumulated depreciation and amortization	1,809,528		1,569,549
	3,549,683		3,263,754
Construction work in progress	158,122		172,238
Nuclear fuel, net of accumulated amortization of $43,905 and $44,455	86,913		82,117
Net utility plant	3,794,718		3,518,109
Deferred Charges and Other Assets:
Regulatory assets	365,413		342,910
Goodwill	51,632		51,632
Commodity derivative instruments	—		2,622
Other deferred charges	68,149		66,810
Total deferred charges and other assets	485,194		463,974
	$	4,867,546	$	4,599,344

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,
	2016			2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	61,000		$	—
Current installments of long-term debt	231,880			124,979
Accounts payable	55,566			72,386
Affiliate payables	23,183			14,318
Customer deposits	11,374			12,216
Accrued interest and taxes	34,819			33,189
Regulatory liabilities	3,517			15,591
Commodity derivative instruments	2,339			1,859
Dividends declared	132			132
Other current liabilities	33,551			42,251
Total current liabilities	457,361			316,921
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,399,489			1,455,698
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	748,666			696,384
Regulatory liabilities	423,701			434,863
Asset retirement obligations	126,601			111,049
Accrued pension liability and postretirement benefit cost	114,427			66,285
Other deferred credits	118,980			117,275
Total deferred credits and liabilities	1,532,375			1,425,856
Total liabilities	3,389,225			3,198,475
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)	1,264,918			1,236,776
Accumulated other comprehensive income (loss), net of income taxes	(92,428		)	(71,476		)
Retained earnings	225,382			152,633
Total PNM common stockholder’s equity	1,397,872			1,317,933
Non-controlling interest in Valencia	68,920			71,407
Total equity	1,466,792			1,389,340
	$	4,867,546		$	4,599,344

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, 2013	$	1,061,776	$	(57,877	)	$	206,300		$	1,210,199		$	77,029		$	1,287,228
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		)
Valencia’s transactions with its owner	—		—			—			—			(17,610		)	(17,610		)
Balance at December 31, 2014	1,061,776		(61,755		)	262,835			1,262,856			73,546			1,336,402
Net earnings (loss)	—		—			(15,234		)	(15,234		)	14,910			(324		)
Total other comprehensive income (loss)	—		(9,721		)	—			(9,721		)	—			(9,721		)
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Equity contributions from parent	175,000		—			—			175,000			—			175,000
Dividends declared on common stock	—		—			(94,440		)	(94,440		)	—			(94,440		)
Valencia’s transactions with its owner	—		—			—			—			(17,049		)	(17,049		)
Balance at December 31, 2015	1,236,776		(71,476		)	152,633			1,317,933			71,407			1,389,340
Net earnings	—		—			77,419			77,419			14,519			91,938
Total other comprehensive income (loss)	—		(20,952		)	—			(20,952		)	—			(20,952		)
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Equity contribution from parent	28,142		—			—			28,142			—			28,142
Dividends declared on common stock	—		—			(4,142		)	(4,142		)	—			(4,142		)
Valencia’s transactions with its owner	—		—			—			—			(17,006		)	(17,006		)
Balance at December 31, 2016	$	1,264,918	$	(92,428	)	$	225,382		$	1,397,872		$	68,920		$	1,466,792

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,
	2016			2015			2014
	(In thousands)

Electric Operating Revenues	$	327,038		$	307,887		$	287,939
Operating Expenses:
Cost of energy	80,882			73,518			67,930
Administrative and general	39,423			36,755			36,982
Depreciation and amortization	61,126			56,285			50,056
Transmission and distribution costs	26,570			25,515			23,443
Taxes other than income taxes	27,396			25,781			23,940
Total operating expenses	235,397			217,854			202,351
Operating income	91,641			90,033			85,588
Other Income and Deductions:
Other income	4,629			4,240			2,865
Other (deductions)	(1,427		)	(504		)	(727		)
Net other income and deductions	3,202			3,736			2,138
Interest Charges	29,335			27,681			27,396
Earnings before Income Taxes	65,508			66,088			60,330
Income Taxes	23,836			24,125			22,523
Net Earnings	$	41,672		$	41,963		$	37,807

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,
	2016		2015		2014
	(In thousands)
Net Earnings	$	41,672	$	41,963	$	37,807
Other Comprehensive Income:
Fair Value Adjustment for Cash Flow Hedge:
Change in fair value, net of income tax (expense) benefit of $0, $0, and $53	—		—		(100		)
Reclassification adjustment for losses included in net earnings, net of income tax expense (benefit) of $0, $0, and $(195)	—		—		363
Total Other Comprehensive Income	—		—		263
Comprehensive Income	$	41,672	$	41,963	$	38,070

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,
	2016			2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	41,672		$	41,963		$	37,807
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	62,866			57,909			52,847
Deferred income tax expense	12,662			20,883			20,549
Allowance for equity funds used during construction and other, net	(772		)	18			(10		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(2,226		)	(783		)	944
Materials and supplies	(245		)	(561		)	(66		)
Other current assets	(621		)	3,928			380
Other assets	(19,126		)	(2,310		)	(6,607		)
Accounts payable	(2,040		)	(1,782		)	2,514
Accrued interest and taxes	12,690			4,317			4,796
Other current liabilities	298			1,019			(203		)
Other liabilities	6,822			(9,823		)	3,112
Net cash flows from operating activities	111,980			114,778			116,063
Cash Flows From Investing Activities:
Utility plant additions	(122,518		)	(124,584		)	(127,191		)
Net cash flows from investing activities	(122,518		)	(124,584		)	(127,191		)

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,
	2016			2015			2014
	(In thousands)

Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	(59,000		)	54,000			5,000
Short-term borrowings (repayments) – affiliate, net	(7,200		)	(10,900		)	(6,700		)
Long-term borrowings	60,000			—			80,000
Repayment of long-term debt	—			—			(50,000		)
Equity contribution from parent	50,000			—			—
Dividends paid	(31,817		)	(33,248		)	(16,336		)
Other, net	(775		)	(46		)	(836		)
Net cash flows from financing activities	11,208			9,806			11,128
Change in Cash and Cash Equivalents	670			—			—
Cash and Cash Equivalents at Beginning of Year	1			1			1
Cash and Cash Equivalents at End of Year	$	671		$	1		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	26,766		$	26,216		$	22,803
Income taxes paid, (refunded) net	$	660		$	290		$	(355	)

Supplemental schedule of noncash investing and financing activities:
(Increase) decrease in accrued plant additions	$	(1,271	)	$	(5	)	$	854

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,
	2016		2015
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	671	$	1
Accounts receivable	22,009		20,408
Unbilled revenues	9,995		9,371
Other receivables	2,090		811
Materials and supplies	8,626		6,909
Regulatory assets	413		1,070
Other current assets	1,031		1,053
Total current assets	44,835		39,623
Other Property and Investments:
Other investments	231		238
Non-utility property	2,240		2,240
Total other property and investments	2,471		2,478
Utility Plant:
Plant in service and plant held for future use	1,380,584		1,285,727
Less accumulated depreciation and amortization	429,397		406,516
	951,187		879,211
Construction work in progress	16,978		16,561
Net utility plant	968,165		895,772
Deferred Charges and Other Assets:
Regulatory assets	135,810		127,754
Goodwill	226,665		226,665
Other deferred charges	5,277		4,847
Total deferred charges and other assets	367,752		359,266
	$	1,383,223	$	1,297,139

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,
	2016		2015
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—	$	59,000
Short-term debt – affiliate	4,600		11,800
Accounts payable	16,709		16,006
Affiliate payables	3,793		3,681
Accrued interest and taxes	45,581		32,891
Regulatory liabilities	92		—
Other current liabilities	2,134		2,044
Total current liabilities	72,909		125,422
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	420,875		361,411
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	245,785		232,791
Regulatory liabilities	31,948		32,550
Asset retirement obligations	754		695
Accrued pension liability and postretirement benefit cost	11,417		6,812
Other deferred credits	6,300		4,078
Total deferred credits and other liabilities	296,204		276,926
Total liabilities	789,988		763,759
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	454,166		404,166
Retained earnings	139,005		129,150
Total common stockholder’s equity	593,235		533,380
	$	1,383,223	$	1,297,139

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, 2013	$	64	$	404,166	$	(263	)	$	98,964		$	502,931
Net earnings	—		—		—			37,807			37,807
Total other comprehensive income (loss)	—		—		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
Net earnings	—		—		—			41,672			41,672
Equity contributions from parent	—		50,000		—			—			50,000
Dividends declared on common stock	—		—		—			(31,817		)	(31,817		)
Balance at December 31, 2016	$	64	$	454,166	$	—		$	139,005		$	593,235

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

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014


(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 2015 and 2014 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2016 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. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned 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

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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, 2016, 2015 and 2014

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

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 collected 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. TNMP estimates the CTC will be fully recovered in November 2020.

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, 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, losses, and costs to remove resulting from retirements or other dispositions of regulated property in the normal course of business are credited or charged to accumulated depreciation.

PNM and TNMP may receive reimbursements, referred to as contributions in aid of construction (“CIAC”), from customers to pay for all or part of certain construction projects to extent that project does not benefit regulated customers in general. PNM and TNMP account for these reimbursements as offsets to utility plant additions based on the requirements of the NMPRC, FERC, and PUCT. Due to the PUCT’s regulatory treatment of CIAC reimbursements, TNMP also receives a financing component that is recognized as other income on the Consolidated Statements of Earnings. Under the NMPRC regulatory treatment, PNM does not receive a financing component.

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 and FERC. 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:

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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, 2016, 2015 and 2014



	Year ended December 31
	2016		2015		2014
PNM
Electric plant	2.33	%	2.27	%	2.26	%
Common, intangible, and general plant	5.40	%	4.66	%	4.64	%
TNMP	3.66	%	3.65	%	3.59	%

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 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 or “debt AFUDC”) and a return on other funds (allowance for equity funds used during construction or “equity AFUDC”). The allowance for borrowed funds used during construction is recorded in interest charges and the allowance for equity funds used during construction is recorded in other income on the Consolidated Statements of Earnings.

For the years ended December 31, 2016, 2015, and 2014, PNM recorded $5.3 million, $7.8 million, and $4.2 million of allowance for borrowed funds used during construction and $4.2 million, $10.4 million, and $5.6 million of allowance for equity funds used during construction. TNMP recorded $0.9 million, $0.5 million, and $0.5 million of allowance for borrowed funds used during construction and $0.8 million, 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 6.1%, 6.6%, and 6.6% for 2016, 2015, and 2014. In 2016, 2015, and 2014, capitalized interest was $1.8 million, $1.5 million, and $1.6 million for PNMR consolidated; $0.8 million, $0.8 million, and $1.1 million for PNM; and less than $0.1 million, $0.1 million, and $0.1 million 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
	2016		2015		2016		2015		2016		2015
	(In thousands)
Coal	$	19,940	$	18,356	$	19,940	$	18,356	$	—	$	—
Materials and supplies	53,087		49,030		44,461		42,121		8,626		6,909
	$	73,027	$	67,386	$	64,401	$	60,477	$	8,626	$	6,909

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.

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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, 2016, 2015 and 2014

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (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, 2016, 2015, and 2014, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trusts of $13.9 million, $10.4 million, and $4.8 million. No gains or losses are deferred as regulatory assets or liabilities. Unrealized gains on these investments, net of related tax effects, are included in OCI and AOCI. The available-for-sale securities are primarily comprised of international, United States, state, and municipal government obligations and corporate debt and equity securities. All investments are held in PNM’s name and are in the custody of major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and deductions. See New Accounting Pronouncements below.

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 18.

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 subject to unplanned netting 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.

See New Accounting Pronouncements below.

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,

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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, 2016, 2015 and 2014

except for amounts recoverable through NMPRC, FERC, or PUCT regulation, which are recorded as regulatory assets or liabilities and amortized over the lives of the respective issues. Unamortized debt premium, discount, and expense are reflected as part of the debt liabilities 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 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. See Note 15 and Note 16. See Note 17 for information concerning the treatment of nuclear decommissioning in the NMPRC’s order in PNM’s NM 2015 Rate Case and PNM’s appeal of that order.

In connection with both the SJGS and Four Corners coal supply agreements, 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. PNM considers the contemporaneous reclamation costs part of the cost of its delivered coal costs. See Note 16 for a discussion of the final reclamation costs.

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

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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, 2016, 2015 and 2014

recorded for environmental expense in the years ended December 31, 2016, 2015, and 2014, as well as the amounts of environmental liabilities at December 31, 2016 and 2015 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. In accordance with GAAP, all deferred taxes are reflected as non-current on the Consolidated Balance Sheets. Current NMPRC, FERC, and PUCT approved rates include the tax effects of the majority of these differences. GAAP requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded based on 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)

In May 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. When it becomes effective, the new standard will replace most existing revenue recognition guidance in GAAP. In August 2015, the FASB issued a one-year deferral in the effective date. Since the issuance of ASU No. 2014-09, the FASB also has issued additional ASUs that clarify implementation guidance regarding principal versus agent considerations, licensing, and identifying performance obligations, as well as adding certain additional practical expedients. The new standard can be applied retrospectively to each prior period presented or on a modified retrospective basis with a cumulative effect adjustment to retained earnings on the date of adoption. The Company has not made a final decision on the transition method, but currently anticipates using the modified retrospective method. The Company will adopt the standard on January 1, 2018, its required effective date.

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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, 2016, 2015 and 2014

The Company has completed its initial assessment of its revenues for potential changes to the amounts and timing of revenue recognition under the new guidance and does not anticipate significant changes in revenue recognition associated with retail electric service rates. The Company, along with others in the utility industry, is continuing to evaluate the impacts of the new guidance on its accounting for CIAC and the presentation of revenues associated with “alternative revenue programs,” which primarily result from its approved rate rider programs. The Company is continuing to analyze the impacts this new standard and has not yet completely determined the effect of the standard on its financial reporting.

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

In January 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 will require those equity securities to be measured at fair value with changes in fair value recognized in net income rather than in OCI. Also, the new standard will revise certain presentation and disclosure requirements. Under the new standard, accounting for investments in debt securities remains essentially unchanged. PNM currently classifies the investments held in the NDT and coal mine reclamation trusts as available for sale securities. Unrealized losses on these securities are recorded immediately through earnings and unrealized gains are recorded in AOCI until the securities are sold. The Company will adopt the new standard on January 1, 2018, its required effective date. At that time any unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment and, thereafter, changes in the value of equity securities will be recorded in the Consolidated Statements of Earnings. The amount of the cumulative adjustment upon adoption will depend on the amounts recorded in AOCI at that time, but PNM had unrealized gains, net of income taxes, recorded in AOCI of $3.8 million at December 31, 2016.

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

In February 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 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. Also, the new standard will revise certain disclosure requirements. Although early adoption of the standard is permitted, the Company does not currently plan to adopt this standard prior to January 1, 2019, its required effective date. At adoption of the ASU, leases will be recognized and measured as of the earliest period presented using a modified retrospective approach. The Company is in the process of analyzing the impacts of this new standard.

Accounting Standards Update 2016-09 – Compensation – Stock Compensation (Topic 718)

In March 2016, the FASB issued ASU No. 2016-09. The ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. Currently, tax benefits resulting from deductions in excess of compensation cost on vested restricted stock and performance awards and on exercised stock options (“excess tax benefits”) are recorded to equity provided these benefits reduce taxes payable. Tax deficiencies resulting from deductions related to awards, which are below realized compensation cost upon vesting and on canceled stock options are recorded to equity. PNMR has not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. PNMR will adopt this standard on January 1, 2017, its required effective date, and will record a cumulative effect adjustment to recognize excess tax benefits that have not been recorded due to the PNMR’s net operating loss. The impact of the cumulative effect adjustment will be to increase PNMR’s retained earnings and reduce accumulated deferred income tax liabilities by $8.4 million. PNMR has historically recognized cash flows from employee share withholdings as a financing activity. As a result, implementation of this standard will not result in any retrospective adjustments to the Consolidated Statements of Cash Flows. Subsequent to implementation, all excess tax benefits and deficiencies will be recorded to tax expense on the Consolidated Statements of Earnings and classified as cash flows from operating activities on the Consolidated Statements of Cash Flows.

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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, 2016, 2015 and 2014

Accounting Standards Update 2016-13 – Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments

In June 2016, the FASB issued ASU No. 2016-13. The ASU changes the way entities recognize impairment of many financial assets, including accounts receivable and investments in debt securities, by requiring immediate recognition of estimated credit losses expected to occur over their remaining lives. The new standard is effective for the Company beginning on January 1, 2020. Early adoption is permitted beginning on January 1, 2019. The Company is in the process of analyzing the impacts of this new standard.

Accounting Standards Update 2016-15 – Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU No. 2016-15. The ASU eliminates diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. Although early adoption is permitted, the Company does not currently plan to adopt this standard prior to January 1, 2018, its required effective date. The Company is in the process of analyzing the impacts of this new standard, but does not anticipate it will have a significant impact on the Company’s financial statements.

Accounting Standards Update 2016-18 – Statement of Cash Flows (Topic 230): Restricted Cash

In November 2016, the FASB issued ASU 2016-18. The ASU requires that the statements of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents during the period. Under the new standard, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the Statements of Cash Flows. Although early adoption is permitted, the Company does not currently plan to adopt this standard prior to January 1, 2018, its required effective date. The new standard requires the use of a retrospective transition method for each period presented after adoption. The Company is in the process of analyzing the impacts of this new standard.


(2)	Segment Information

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

PNM

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

TNMP

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

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company. The activities of PNMR Development and NM Capital are also included in Corporate and Other.

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, 2016, 2015 and 2014

PNMR SEGMENT INFORMATION



2016	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Electric operating revenues	$	1,035,913		$	327,038		$	—		$	1,362,951
Cost of energy	299,714			80,882			—			380,596
Utility margin	736,199			246,156			—			982,355
Other operating expenses	414,662			93,389			(12,791		)	495,260
Depreciation and amortization	133,447			61,126			14,537			209,110
Operating income (loss)	188,090			91,641			(1,746		)	277,985
Interest income	10,173			—			12,120			22,293
Other income (deductions)	22,066			3,202			(1,739		)	23,529
Interest charges	(87,469		)	(29,335		)	(11,829		)	(128,633		)
Segment earnings (loss) before income taxes	132,860			65,508			(3,194		)	195,174
Income taxes (benefit)	40,922			23,836			(1,480		)	63,278
Segment earnings (loss)	91,938			41,672			(1,714		)	131,896
Valencia non-controlling interest	(14,519		)	—			—			(14,519		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	76,891		$	41,672		$	(1,714	)	$	116,849

At December 31, 2016:
Total Assets	$	4,867,546		$	1,383,223		$	220,311		$	6,471,080
Goodwill	$	51,632		$	226,665		$	—		$	278,297



2015	PNM			TNMP			Corporate and Other			Consolidated

Electric operating revenues	$	1,131,195		$	307,887		$	—		$	1,439,082
Cost of energy	391,131			73,518			—			464,649
Utility 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, 2016, 2015 and 2014



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
Utility 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

Major Customers

No individual customer accounted for more than 10% of the electric operating revenues of PNMR or PNM. Three REPs accounted for more than 10% of the electric operating revenues of TNMP, as follows:



	Year Ended December 31,
	2016		2015		2014
REP A	16	%	16	%	15	%
REP B	11	%	13	%	15	%
REP C	11	%	11	%	11	%


(3)	Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP, as is PNMR Services Company, a wholly-owned subsidiary of PNMR that 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.

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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, 2016, 2015 and 2014

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,
	2016		2015		2014
			(In thousands)
Services billings:
PNMR to PNM	$	94,606	$	90,827	$	86,871
PNMR to TNMP	28,907		28,109		28,349
PNM to TNMP	427		554		524
TNMP to PNMR	66		41		31
Income tax sharing payments:
PNMR to TNMP	—		—		—
PNMR to PNM	—		1,450		—
TNMP to PNMR	—		—		—
Interest payments:
PNM to PNMR	11		54		65
PNMR to PNM	150		110		102
TNMP to PNMR	132		276		309


(4)	Regulatory Assets and Liabilities

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



	PNM				TNMP
	December 31,				December 31,
	2016		2015		2016		2015
Assets:	(In thousands)
Current:
FPPAC	$	1,451	$	—	$	—	$	—
Energy efficiency costs	1,991		—		413		629
Other	—		—		—		441
	3,442		—		413		1,070
Non-Current:
CTC, including carrying charges	—		—		36,328		46,147
Coal mine reclamation costs	22,383		28,303		—		—
Deferred income taxes	62,918		66,990		9,932		10,244
Loss on reacquired debt	24,404		23,627		34,107		35,405
Pension and OPEB	249,286		218,743		27,661		23,356
AMS surcharge	—		—		14,669		1,673
AMS retirement costs	—		—		11,086		8,549
Other	6,422		5,247		2,027		2,380
	365,413		342,910		135,810		127,754
Total regulatory assets	$	368,855	$	342,910	$	136,223	$	128,824

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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, 2016, 2015 and 2014



	PNM						TNMP
	December 31,						December 31,
	2016			2015			2016			2015
Liabilities:	(In thousands)
Current:
FPPAC	$	—		$	(11,410	)	$	—		$	—
Renewable energy rider	(3,411		)	(2,584		)	—			—
Other	(106		)	(1,597		)	(92		)	—
	(3,517		)	(15,591		)	(92		)	—
Non-Current:
Cost of removal	(297,087		)	(284,015		)	(26,900		)	(26,859		)
Deferred income taxes	(62,920		)	(77,502		)	(2,644		)	(3,283		)
PVNGS ARO	(30,621		)	(33,747		)	—			—
Renewable energy tax benefits	(22,540		)	(23,697		)	—			—
Nuclear spent fuel reimbursements	(8,875		)	(9,214		)	—			—
Pension and OPEB	—			—			(1,955		)	(1,913		)
Other	(1,658		)	(6,688		)	(449		)	(495		)
	(423,701		)	(434,863		)	(31,948		)	(32,550		)
Total regulatory liabilities	$	(427,218	)	$	(450,454	)	$	(32,040	)	$	(32,550	)

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 PVNGS ARO (to be determined in a future regulatory proceeding). In addition, TNMP does not currently receive a return on substantially all of its loss on reacquired debt (through 2043).

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

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


(5)	Stockholders’ Equity

Common Stock and Equity Contributions

PNMR, PNM, and TNMP did not issue any common stock during the three year period ended December 31, 2016. PNMR funded cash equity contributions to PNM of $28.1 million and $175.0 million in 2016 and 2015 and $50.0 million to TNMP in 2016. 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.

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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, 2016, 2015 and 2014

PNM declared and paid cash dividends to PNMR of $4.1 million, $94.4 million, and $30.3 million in 2016, 2015, and 2014. TNMP paid cash dividends to PNMR of $31.8 million, $33.2 million, and $16.3 million in 2016, 2015, and 2014.

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, without prior NMPRC approval, from current earnings, which is determined on a rolling four quarter basis, or from equity contributions previously made by PNMR. 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. 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, 2016, none of the numerical tests would restrict the payment of dividends from the retained earnings of PNMR, PNM, or TNMP.

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

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, which requires the maintenance of debt-to-capital ratios of less than or equal to 65%, 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

At January 1, 2014, PNMR had outstanding a one-year $100.0 million Term Loan Agreement (as amended and restated, the “PNMR Term Loan Agreement”) due in December 2014. In December 2014 and again in December 2015, PNMR entered into agreements each of which amended and restated the PNMR Term Loan Agreement and extended the maturity date for an additional year. The December 2015 amendment also increased the amount outstanding to $150.0 million. The PNMR Term Loan Agreement was repaid on 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 1.55% at December 31, 2016, and must be repaid on or before March 9, 2018.

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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, 2016, 2015 and 2014

In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 1.927%, subject to change if there is a change in PNMR’s credit rating, 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 loss of less than $0.1 million and a fair value gain of $0.1 million at December 31, 2016 and 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.

At January 1, 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”) with BTMU, as lender and 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, which aggregated 3.64% at December 31, 2016. PNMR, as parent company of NM Capital, has guaranteed NM Capital’s obligations to BTMU. The BTMU Term Loan Agreement and the guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio of 65%, 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 (the “Westmoreland Loan”) 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. The BTMU Term Loan Agreement provides that the amount outstanding thereunder must be reduced by at least $5.0 million quarterly beginning on November 1, 2016. NM Capital is also required to utilize the net proceeds of all amounts received under the Westmoreland Loan, after income taxes and fees, to make principal and interest payments on the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $92.2 million at December 31, 2016 and $82.8 million at February 21, 2017. Based on scheduled payments on the Westmoreland Loan, NM Capital estimates it will make principal payments of $42.0 million on the BTMU Term Loan Agreement in the twelve months ended December 31, 2017, including $9.4 million paid on February 1, 2017.

On December 21, 2016, PNMR entered into two term loan agreements: (1) a $100.0 million term loan agreement (“PNMR 2016 One-Year Term Loan”) among PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as administrative agent, that matures on December 21, 2017; and (2) a $100.0 million term loan agreement (“PNMR 2016 Two-Year Term Loan”) among PNMR and JPMorgan Chase Bank, N.A., as lender and administrative agent, that matures on December 21, 2018. The proceeds of the term loans were used to repay the $150.0 million PNMR Term Loan Agreement and to reduce borrowings under the PNMR Revolving Credit Facility. The PNMR 2016 One-Year Term Loan and the PNMR 2016 Two-Year Term Loan bear interest at variable rates, which were 1.60% and 1.69% at December 31, 2016.

PNM

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 a $75.0 million term loan 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 $125.0 million multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as lender and administrative agent, that had 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. The PNM Multi-draw Term Loan was repaid on May 20, 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, 2016, 2015 and 2014

At January 1, 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.

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 May 20, 2016, PNM entered into a $175.0 million term loan agreement (the “PNM 2016 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent. The PNM 2016 Term Loan Agreement bears interest at a variable rate, which was 1.36% at December 31, 2016, and has a maturity date of November 17, 2017. PNM used a portion of the proceeds of the PNM 2016 Term Loan Agreement to prepay without penalty the $125.0 million outstanding under the PNM Multi-draw Term Loan, which had a scheduled maturity of June 21, 2016.

On September 27, 2016, PNM participated in the issuance and sale of an aggregate of $146.0 million of PCRBs by the City of Farmington, New Mexico. The proceeds from the sale were utilized to refund an aggregate of $146.0 million of outstanding PCRBs previously issued by the City of Farmington. The arrangements governing the PCRBs result in PNM reflecting the bonds as debt on its financial statements. The PCRBs issued consist of the 2016 Series A in the aggregate principal amount of $46.0 million and the 2016 Series B in the aggregate principal amount of $100.0 million. Both series bear interest at a rate of 1.875% for the period from September 27, 2016 through September 30, 2021, have a mandatory tender for remarketing on October 1, 2021, and a final maturity on April 1, 2033.

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 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.

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, 2016 and 2015, TNMP had outstanding borrowings of $4.6 million and $11.8 million from PNMR. At February 21, 2017, TNMP had borrowings of $7.4 million from PNMR. PNM had no outstanding borrowings from PNMR at December 31, 2016 or February 21, 2017.

Short-term Debt

Currently, 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 November 2016, PNMR and PNM entered into agreements to extend the maturity of both facilities from October 31, 2020 to October 31, 2021. However, one lender, whose current commitment is $10.0 million under the PNMR Revolving Credit Facility and $40.0 million under the PNM Revolving Credit Facility, did not agree to extend its commitment beyond October 31, 2020. Unless one or more of the other current lenders or a new lender assumes the

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

commitments of the non-extending lender, the financing capacities will be reduced to $290.0 million for the PNMR Revolving Credit Facility and $360.0 million for the PNM Revolving Credit Facility from November 1, 2020 through October 31, 2021. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility, which is secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds and 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, 2016, interest rates on outstanding borrowings were 1.98% for the PNMR Revolving Credit Facility, 1.82% for the PNM Revolving Credit Facility, and 1.81% for the PNM New Mexico Credit Facility. The TNMP Revolving Credit Facility had no borrowings outstanding at December 31, 2016. Short-term debt outstanding consists of:



	December 31,
Short-term Debt	2016		2015
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	35,000	$	—
PNM New Mexico Credit Facility	26,000		—
	61,000		—
TNMP Revolving Credit Facility	—		59,000
PNMR:
PNMR Revolving Credit Facility	126,100		41,600
PNMR Term Loan Agreement	—		150,000
PNMR 2016 One-Year Term Loan	$	100,000
	$	287,100	$	250,600

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.2 million, $2.5 million, and $0.1 million at December 31, 2016 that reduce the available capacity under their respective revolving credit facilities. In addition, PNMR had $30.3 million of letters of credit outstanding under the JPM LOC Facility.

At February 21, 2017, PNMR, PNM, and TNMP had $149.5 million, $366.2 million, and $66.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $25.0 million availability under the PNM New Mexico Credit Facility. Total availability at February 21, 2017, on a consolidated basis, was $607.6 million for PNMR. At February 21, 2017, PNMR had invested cash of $1.5 million. PNM and TNMP had no invested cash at February 21, 2017.

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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, 2016, 2015 and 2014

Long-Term Debt

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



	December 31, 2016					December 31, 2015
	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
1.875% due 2033, mandatory tender at October 1, 2021	146,000		1,807			—		—
6.25% due 2038	36,000		239			36,000		251
4.75% due 2040, mandatory tender at June 1, 2017	37,000		25			37,000		82
5.20% due 2040, mandatory tender at June 1, 2020	40,045		147			40,045		190
5.90% due 2040	255,000		2,131			255,000		2,222
6.25% due 2040	11,500		96			11,500		100
2.54% due 2042, mandatory tender at June 1, 2017	20,000		67			20,000		199
2.40% due 2043, mandatory tender at June 1, 2020	39,300		340			39,300		456
5.20% due 2043, mandatory tender at June 1, 2020	21,000		75			21,000		96
Senior Unsecured Notes:
7.95% due 2018	350,000		995			350,000		1,718
7.50% due 2018	100,025		197			100,025		320
5.35% due 2021	160,000		780			160,000		943
3.85% due 2025	250,000		2,574			250,000		2,874
PNM Multi-draw Term Loan due 2016	—		—			125,000		21
PNM 2016 Term Loan Agreement due 2017	175,000		28			—		—
	1,640,870		9,501			1,590,870		10,193
Less current maturities	232,000		120			125,000		21
	1,408,870		9,381			1,465,870		10,172
TNMP Debt
First Mortgage Bonds:
9.50% due 2019, Series 2009A	172,302		1,857			172,302		2,682
6.95% due 2043, Series 2013A	93,198		(18,773		)	93,198		(19,490		)
4.03% due 2024, Series 2014A	80,000		792			80,000		897
3.53% due 2026, Series 2016A	60,000		749			—		—
	405,500		(15,375		)	345,500		(15,911		)
Less current maturities	—		—			—		—
	405,500		(15,375		)	345,500		(15,911		)
PNMR Debt
PNMR 2015 Term Loan Agreement due 2018	150,000		84			150,000		140
BTMU Term Loan Agreement	92,207		1,634			—		—
PNMR 2016 Two-Year Term Loan due 2018	100,000		21			—		—
	342,207		1,739			150,000		140
Less current maturities	42,025		557			—		—
	300,182		1,182			150,000		140
Total Consolidated PNMR Debt	2,388,577		(4,135		)	2,086,370		(5,578		)
Less current maturities	274,025		677			125,000		21
	$	2,114,552	$	(4,812	)	$	1,961,370	$	(5,599	)

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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, 2016, 2015 and 2014

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



	PNMR		PNM		TNMP		PNMR Consolidated
	(In thousands)
2017	$	42,025	$	232,000	$	—	$	274,025
2018	257,700		450,025		—		707,725
2019	12,310		—		172,302		184,612
2020	25,900		100,345		—		126,245
2021	4,272		306,000		—		310,272
Thereafter	—		552,500		233,198		785,698
Total	$	342,207	$	1,640,870	$	405,500	$	2,388,577


(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. See New Accounting Pronouncements in Note 1.

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 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 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, which are included in the table of future lease payments shown below.

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. See Note 17 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case.

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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, 2016, 2015 and 2014

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 owner participants, and take title to the leased interests. Exercise of renewal options under the leases required that amounts payable to the owner 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, 2016, amounts due to the owner participants would be up to approximately $176.1 million on January 15, 2017 in addition to the scheduled lease payments due on January 15, 2017. In such event, PNM would record the acquired assets at the lower of their fair value or the amount paid.

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)
2016	$	51,938	$	47,349	$	3,748
2015	$	68,652	$	63,558	$	3,688
2014	$	82,756	$	76,745	$	3,932

Future minimum operating lease payments at December 31, 2016 are shown below:



	PNMR		PNM		TNMP
	(In thousands)
2017	$	27,873	$	26,497	$	1,104
2018	25,809		25,262		267
2019	25,059		24,958		—
2020	25,044		24,958		—
2021	24,958		24,958		—
Later years	84,462		84,462		—
Total minimum lease payments	$	213,205	$	211,095	$	1,371


(8)	Fair Value of Derivative and Other Financial Instruments

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

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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, 2016, 2015 and 2014

liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, swaps, 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 wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its wholesale customers not covered under a FPPAC. However, as discussed below, PNM has hedging arrangements for the output of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers. 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, 2016, 2015, and 2014, 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.

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,
	2016			2015
	(In thousands)
PNMR and PNM
Current assets	$	5,224		$	3,813
Deferred charges	—			2,622
	5,224			6,435
Current liabilities	(2,339		)	(1,859		)
Net	$	2,885		$	4,576

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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, 2016, 2015 and 2014

Included in the above table are $2.7 million of current assets at December 31, 2016 and $3.0 million of current assets and $2.6 million of deferred charges at December 31, 2015 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, 2016 and 2015.

At December 31, 2016 and 2015, PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at December 31, 2016 and 2015, amounts posted as cash collateral under margin arrangements were $2.6 million and $2.7 million for both PNMR and PNM. At December 31, 2016 and 2015, obligations to return cash collateral were $0.1 million and $0.1 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 $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 and $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.

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,
	2016			2015			2014
	(In thousands)
PNMR and PNM
Electric operating revenues	$	(53	)	$	7,156		$	4,491
Cost of energy	(1,208		)	(293		)	593
Total gain	$	(1,261	)	$	6,863		$	5,084

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
PNMR and PNM
December 31, 2016	254,100	(2,471,600	)
December 31, 2015	577,481	(3,405,843	)

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

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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, 2016, 2015 and 2014

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)
PNMR and PNM
December 31, 2016	$	—	$	—	$	—
December 31, 2015	$	839	$	—	$	839

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. PVNGS Unit 3 will be included as a jurisdictional resource to serve New Mexico retail customers beginning on January 1, 2018. As of December 31, 2016, PNM had contracted to sell 100% 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 the sales through 2017, which average approximately $29 per MWh.

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 trusts for PNM’s share of final reclamation costs related to the coal mines serving SJGS and Four Corners (Note 16). At December 31, 2016 and 2015, the fair value of available-for-sale securities included $253.9 million and $249.1 million for the NDT and $19.1 million and $9.9 million for the mine reclamation trusts. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.



	December 31, 2016				December 31, 2015
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	23,683	$	—	$	10,700
Equity securities:
Domestic value	1,135		34,796		11,610		44,505
Domestic growth	3,032		47,595		11,163		61,078
International and other	2,029		27,481		1,569		27,961
Fixed income securities:
U.S. Government	115		40,962		178		27,880
Municipals	585		43,789		3,672		58,576
Corporate and other	553		54,671		628		28,342
	$	7,449	$	272,977	$	28,820	$	259,042

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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, 2016, 2015 and 2014

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 $(1.2) million, $(4.3) million, and $(0.7) million for the years ended December 31, 2016, 2015 and 2014.



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Proceeds from sales	$	522,601		$	252,174		$	117,989
Gross realized gains	$	46,116		$	29,663		$	15,162
Gross realized (losses)	$	(25,430	)	$	(9,259	)	$	(3,964	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. At December 31, 2016, held-to-maturity securities consist of the Westmoreland Loan.

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

At December 31, 2016, 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
	(In thousands)
Within 1 year	$	4,291	$	—
After 1 year through 5 years	35,884		100,893
After 5 years through 10 years	52,651		—
After 10 years through 15 years	5,617		—
After 15 years through 20 years	6,924		—
After 20 years	34,055		—
	$	139,422	$	100,893

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, 2016 and 2015.

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.

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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, 2016, 2015 and 2014

The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, including the Westmoreland Loan, 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, 2016 and 2015 for items recorded at fair value.



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
PNMR and PNM				(In thousands)
December 31, 2016
Available-for-sale securities
Cash and cash equivalents	$	23,683		$	23,683	$	—
Equity securities:
Domestic value	34,796			34,796		—
Domestic growth	47,595			47,595		—
International and other	27,481			27,481		—
Fixed income securities:
U.S. Government	40,962			39,723		1,239
Municipals	43,789			—		43,789
Corporate and other	54,671			23,158		31,513
	$	272,977		$	196,436	$	76,541

Commodity derivative assets	$	5,224		$	—	$	5,224
Commodity derivative liabilities	(2,339		)	—		(2,339		)
Net	$	2,885		$	—	$	2,885



December 31, 2015
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

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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, 2016, 2015 and 2014

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



					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2016	(In thousands)
PNMR
Long-term debt	$	2,392,712	$	2,540,693	$	—	$	2,540,693	$	—
Westmoreland Loan	$	95,000	$	100,893	$	—	$	—	$	100,893
Other investments	$	547	$	1,164	$	547	$	—	$	617
PNM
Long-term debt	$	1,631,369	$	1,730,157	$	—	$	1,730,157	$	—
Other investments	$	316	$	316	$	316	$	—	$	—
TNMP
Long-term debt	$	420,875	$	468,329	$	—	$	468,329	$	—
Other investments	$	231	$	231	$	231	$	—	$	—

December 31, 2015
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	$	—	$	—

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 (Note 12), 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.

GAAP provides a practical expedient 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. Under GAAP, investments for which fair value is measured using that practical expedient are not required to be categorized within the fair value hierarchy. 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

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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, 2016, 2015 and 2014

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:



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2016			(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	467,965	$	129,624	$	337,989	$	352
Uncategorized investments	75,685
Total Master Trust Investments	$	543,650

TNMP Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	50,901	$	14,447	$	36,416	$	38
Uncategorized investments	9,729
Total Master Trust Investments	$	60,630

PNM OPEB Plan
Cash and cash equivalents	$	2,567	$	2,567	$	—	$	—
Equity securities:
International funds	9,300		—		9,300		—
Domestic value	10,260		10,260		—		—
Domestic growth	6,338		6,338		—		—
Other funds	26,405		—		26,405		—
Fixed income securities:
Mutual funds	18,959		18,959		—		—
	$	73,829	$	38,124	$	35,705	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	308	$	308	$	—	$	—
Equity securities:
International funds	1,279		—		1,279		—
Domestic value	449		449		—		—
Domestic growth	1,089		1,089		—		—
Other funds	3,060		—		3,060		—
Fixed income securities:
Mutual funds	2,593		2,593		—		—
	$	8,778	$	4,439	$	4,339	$	—

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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, 2016, 2015 and 2014



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Markets 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, 2016, 2015 and 2014

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



			GAAP Fair Value Hierarchy
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2016	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	20,503	$	20,503	$	—	$	—
Equity securities:
International	38,401		—		38,401		—
Domestic value	36,036		36,036		—		—
Domestic growth	18,484		18,484		—		—
Other funds	27,532		—		27,532		—
Fixed income securities:
Corporate	205,419		—		205,029		390
U.S. Government	94,359		69,048		25,311		—
Municipals	13,970		—		13,970		—
Other funds	64,162		—		64,162		—
Total investments categorized within fair value hierarchy	518,866		$	144,071	$	374,405	$	390
Uncategorized investments:
Private equity funds	27,060
Hedge funds	42,070
Real estate funds	16,284
	$	604,280
December 31, 2015
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

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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, 2016, 2015 and 2014

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, 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
Actual return on assets sold during the period	1			—			1
Actual return on assets still held at period end	19			2			21
Purchases	—			—			—
Sales	(387		)	(42		)	(429		)
Balance at December 31, 2016	$	352		$	38		$	390


(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 VIE.

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, 2016, 2015, and 2014, PNM paid $19.3 million, $19.2 million, and $19.1 million for fixed charges and $1.1 million, $1.6 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 VIE 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

Summarized financial information for Valencia is as follows:



Results of Operations
	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Operating revenues	$	20,371		$	20,687		$	20,247
Operating expenses	(5,852		)	(5,777		)	(6,120		)
Earnings attributable to non-controlling interest	$	14,519		$	14,910		$	14,127



Financial Position
	December 31,
	2016		2015
	(In thousands)
Current assets	$	2,551	$	2,588
Net property, plant and equipment	66,947		69,784
Total assets	69,498		72,372
Current liabilities	578		965
Owners’ equity – non-controlling interest	$	68,920	$	71,407

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the VIE. 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. The parties engaged in periodic discussions concerning the terms of the proposed purchase, but ultimately were unable to reach agreement.

Westmoreland San Juan LLC (“WSJ”) and SJCC

As discussed in the subheading Coal Supply in Note 16, PNM purchases coal for SJGS from SJCC under a coal supply agreement (“CSA”). That section includes information on the purchase of SJCC by WSJ on January 31, 2016, as well as a $125.0 million loan (the “Westmoreland Loan”) from NM Capital, a subsidiary of PNMR, to WSJ, which loan provided substantially all of the funds required for the SJCC purchase, and the issuance of $30.3 million in letters of credit to facilitate the issuance of reclamation bonds required in order for SJCC to mine coal to be supplied to SJGS. The Westmoreland Loan and the letters of credit support result in PNMR being considered to have a variable interest in WSJ, including its subsidiary, SJCC, since PNMR and NM Capital could be subject to loss in the event WSJ were to default under the Westmoreland Loan and/or performance under the letter of credit support was required. Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 1, 2016.

At December 31, 2016, the amount outstanding under the Westmoreland Loan was $95.0 million and is reflected on the Consolidated Balance Sheet net of unamortized fees. In addition, interest receivable of $1.3 million is included in Other receivables. The Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

reserves, be utilized for principal and interest payments under the loan until it is fully repaid. As of February 21, 2017, the amount outstanding under the Westmoreland Loan was $85.4 million, reflecting the February 1, 2017 scheduled principal payment of $9.6 million. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC. In the event of a default by WSJ, NM Capital would have the ability to take over the mining operations. In such event, NM Capital would likely engage a third-party mining company to operate SJCC so that operations of the mine are not disrupted. Since the acquisition of SJCC by WSJ for approximately $125.0 million is a recently negotiated, arms-length transaction between Westmoreland and BHP, that amount should approximate the fair value of SJCC. Therefore, if WSJ were to default, NM Capital should be able to acquire assets of approximately the value of the Westmoreland Loan without a significant loss. Furthermore, PNMR considers the possibility of loss under the letters of credit support to be remote since the purpose of posting the bonds is to provide assurance that SJCC performs the required reclamation of the mine site in accordance with applicable regulations and all reclamation costs are reimbursable under the CSA. Also, much of the mine reclamation activities will not be performed for many years in the future, including after the expiration of the CSA and the final maturity of the Westmoreland Loan. In addition, each of the SJGS participants has established, and funds, a trust to meet its future reclamation obligations.

Both WSJ and SJCC are considered to be VIEs. PNMR’s analysis of these arrangements concluded that Westmoreland, as the parent of WSJ, has the ability to direct the SJCC mining operations, which is the factor that most significantly impacts the economic performance of WSJ and SJCC. NM Capital’s rights under the Westmoreland Loan are the typical protective rights of a lender, but do not give NM Capital any oversight over mining operations unless there is a default under the loan. Other than PNM being able to ensure that coal is supplied in adequate quantities and of sufficient quality to provide the fuel necessary to operate SJGS in a normal manner, the mining operations are solely under the control of Westmoreland and its subsidiaries, including developing mining plans, hiring of personnel, and incurring operating and maintenance expenses. Neither PNMR nor PNM has any ability to direct or influence the mining operation. Therefore, PNM’s involvement through the CSA is a protective right rather than a participating right and Westmoreland has the power to direct the activities that most significantly impact the economic performance of the SJCC. The CSA requires SJCC to deliver coal required to fuel SJGS in exchange for payment of a set price per ton, which is escalated over time for inflation. If SJCC is able to mine more efficiently than anticipated, its economic performance will be improved. Conversely, if SJCC cannot mine as efficiently as anticipated, its economic performance will be negatively impacted. Accordingly, PNMR believes Westmoreland is the primary beneficiary of WSJ and, therefore, WSJ and SJCC are not consolidated by either PNMR or PNM. The amounts outstanding under the Westmoreland Loan and the letter of credit support constitute PNMR’s maximum exposure to loss from the VIEs.

PVNGS Leases

PNM leased portions of its interests in Units 1 and 2 of PVNGS under leases, 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. See Note 7 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. 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. 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. See Note 17 for information concerning the NMPRC’s treatment of the purchased assets and extended leases in PNM’s NM 2015 Rate Case. 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 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 $8.3 million and $18.4 million at December 31, 2016 and 2015, which are included in other current liabilities on the Consolidated Balance Sheets.

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 evaluated the PVNGS lease arrangements, including actions taken with respect to the renewal and purchase options, and concluded that it did not have the power to direct the activities that most significantly impacted the economic performance of the trusts and, therefore, was not the primary beneficiary of the trusts under GAAP. The significant factors considered in reaching

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

this conclusion were: the periods covered by fixed price renewal options were significantly shorter than the anticipated remaining useful lives of the assets since the operating licenses for the plants were extended for 20 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. 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, 2016, 2015 and 2014


(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,
	2016		2015		2014
	(In thousands, except per share amounts)
Earnings Attributable to PNMR	$	116,849	$	15,640	$	116,254
Average Number of Common Shares:
Outstanding during year	79,654		79,654		79,654
Vested awards of restricted stock	104		105		134
Average Shares – Basic	79,758		79,759		79,788
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	374		380		491
Average Shares – Diluted	80,132		80,139		80,279
Net Earnings Per Share of Common Stock:
Basic	$	1.47	$	0.20	$	1.46
Diluted	$	1.46	$	0.20	$	1.45
Dividends Declared per Common Share	$	0.9025	$	0.8200	$	0.7550


(11)	Income Taxes

PNMR

PNMR’s income taxes consist of the following components:



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current federal income tax	$	—		$	—		$	(2,015	)
Current state income tax	(527		)	(1,376		)	(728		)
Deferred federal income tax	60,892			5,488			59,814
Deferred state income tax	3,886			12,305			14,831
Amortization of accumulated investment tax credits	(973		)	(1,342		)	(2,164		)
Total income taxes	$	63,278		$	15,075		$	69,738

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

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,
	2016			2015			2014
	(In thousands)
Federal income tax at statutory rates	$	68,311		$	16,154		$	70,226
Amortization of accumulated investment tax credits	(973		)	(1,342		)	(2,164		)
Flow-through of depreciation items	1,227			1,485			1,344
Earnings attributable to non-controlling interest in Valencia	(5,082		)	(5,218		)	(4,945		)
State income tax, net of federal benefit	4,537			(1,781		)	5,723
Impairment of state net operating loss carryforwards	(311		)	5,278			3,129
Impairment of state production tax credits	—			3,092			894
Allowance for equity funds used during construction	(1,732		)	(3,650		)	(1,947		)
Reversal of deferred items related to BART at SJGS	—			1,826			—
Impairment of charitable contribution carryforward	—			2,042			—
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(1,877		)	—			—
Other	(822		)	(2,811		)	(2,522		)
Total income taxes	$	63,278		$	15,075		$	69,738
Effective tax rate	32.42		%	32.66		%	34.76		%

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



	December 31,
	2016			2015
	(In thousands)
Deferred tax assets:
Net operating loss	$	160,901		$	161,691
Regulatory liabilities related to income taxes	64,657			80,031
Federal tax credit carryforwards	78,675			77,417
Shutdown of SJGS Units 2 and 3	53,434			53,823
Other	75,805			70,749
Total deferred tax assets	433,472			443,711
Deferred tax liabilities:
Depreciation and plant related	(1,102,458		)	(1,027,047		)
Investment tax credit	(56,017		)	(56,589		)
Regulatory assets related to income taxes	(66,378		)	(71,054		)
CTC	(12,715		)	(16,151		)
Pension	(57,287		)	(65,226		)
Other	(79,267		)	(85,037		)
Total deferred tax liabilities	(1,374,122		)	(1,321,104		)
Net accumulated deferred income tax liabilities	$	(940,650	)	$	(877,393	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

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, 2016
	(In thousands)
Net change in deferred income tax liability per above table	$	63,257
Change in tax effects of income tax related regulatory assets and liabilities	(10,621		)
Tax effect of mark-to-market adjustments	8,379
Tax effect of excess pension liability	5,071
Adjustment for uncertain income tax positions	297
Reclassification of unrecognized tax benefits	(297		)
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(1,877		)
Other	(404		)
Deferred income taxes	$	63,805

PNM

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



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current federal income tax	$	(10,290	)	$	(7,934	)	$	(2,175	)
Current state income tax	(1,907		)	(1,988		)	(979		)
Deferred federal income tax	49,123			(6,827		)	45,890
Deferred state income tax	4,969			5,333			12,061
Amortization of accumulated investment tax credits	(973		)	(1,342		)	(2,164		)
Total income taxes (benefit)	$	40,922		$	(12,758	)	$	52,633

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

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:



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Federal income tax (benefit) at statutory rates	$	46,501		$	(4,579	)	$	53,930
Amortization of accumulated investment tax credits	(973		)	(1,342		)	(2,164		)
Flow-through of depreciation items	1,185			1,465			1,325
Earnings attributable to non-controlling interest in Valencia	(5,082		)	(5,218		)	(4,945		)
State income tax, net of federal benefit	3,921			(2,162		)	5,522
Impairment of state net operating loss carryforwards	(213		)	3,619			2,145
Allowance for equity funds used during construction	(1,457		)	(3,650		)	(1,947		)
Reversal of deferred items related to BART at SJGS	—			1,826			—
Reversal of deferred income taxes accrued at prior tax rates	(301		)	(737		)	(737		)
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(1,877		)	—			—
Other	(782		)	(1,980		)	(496		)
Total income taxes (benefit)	$	40,922		$	(12,758	)	$	52,633
Effective tax rate	30.80		%	97.52		%	34.16		%

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



	December 31,
	2016			2015
	(In thousands)
Deferred tax assets:
Net operating loss	$	117,922		$	116,693
Regulatory liabilities related to income taxes	60,940			75,889
Federal tax credit carryforwards	59,156			57,928
Shutdown of SJGS Units 2 and 3	53,434			53,823
Other	41,700			41,210
Total deferred tax assets	333,152			345,543
Deferred tax liabilities:
Depreciation and plant related	(891,578		)	(828,926		)
Investment tax credit	(56,017		)	(56,589		)
Regulatory assets related to income taxes	(56,577		)	(61,018		)
Pension	(50,134		)	(58,070		)
Other	(27,512		)	(37,324		)
Total deferred tax liabilities	(1,081,818		)	(1,041,927		)
Net accumulated deferred income tax liabilities	$	(748,666	)	$	(696,384	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

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, 2016
	(In thousands)

Net change in deferred income tax liability per above table	$	52,282
Change in tax effects of income tax related regulatory assets and liabilities	(10,510		)
Tax effect of mark-to-market adjustments	8,336
Tax effect of excess pension liability	5,071
Adjustment for uncertain income tax positions	297
Reclassification of unrecognized tax benefits	(297		)
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(1,877		)
Other	(183		)
Deferred income taxes	$	53,119

TNMP

TNMP’s income taxes consist of the following components:



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Current federal income tax	$	9,445		$	1,603		$	35
Current state income tax	1,729			1,639			1,939
Deferred federal income tax	12,690			20,904			20,577
Deferred state income tax	(28		)	(21		)	(28		)
Total income taxes	$	23,836		$	24,125		$	22,523

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,
	2016			2015			2014
	(In thousands)
Federal income tax at statutory rates	$	22,928		$	23,131		$	21,115
State income tax, net of federal benefit	1,132			1,065			1,257
Other	(224		)	(71		)	151
Total income taxes	$	23,836		$	24,125		$	22,523
Effective tax rate	36.39		%	36.50		%	37.33		%

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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, 2016, 2015 and 2014

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



	December 31,
	2016			2015
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	3,718		$	4,141
Other	6,016			6,702
Total deferred tax assets	9,734			10,843
Deferred tax liabilities:
Depreciation and plant related	(201,017		)	(189,322		)
CTC	(12,715		)	(16,151		)
Regulatory assets related to income taxes	(9,800		)	(10,036		)
Loss on reacquired debt	(11,937		)	(12,392		)
Other	(20,050		)	(15,733		)
Total deferred tax liabilities	(255,519		)	(243,634		)
Net accumulated deferred income tax liabilities	$	(245,785	)	$	(232,791	)

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, 2016
	(In thousands)
Net change in deferred income tax liability per above table	$	12,994
Change in tax effects of income tax related regulatory assets and liabilities	(111		)
Other	(221		)
Deferred income taxes	$	12,662

Other Disclosures

GAAP requires that the Company recognize only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the taxing authority. A reconciliation of unrecognized tax benefits (expenses) is as follows:



	PNMR			PNM			TNMP
	(In thousands)
Balance at December 31, 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			—
Additions based on tax positions related to 2016	242			242			—
Additions (reductions) for tax positions of prior years	55			55			—
Settlement payments	—			—			—
Balance at December 31, 2016	$	6,752		$	3,949		$	—

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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, 2016, 2015 and 2014

Included in the balance of unrecognized tax benefits at December 31, 2016 are $6.2 million and $3.4 million 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 2017.

In 2016, the Company undertook an analysis of interest income and interest expense applicable to federal income tax matters. The analysis encompassed the impacts of IRS examinations, amended income tax returns, and filings for carrybacks of tax matters to previous taxable years applicable to all years not closed under the IRS rules. As a result of this effort, PNMR received net refunds from the IRS of $6.5 million. Of the refunds, $2.1 million was recorded as a reduction of the net interest receivable and $5.1 million was recorded as interest income, which was partially offset by $0.7 million of interest expense. In addition, PNMR incurred $0.9 million in professional fees related to the analysis. Of the net pre-tax impacts aggregating $3.5 million, $2.6 million is reflected in the PNM segment, $0.3 million in the TNMP segment, and $0.6 million in the Corporate and Other segment.

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 Charges in the Consolidated Statements of Earnings. Interest income (expense) related to income taxes is as follows:



	PNMR		PNM		TNMP
	(In thousands)
2016	$	4,398	$	3,625	$	345
2015	$	—	$	—	$	—
2014	$	146	$	148	$	(2	)

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



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2016:
Accumulated accrued interest receivable	$	—		$	—		$	—
Accumulated accrued interest payable	$	—		$	—		$	—
December 31, 2015:
Accumulated accrued interest receivable	$	3,236		$	3,236		$	—
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 2013 are closed to examination by either federal or state taxing authorities other than Arizona. The tax years prior to 2012 are closed to examination by Arizona taxing authorities. Other tax years are open to examination by federal and state taxing authorities. At December 31, 2016, the Company has $420.1 million of federal net operating loss carryforwards that expire beginning in 2030 and $78.7 million of federal tax credit carryforwards that expire beginning in 2023. State net operating losses expire beginning in 2017 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. PNM’s NM 2016 Rate Case (Note 17) reflects that assumption. 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:

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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, 2016, 2015 and 2014



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2016:
Regulatory liability	$	(7,132	)	$	(7,132	)	$	—
Income tax expense	$	712		$	804		$	—
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	)	$	—

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 2014 through 2016 are as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2016:
State tax credit carryforwards	$	—		$	—		$	—
State net operating loss carryforwards	$	(311	)	$	(213	)	$	—
Charitable contribution carryforwards	$	—		$	—		$	—
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		$	—

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, 2016 and 2015 are as follows:



	PNMR		PNM		TNMP
	(In thousands)
December 31, 2016:
State tax credit carryforwards	$	3,986	$	—	$	—
State net operating loss carryforwards	$	361	$	248	$	—
Charitable contribution carryforwards	$	659	$	—	$	—
December 31, 2015:
State tax credit carryforwards	$	6,378	$	—	$	—
State net operating loss carryforwards	$	361	$	248	$	—
Charitable contribution carryforwards	$	659	$	—	$	—

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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, 2016, 2015 and 2014

The NMPRC’s order in the NM 2015 Rate Case (Note 17) approved PNM’s request to record a regulatory asset, which net of federal income taxes, amounts to $2.1 million, to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The regulatory asset is being recovered through rates over two years. The impact, net of amortization, is reflected as a reduction of income tax expense on the Consolidated Statement of Earnings.

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.


(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.

The Company maintains trust funds for the pension and OBEB plans from which benefits are paid to eligible employees and retirees. The Company’s funding policy is to make contributions to the trusts as determined by independent actuary and that comply with minimum guidelines of the Employee Retirement Income Security Act and the Internal Revenue Code. Information concerning the investments is contained in Note 8. 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

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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, 2016, 2015 and 2014

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.

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 pension 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,
	2016			2015			2016			2015
	(In thousands)
PBO at beginning of year	$	597,900		$	657,557		$	64,198		$	72,305
Service cost	—			—			—			—
Interest cost	30,307			28,255			3,304			3,043
Actuarial (gain) loss	39,463			(38,151		)	4,318			(5,157		)
Benefits paid	(45,919		)	(49,761		)	(4,759		)	(5,993		)
PBO at end of year	621,751			597,900			67,061			64,198
Fair value of plan assets at beginning of year	557,923			587,909			62,082			69,177
Actual return on plan assets	31,597			(10,225		)	3,301			(1,102		)
Employer contributions	—			30,000			—			—
Benefits paid	(45,919		)	(49,761		)	(4,759		)	(5,993		)
Fair value of plan assets at end of year	543,601			557,923			60,624			62,082
Funded status – asset (liability) for pension benefits	$	(78,150	)	$	(39,977	)	$	(6,437	)	$	(2,116	)

Actuarial (gain) loss results from changes in:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Discount rates	$	41,849		$	(45,918	)	$	5,055		$	(6,090	)
Demographic experience	(334		)	2,778			(556		)	877
Other assumption and experience	(2,052		)	4,989			(181		)	56
	$	39,463		$	(38,151	)	$	4,318		$	(5,157	)

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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, 2016, 2015 and 2014

The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2016.



	PNM Plan						TNMP Plan
	December 31, 2016						December 31, 2016
	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	$	(1,855	)	$	146,775		$	—
Experience (gain) loss	—			43,283			4,960
Regulatory asset (liability) adjustment	—			(25,104		)	(4,960		)
Amortization recognized in net periodic benefit cost (income)	405			(5,805		)	—
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(1,450	)	$	159,149		$	—
Amortization expected to be recognized in 2017	$	(405	)	$	6,320		$	—

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



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
PNM Plan
Service cost	$	—		$	—		$	—
Interest cost	30,307			28,255			30,163
Expected return on plan assets	(35,416		)	(39,323		)	(38,044		)
Amortization of net (gain) loss	13,820			14,820			13,020
Amortization of prior service cost	(965		)	(965		)	(965		)
Net periodic benefit cost	$	7,746		$	2,787		$	4,174
TNMP Plan
Service cost	$	—		$	—		$	—
Interest cost	3,304			3,043			3,193
Expected return on plan assets	(3,943		)	(4,420		)	(4,526		)
Amortization of net (gain) loss	700			782			665
Amortization of prior service cost	—			—			—
Net periodic benefit cost (income)	$	61		$	(595	)	$	(668	)

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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, 2016, 2015 and 2014

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	2016		2015		2014
Discount rate for determining December 31 PBO	4.51	%	5.29	%	4.48	%
Discount rate for determining net periodic benefit cost (income)	5.29	%	4.48	%	5.27	%
Expected return on plan assets	6.50	%	6.80	%	7.20	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.49	%	5.39	%	4.39	%
Discount rate for determining net periodic benefit cost (income)	5.39	%	4.39	%	5.06	%
Expected return on plan assets	6.50	%	6.80	%	7.20	%
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 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 2017 net periodic cost to increase $5.3 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 5.9% and 5.5% for the year ended December 31, 2016.

The Company’s long-term pension investment strategy is to invest in assets whose interest rate sensitivity is correlated with the pension liability. The Company has chosen to implement this strategy known as Liability Driven Investing (“LDI”) by increasing the liability matching investments as the funded status of the pension plans improves. These liability matching investments are currently fixed income securities. The pension plans current targeted asset allocation is 21% equities, 65% fixed income, and 14% alternative investments. Equity investments are primarily in domestic securities that include large, mid, and small capitalization companies. The pension plans have a 6% targeted allocation to equities of companies domiciled primarily in developed countries outside of the United States. This category includes actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries and government securities. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. The hedge funds and private equity funds are structured as multi-manager multi-strategy fund of funds to achieve a diversified position in these asset classes. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, buy-outs, and venture capital. The real estate investment is structured as an open-ended, commingled private real estate portfolio that invests in a diversified portfolio of assets including commercial property and multi-family housing. See Note 8 for fair value information concerning assets held by the pension plans.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

The following pension benefit payments are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2017	$	50,244	$	5,526
2018	48,398		5,728
2019	47,696		5,086
2020	46,879		5,042
2021	45,348		5,294
2022 – 2026	209,331		22,509

The Company does not expect to make any cash contributions to the pension plans in 2017-2021, 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 4.1% to 4.9%. 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.

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,
	2016			2015			2016			2015
	(In thousands)
APBO at beginning of year	$	84,674		$	95,175		$	13,106		$	14,070
Service cost	140			204			186			247
Interest cost	4,346			4,089			677			608
Participant contributions	2,690			2,439			520			320
Actuarial (gain) loss	17,877			(6,565		)	(96		)	(575		)
Benefits paid	(11,734		)	(10,668		)	(1,563		)	(1,564		)
Plan design changes	(3,724		)	—			—			—
APBO at end of year	94,269			84,674			12,830			13,106
Fair value of plan assets at beginning of year	72,952			78,175			9,111			10,094
Actual return on plan assets	5,923			(617		)	476			(82		)
Employer contributions	2,863			3,623			—			343
Participant contributions	2,690			2,439			520			320
Benefits paid	(11,734		)	(10,668		)	(1,563		)	(1,564		)
Fair value of plan assets at end of year	72,694			72,952			8,544			9,111
Funded status – asset (liability)	$	(21,575	)	$	(11,722	)	$	(4,286	)	$	(3,995	)

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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, 2016, 2015 and 2014

Actuarial (gain) loss results from changes in:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2016			2015			2016			2015
	(in thousands)
Discount rates	$	6,569		$	(7,345	)	$	1,112		$	(1,322	)
Claims, contributions, and demographic experience	19,562			780			(102		)	747
Assumed participation rate	(6,335		)	—			(1,013		)	—
Mortality rate	(691		)	—			(93		)	—
Medical benefits	(1,228		)	—			—			—
	$	17,877		$	(6,565	)	$	(96	)	$	(575	)

In the year ended December 31, 2016, actuarial losses of $17.4 million were recorded as adjustments to regulatory assets for the PNM Plan. For the TNMP Plan, actuarial gains 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,
	2016			2015			2014
	(In thousands)
PNM Plan
Service cost	$	140		$	204		$	181
Interest cost	4,346			4,089			4,630
Expected return on plan assets	(5,483		)	(5,610		)	(5,638		)
Amortization of net (gain) loss	1,145			1,966			2,225
Amortization of prior service credit	(30		)	(642		)	(1,343		)
Net periodic benefit cost	$	118		$	7		$	55
TNMP Plan
Service cost	$	186		$	247		$	237
Interest cost	677			608			619
Expected return on plan assets	(490		)	(520		)	(534		)
Amortization of net (gain) loss	(40		)	—			(122		)
Amortization of prior service cost	—			—			32
Net periodic benefit cost	$	333		$	335		$	232

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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, 2016, 2015 and 2014

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	2016		2015		2014
Discount rate for determining December 31 APBO	4.47	%	5.34	%	4.45	%
Discount rate for determining net periodic benefit cost	5.34	%	4.45	%	5.21	%
Expected return on plan assets	7.70	%	7.70	%	8.50	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 APBO	4.47	%	5.34	%	4.45	%
Discount rate for determining net periodic benefit cost	5.34	%	4.45	%	5.21	%
Expected return on plan assets	5.70	%	5.70	%	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. 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 2017 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 8.5% and 5.5% for the year ended December 31, 2016.

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



	PNM Plan
	December 31,
	2016		2015
Health care cost trend rate assumed for next year	6.8	%	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		2024

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	$	259	$	(226	)
Effect on APBO	$	1,575	$	(2,193	)

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.

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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, 2016, 2015 and 2014

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)
2017	$	8,425	$	803
2018	8,327		818
2019	8,092		827
2020	7,965		839
2021	7,792		859
2022 - 2026	33,891		4,466

PNM expects to make no cash contributions to the PNM postretirement benefit plan totaling for 2017-2021. TNMP expects to make contributions to the TNMP postretirement benefit plan totaling $0.4 million in 2017 and $1.4 million for 2018-2021.

Executive Retirement Programs

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



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2016			2015			2016			2015
	(In thousands)
PBO at beginning of year	$	16,105		$	17,730		$	794		$	878
Service cost	—			—			—			—
Interest cost	812			760			40			36
Actuarial (gain) loss	768			(908		)	47			(26		)
Benefits paid	(1,473		)	(1,477		)	(94		)	(94		)
PBO at end of year – funded status	16,212			16,105			787			794
Less current liability	1,510			1,519			93			93
Non-current liability	$	14,702		$	14,586		$	694		$	701

The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2016.



	December 31, 2016
	PNM Plan			TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,084		$	—
Experience (gain) loss	768			47
Regulatory asset (liability) adjustment	(445		)	(47		)
Amortization recognized in net periodic benefit cost (income)	(108		)	—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,299		$	—
Amortization expected to be recognized in 2017	$	132		$	—

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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, 2016, 2015 and 2014

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



	Year Ended December 31,
	2016		2015		2014
	(In thousands)
PNM Plan
Service cost	$	—	$	—	$	—
Interest cost	812		760		822
Amortization of net (gain) loss	256		325		210
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	1,068	$	1,085	$	1,032
TNMP Plan
Service cost	$	—	$	—	$	—
Interest cost	40		36		39
Amortization of net (gain) loss	2		5		—
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	42	$	41	$	39

The following significant weighted-average assumptions were used to determine the PBO and net periodic benefit cost. Should actual experience differ from actuarial assumptions, the PBO and net periodic benefit cost would be affected.



	Year Ended December 31,
PNM Plan	2016		2015		2014
Discount rate for determining December 31 PBO	4.51	%	5.29	%	4.48	%
Discount rate for determining net periodic benefit cost	5.29	%	4.48	%	5.27	%
Long-term rate of return on plan assets	N/A		N/A		N/A
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.49	%	5.39	%	4.39	%
Discount rate for determining net periodic benefit cost	5.39	%	4.39	%	5.06	%
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)
2017	$	1,510	$	93
2018	1,487		92
2019	1,459		89
2020	1,427		86
2021	1,391		83
2022 – 2026	6,228		341

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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, 2016, 2015 and 2014

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.

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



	Year Ended December 31,
	2016		2015		2014
	(In thousands)
PNMR
401(k) plan	$	17,762	$	16,725	$	16,703
Non-qualified plan	$	2,017	$	1,436	$	2,257
PNM
401(k) plan	$	13,397	$	12,679	$	12,745
Non-qualified plan	$	1,535	$	1,090	$	1,722
TNMP
401(k) plan	$	4,365	$	4,046	$	3,958
Non-qualified plan	$	482	$	346	$	535


(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 vesting period for awards of restricted stock to non-employee members of the Board in 2017 and thereafter will be one year. 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.

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

Accounting for Stock Awards

The stock-based compensation expense related to restricted stock awards without performance or market conditions to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for other such awards is amortized to compensation expense over the shorter of the requisite vesting period or the period until the participant becomes retirement eligible. 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.

Total compensation expense for stock-based payment arrangements recognized by PNMR for the years ended December 31, 2016, 2015, and 2014 was $5.6 million, $4.9 million, and $5.9 million. Stock compensation expense of $4.2 million, $3.6 million, and $4.2 million was charged to PNM and $1.5 million, $1.3 million, and $1.7 million was charged to TNMP. At December 31, 2016, PNMR had unrecognized compensation expense related to stock awards of $4.5 million, which are expected to be recognized over an average of 1.82 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. See New Accounting Pronouncements in Note 1.

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	2016			2015			2014
Expected quarterly dividends per share	$	0.2200		$	0.2000		$	0.1850
Risk-free interest rate	0.94		%	0.92		%	0.62		%

Market-Based Shares
Dividend yield	2.74		%	2.87		%	2.82		%
Expected volatility	20.44		%	18.73		%	25.11		%
Risk-free interest rate	0.97		%	1.00		%	0.64		%

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, 2015	245,094		$	24.81	569,342		$	19.35
Granted	190,276		$	26.49	—		$	—
Exercised	(216,340	)	$	23.47	(253,268	)	$	27.75
Forfeited	(714	)	$	29.54	(2,000	)	$	12.22
Expired	—		—		(8,200	)	$	24.85
Outstanding at December 31, 2016	218,316		$	27.59	305,874		$	12.29

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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, 2016, 2015 and 2014

PNMR’s stock-based compensation program provides for performance and market targets through 2018. Included as restricted stock granted and exercised in the above table are 79,619 previously awarded shares that were earned for the 2013 through 2015 performance measurement period and ratified 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%). Excluded from the above table are 49,682 previously awarded shares that were earned for the 2014 through 2016 performance measurement period and ratified by the Board in February 2017 (based upon achieving market targets at “target” levels, weighted at 60%, and not meeting performance targets, weighted at 40%), as well as maximums of 163,712 and 137,036 shares for the three-year performance periods ending in 2017 and 2018 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 ratified her receiving the 35,000 shares in February 2015. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the 100,000 shares in February 2017. The above table does not include the restricted stock shares issued in February 2017. The retention award was made under the PEP and was approved by the Board on February 28, 2012.

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. The specified market target was achieved at the end of 2016 and the Board ratified him receiving $100,000 of PNMR common stock in February 2017 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. The above table does not include any restricted stock shares under this retention award agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014.

In March 2015, the Company entered into an additional 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 above table does not include any restricted stock shares under this retention award agreement. The retention award was made under the PEP and was approved by the Board on February 26, 2015.

At December 31, 2016, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.7 million with a weighted-average remaining contract life of 2.04 years. At December 31, 2016, no outstanding stock options had an exercise price greater than the closing price of PNMR common stock on that date.

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	2016		2015		2014
Weighted-average grant date fair value	$	26.49	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	5,079	$	6,507	$	4,933

Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,242	$	2,350	$	2,473

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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, 2016, 2015 and 2014


(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 2022 for SJGS, July 2041 for Four Corners, December 2046 for Luna, and November 2047 for PVNGS.

PNM’s expenditures for additions to utility plant were $445.5 million in 2016, 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 $122.5 million during 2016. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $600.1 million in 2016.

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, 2016, PNM’s interests and investments in jointly-owned generating facilities are:



Station (Fuel Type)	Plant in Service		Accumulated Depreciation⁽¹⁾			Construction Work in Progress		Composite Interest
	(In thousands)
SJGS (Coal) ⁽²⁾	$	1,082,537	$	(445,597	)	$	4,406	46.30	%
PVNGS (Nuclear) ⁽³⁾	$	797,793	$	(334,887	)	$	38,946	10.20	%
Four Corners Units 4 and 5 (Coal)	$	188,026	$	(103,584	)	$	52,869	13.00	%
Luna (Gas)	$	69,678	$	(25,386	)	$	259	33.33	%


⁽¹⁾	Includes cost of removal.

⁽²⁾

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, 2016, PNM’s carrying value for its current ownership share of SJGS Units 2 and 3 included plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $203.9 million for a net undepreciated net book value of $267.9 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.


⁽³⁾	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. Currently, 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; and 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 December 31, 2017 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%

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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, 2016, 2015 and 2014

undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. See Note 7 for additional information concerning the PVNGS leases, including PNM’s purchase of the assets underlying certain of the leases at the expiration of the leases on January 15, 2016, and Note 17 for the NMPRC’s treatment of those purchases in the ratemaking process.

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. In April 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), an affiliate of APS, 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:



	2017		2018		2019		2020		2021		Total
					(In millions)
PNM	$	308.1	$	231.0	$	282.2	$	252.5	$	190.7	$	1,264.5
TNMP	151.0		134.3		137.1		136.2		126.2		684.8
Corporate and Other	58.2		29.7		15.3		15.2		15.4		133.8
Total PNMR	$	517.3	$	395.0	$	434.6	$	403.9	$	332.3	$	2,083.1

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The above construction expenditures include $44.2 million for environmental upgrades at Four Corners, $46.9 million for 30MW of new solar capacity to supply power to a new data center being constructed by Facebook Inc., and $43.7 million for a 40 MW gas-fired peaking generating facility to be completed in 2020.

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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, 2016, 2015 and 2014


(15)	Asset Retirement Obligations

AROs are recorded based on studies to estimate the amount and timing of future ARO expenditures and refect underlying assumptions, such as discount rates, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Any changes in these assumptions underlying the required calculations may require revisions to the estimated AROs when identified. A reconciliation of the ARO liability is as follows:



	PNMR			PNM			TNMP
	(In thousands)
Liability at December 31, 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⁽¹⁾	(170		)	(170		)	—
Liability at December 31, 2015	111,895			111,049			695
Liabilities incurred	—			—			—
Liabilities settled	(14		)	(14		)	—
Accretion expense	9,170			9,098			59
Revisions to estimated cash flows⁽²⁾	6,468			6,468			—
Liability at December 31, 2016	$	127,519		$	126,601		$	754

⁽¹⁾ PNM has an ARO for Four Corners that includes the 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.

⁽²⁾

PNM has an ARO for PVNGS that includes obligations for nuclear decommissioning of that facility. In 2016, a new decommissioning study for PVNGS was implemented reflecting updated cash flow estimates. The new study resulted in an increase of $6.1 million to the ARO. In addition, an adjustment for SJGS related to the 2015 decommissioning study was implemented in 2016, resulting in a $0.3 million increase to the ARO.


(16)	Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company 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

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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, or other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Commitments and Contingencies Related to the Environment

PVNGS Decommissioning Funding

PNM has a program for funding its share of decommissioning costs for PVNGS, including portions held under leases. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. PNM funded $4.2 million, $4.9 million, and $4.9 million for the years ended December 31, 2016, 2015, and 2014 into the qualified and non-qualified trust funds. The market value of the trusts at December 31, 2016 and 2015 was $253.9 million and $249.1 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 DC 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. In August 2014, 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 for costs incurred from January 2007 through June 2011, which amounted to $5.9 million, was recorded in the fourth quarter of 2014 and substantially all was credited back to PNM’s customers. In the first quarter of 2015, PNM recorded $4.3 million, including $3.1 million credited back to PNM’s customers, for its share of the settlement under this process for costs incurred from July 2011 through June 2014. 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, which would have terminated upon payment of costs incurred through December 31, 2016, has been extended to December 31, 2019.

PNM estimates that it will incur approximately $57.7 million (in 2016 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, 2016 and 2015, PNM had a liability for interim storage costs of $12.1 million and $12.2 million included in other deferred credits.

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.

On June 8, 2012, the DC 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

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had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The DC 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 DC 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 reviews for individual licenses. The NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the DC Circuit issued its June 2012 decision although PVNGS had not been involved in any licensing actions affected by that decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged, in the DC Circuit, 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. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval, as ordered by the DC Circuit. 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 Compliance – 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 SJGS was required to reduce NOx emissions by installing selective non-catalytic reduction technology (“SNCR”) as BART. Nevertheless, in August 2011, EPA published a FIP, which included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) as BART on all four units by September 21, 2016.

PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP, which resulted in a non-binding agreement that would include 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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(the “RSIP”). EPA issued final rules, which became effective on November 10, 2014, approving the RSIP and withdrawing the FIP.

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 ….”

Following issuance of the FIP, 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. 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 work. 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 $77.9 million. See Note 17 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. 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 have increased with the installation of SNCR and BDT equipment.

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 will reduce PNM’s ownership in SJGS by 340 MW, including a 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). On October 1, 2014, PNM and certain intervenors filed a stipulation with the NMPRC that would have settled all matters in PNM’s filing. On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommended the NMPRC reject the stipulation as proposed. 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”).

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

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Request for Stay in the NM Supreme Court requesting the four commissioners be recused from this case and that PNM’s application be dismissed. On October 9, 2015, the NM Supreme Court 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 NM Supreme Court 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 NM Supreme Court on November 9, 2015. On November 9, 2015, the NM Supreme Court denied NEE’s petition.

On December 16, 2015, following oral argument, the NMPRC issued an order adopting the Stipulated Settlement. As provided in that order:


•	PNM will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) by 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 is granted a CCN to acquire an additional 132 MW in SJGS Unit 4, with an initial book value of zero, plus the costs of SNCR and other capital additions


•	PNM is 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, (currently estimated to aggregate approximately $151 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 a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties to the stipulation agree to support this case being decided within six months (to facilitate the 2018 filing PNM is developing two resource portfolios in its 2017 IRP to be filed in July 2017, one with SJGS continuing beyond mid-2022 and one where it is shut down)


•	PNM is 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 is discussed in Note 17)


•	PNM will 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

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 (including cost of removal) 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 estimated the undepreciated net book value of SJGS Units 2 and 3 at December 31, 2017 would 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 dependent on the actual December 31, 2017 net undepreciated 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 and in Note 16, 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 is included in income tax expense.

During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million, including a $4.5 million expense related to a refinement

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of the estimated liability for coal mine reclamation resulting from the new coal mine reclamation arrangement, that is reflected in regulatory disallowances and restructuring costs on the Consolidated Statement of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Consolidated Statement of Earnings. At December 31, 2016, the carrying value for PNM’s current ownership share of SJGS Units 2 and 3 is comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $203.9 million for a net undepreciated book value of $267.9 million, offset by 50% (which equals $128.6 million) of the anticipated December 31, 2017 net undepreciated book value of SJGS Units 2 and 3 that will not be recovered, resulting in the net carrying value for SJGS Units 2 and 3 being $139.3 million at December 31, 2016.

On January 14, 2016, NEE filed a Notice of Appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. On July 22, 2016, NEE filed a brief alleging that the NMPRC’s decision violated New Mexico Statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious. Answer briefs refuting NEE’s claims were filed on November 2, 2016 by PNM, the NMPRC, and other intervenors. In addition, on February 5, 2016, NEE filed a motion for reconsideration with the NMPRC of that order based on developments related to the loan made by NM Capital to facilitate the sale of SJCC, which is described under Coal Supply below. NEE alleged 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. The NEE motion was denied by operation of law because the NMPRC did not act on the motion. On March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. The NMPRC has taken no action on this matter. PNM cannot currently predict the outcome of these matters.

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 requirements to install SNCR and BDT equipment at SJGS, 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 by December 31, 2017. One other participant also expressed a similar intent to exit ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. 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.

Following mediated negotiations, the SJGS participants executed the San Juan Project Restructuring Agreement (“RA”) on July 31, 2015. The RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants 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. PNMR Development became a party to the RA and agreed to acquire a 65 MW ownership interest in SJGS Unit 4 on the exit date, 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 exiting owners for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million. PNMR currently anticipates 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. As ordered by the NMPRC, PNM would treat the 65 MW as merchant utility plant that would be excluded from retail rates. Reflecting the additions of the 132 MW and 65 MW, PNM’s ownership share would be 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

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 acquired the coal

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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 provides economic benefits that are being 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. The SJPPA also obligates PNM to take reasonable and prudent actions necessary for the successful and proper operation of SJGS if the participants fail to approve the requested expenditures. 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, was not approved. PNM subsequently submitted several requests to the owners of Unit 4 for 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, subsequently issued several “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to comply with regulatory requirements and keep the Unit 4 SNCR project on schedule.

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.

PNM estimates its share of costs for post-combustion controls at Four Corners Units 4 and 5 to be up to $90.4 million, including amounts incurred through December 31, 2016 and PNM’s AFUDC. PNM is seeking recovery from its ratepayers of these costs in its NM 2016 Rate Case discussed in Note 17. PNM is unable to predict the ultimate outcome of this matter.

The Four Corners plant site is leased from the Navajo Nation. APS, on behalf of the Four Corners participants, negotiated amendments to the 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.

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

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jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016. The court granted APS’ motion to intervene in the litigation on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC’s tribal sovereign immunity. The court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss. PNM cannot predict the timing or outcome of this matter.

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 DC Circuit.

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and establishes deadlines for states to submit initial plans to EPA by September 6, 2016, with a potential two-year extension, and final plans by 2018. The September deadline has passed with no action and the 2018 deadline could be adjusted due to the stay of the Clean Power Plan issued by the US Supreme Court and pending litigation described below. 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.

On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan. On January 26, 2016, 29 states and state agencies filed a petition to the US Supreme Court to reverse the DC Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the US Supreme Court issued a 5-4 decision granting the stay pending judicial review of the rule. The US Supreme Court’s order 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 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 may still have six more months to prepare initial plans and 2.5 years for final plans. The DC Circuit heard oral arguments on September 27, 2016 in the case challenging the Clean Power Plan. A decision by the DC Circuit is not expected until sometime later in 2017. The stay will remain in effect pending US Supreme Court review if such review is sought.

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, 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.

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On June 30, 2016, EPA published in the Federal Register the design details of its voluntary Clean Energy Incentive Program under the Clean Power Plan. Comments were due to EPA on November 1, 2016.

PNM’s review of the new CO₂ emission reductions standards is ongoing and the assessment of its impacts will depend on the litigation of the final rule and actions the Trump administration may take through 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 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. On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicates that no area in New Mexico exceeds the 1-hour SO₂ standard. In July of each year, NMED will submit an annual report to EPA documenting annual SO₂emissions from SJGS and the associated compliance status.

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 for these constituents. 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.

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.

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 New

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Mexico and Arizona 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.

On February 25, 2016, EPA released guidance on area designations, which states used to determine their initial designation recommendations by October 1, 2016. EPA recommended that states and tribes use the three most recent years of quality assured monitoring data available (e.g., 2013 to 2015) to recommend designations. In their submittals, states and tribes were also able to use preliminary 2016 data. EPA is expected to release final designations of attainment/nonattainment for areas by October 1, 2017. By October 2018, NMED must submit an infrastructure SIP that provides the basic air quality management program to implement the revised ozone standard. Due dates for SIPs for areas that have been designated as non-attainment for ozone are generally due within 36 months from the date of designation and are expected to be submitted to EPA by October 1, 2020.

NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, NMED is designating only a small area in southern Dona Ana County as non-attainment for ozone. NMED will have responsibility for bringing this nonattainment area into compliance and will look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain nonattainment but would not face more stringent requirements over time”.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s nonattainment designation of the small area within Dona Ana County, but must wait on EPA’s ultimate approval, which should occur by October 1, 2017. 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.

Citizen Suit Under the Clean Air Act

The operations of SJGS were 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 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.

Achievement of mercury operational requirements was the final open issue under the consent decree, and on January 23, 2017, PNM, NMED, and the plaintiffs filed an agreed petition with the court for termination. In the petition, the parties advised the court that investments by PNM and the other SJGS owners in SO₂, particulate matter, NOx, and mercury pollution technologies at SJGS had significantly reduced emissions from the plant, improved air quality in the “four corners” region, and fulfilled the terms of the consent decree. The court granted the petition to terminate the consent decree the same day.

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 August 17, 2015, a consent decree was entered by the court, marking resolution to the litigation. The settlement requires installation of pollution control technology and implementation of other measures to reduce SO₂ and NOx emissions from Four Corners Units 4 and 5, although installation of much of this equipment was already planned in order to comply with EPA’s Regional Haze Rule BART requirements. The

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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. Under the terms of the consent decree, the current Four Corners co-owners are responsible for $3.5 million of the environmental mitigation project costs. 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. A former Four Corners co-owner is responsible for the $3.2 million balance of the environmental mitigation costs.

Navajo 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 took action to cure the defect in its permitting process identified by the court. NTEC, the owner of the mine, appealed to the Tenth Circuit. On December 29, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment with a finding of no new significant impact and reissued the permit. On March 30, 2016, the Tenth Circuit vacated and dismissed the appeal on mootness grounds due to OSM’s revised environmental assessment and re-approval of the permit at issue.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans; voiding, reversing, and remanding the various mining modification approvals; enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated; and enjoining operations at the seven mines. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. In February 2016, venue for this matter was transferred to the United States District Court for the Western District of Texas. A stay in this matter expired on April 1, 2016 and was not renewed although the parties continued to engage in settlement negotiations. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS. The EIS is to be completed by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation will be administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue. The scope of the EIS will be determined through a public process and is expected to include cumulative and indirect effects of surrounding sources. PNM cannot currently predict the outcome of this matter.

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.

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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.

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is in discussion with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS. 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 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. 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 is not required to hold a 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. 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

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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.

The Superfund Oversight Section of the NMED also 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. 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. However, 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. Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station. PNM is unable to predict the outcome of these matters.

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 hydrocarbon investigation 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 (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF 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. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with the recent monitoring activities conducted under the CAF to NMED on October 3, 2016. Following review of the data by NMED, PNM, and NMED will develop plans for the next phase of work under the CAF.

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 NMMMD currently regulates placement of ash, which is generated from coal combustion at SJGS, in the San Juan mine 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

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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.

As indicated above, CCBs at Four Corners are currently disposed of in ash ponds and dry storage areas. Depending upon the results of groundwater monitoring required by the CCB rule, Four Corners may be required to take corrective action. Initial monitoring at Four Corners is not yet complete, so expenditures related to potential corrective actions, if any, cannot be reasonably estimated at this time.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCB regulations, within the next three years EPA is required to complete a rulemaking proceeding concerning whether or not boron must be included on the list of groundwater constituents that might trigger corrective action under EPA’s CCB rules. EPA is not required to take final action approving the inclusion of boron, but EPA must propose and consider its inclusion. Should EPA take final action adding boron to the list of groundwater constituents that might trigger corrective action, any resulting corrective action measures may increase costs of compliance with the CCB rule at coal-fired generating facilities. At this time, PNM cannot predict when EPA will commence its rulemaking concerning boron or the eventual results of those proceedings.

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA to modify the self-implementing provisions of the current CCB rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCBs, provides flexibility for states to incorporate the EPA final rule for CCBs or develop other criteria that are at least as protective as the EPA’s final rule, and requires EPA to approve state permit programs within 180 days of submission by the state for approval. As a result, the CCB rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional appropriated funding, EPA will implement the permit program in states that choose not to implement a program. Until permit programs are in effect, EPA has authority to directly enforce the self-implementing CCB rule. For facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. EPA has yet to undertake rulemaking proceedings to implement the CCB provisions of the WIIN Act. There is no timeline for establishing either state or federal permitting programs, which could take at least 18 months.

The December 2014 CCB 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 2017 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 US 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 DC Circuit for further proceedings consistent with the opinion. No changes are required at SJGS as a result of the US Supreme Court action.

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Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. Through January 31, 2016, SJCC was a wholly owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 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. 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, 2016 and 2015, prepayments for coal, which are included in other current assets, amounted to $48.7 million (including amounts purchased from the existing SJGS participants discussed below) and $49.0 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. 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 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 coal supply agreement (“CSA”), pursuant to which Westmoreland will 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 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 acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and 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. Coal costs under the CSA are significantly less than under the previous 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 are 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 (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland, to finance the purchase price of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital was able to provide the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”) with BTMU, as lender and administrative agent. The BTMU Term Loan Agreement became 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, has guaranteed NM Capital’s

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December 31, 2016, 2015 and 2014

obligations to BTMU. The balance outstanding under the BTMU Term Loan Agreement was $92.2 million at December 31, 2016 and $82.8 million at February 21, 2017.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, SJCC and its affiliate, as guarantors, BTMU, as administrative agent, and MUFG Union Bank, N.A., as depository bank. The Westmoreland Loan became effective as of February 1, 2016, and has a maturity date of February 1, 2021. The Westmoreland Loan initially bears interest at a rate of 7.25% plus LIBOR and escalates over time. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan requires that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it is fully repaid. At December 31, 2016, the amount outstanding under the Westmoreland Loan was $95.0 million. Reflecting the principal payment of $9.6 million that was paid when due on February 1, 2017, the balance of the Westmoreland Loan was $85.4 million as of February 21, 2017. The Westmoreland Loan is secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC was required to post reclamation bonds of $161.6 million with the NMMMD. In April 2016, NMMMD reduced SJCC’s bonding requirements to $118.7 million. In order to facilitate the posting of reclamation bonds by a surety on behalf of SJCC, a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) was entered into by PNMR, Westmoreland, and SJCC with the 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 for the benefit of the surety. On July 19, 2016, these reclamation bonds were released by NMMMD upon acceptance of $118.7 million of replacement reclamation bonds from alternate surety companies, which were supported by letters of credit aggregating $30.3 million issued from available capacity under the PNMR Revolving Credit Facility. The Reclamation Bond Agreement was terminated effective August 3, 2016 and the prior letter of credit was surrendered and canceled. On October 21, 2016, PNMR entered into separate letter of credit arrangements with a bank to replace the letters of credit issued from available capacity under the PNMR Revolving Credit Facility. The letters of credit issued from available capacity under the PNMR Revolving Credit Facility were surrendered and canceled upon acceptance of the replacement letters of credit by the surety companies that issued the reclamation bonds.

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 NTEC, 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 NTEC. The BHP subsidiary was retained as the mine manager and operator through December 2016. Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, took over management and operation of the mine effective January 1, 2017. The average coal price per MMBTU under the new contract was approximately 48% higher in the second half of 2016 than in the second half of 2015. 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.

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.

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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. The 2015 reclamation cost estimate reflects 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 expectations, 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 were reflected in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss).

Upon effectiveness of the CSA and the RA, PNM, on behalf of the SJGS owners, coordinated a more detailed coal mine reclamation cost study, which was completed in the third quarter of 2016. To complete the study, PNM was provided access to the mine site and obtained supporting data from Westmoreland, allowing for the 2015 study to be refined with a more extensive engineering analysis. The new reclamation cost estimate reflects the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053. The study indicates an increase in the reclamation cost estimate. PNM’s share of the increase is $4.5 million, which was recorded in 2016 and is reflected in regulatory disallowances and restructuring costs in the Consolidated Statements of Earnings. The current estimate for decommissioning the mine serving Four Corners reflects the operation of the mine through 2031, the term of the new agreement for coal supply.

Based on the 2016 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $102.0 million for the surface mines at both SJGS and Four Corners and $127.8 million for the underground mine at SJGS as of December 31, 2016. At December 31, 2016 and 2015, liabilities, in current dollars, of $41.0 million and $38.8 million for surface mine reclamation and $14.0 million and $11.4 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. On June 1, 2012, the SJGS owners entered into a reclamation 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 funds 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 $7.0 million in 2016, $4.3 million in 2015, and $1.0 million in 2014. Based on PNM’s reclamation trust fund balance at December 31, 2016, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $7.8 million in 2017, $8.3 million in 2018, and $8.7 million in 2019.

Under the coal supply agreement for Four Corners, which became 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. In July 2016, PNM funded its $1.9 million requirement for 2016. PNM’s anticipated funding level is $2.0 million, $2.0 million, and $2.1 million in 2017, 2018, and 2019.

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 retail customers 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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December 31, 2016, 2015 and 2014

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”). Comments regarding the rulemaking were due on October 11, 2013 and PNM submitted comments in opposition to the proposed rule. There is no legal deadline for adoption of the final rule.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS. In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM. In August 2006, SJCC and MMS entered into an 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. In March 2016, the parties settled this matter. PNM has paid its share of the settlement, which was $0.1 million in addition to amounts previously paid.

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 commercial sources and an industry-wide retrospective payment plan. In accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $13.4 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.0 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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December 31, 2016, 2015 and 2014

The PVNGS participants maintain 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”). 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 due to losses. 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 and Four Corners, PNM and APS have negotiated an agreement 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 agreement to share shortages in 2017 through 2020 has been negotiated and awaits endorsement by the parties and the New Mexico State Engineer.

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 40 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, then 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.

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

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December 31, 2016, 2015 and 2014

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 and maintaining the rights-of-way, as well as for capital improvements. 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. On January 4, 2016, the utilities filed an Application for Interlocutory Appeal from the state court. The state court litigation is stayed pending the New Mexico Court of Appeals’ ruling on the Application for Interlocutory Appeal. 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. In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM. 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.

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the

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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 1, 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’s motion for reconsideration of this ruling was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated and are stayed while PNM pursues its appeal before the Tenth Circuit. On June 27, 2016, PNM filed its opening brief in the Tenth Circuit. Amicus briefs were filed in support of PNM’s position. On October 5, 2016, the United States, the Navajo Nation, and individual allottees filed their response briefs. After the response briefs were filed, other entities requested leave to file amicus briefs addressing arguments raised in the United States’ response brief. Oral argument before the Tenth Circuit was heard on January 17, 2017.

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 Cases

New Mexico 2015 General Rate Case (“NM 2015 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 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 did 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. 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 proposed a revenue increase of $123.5 million, including base non-fuel revenues of $121.7 million. PNM’s new application was based on a FTY period beginning October 1, 2015, which met the NMPRC’s May 2015 interpretation of the FTY statute discussed below, and proposed a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and economic factors. The new application included several proposed changes in rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included higher customer and demand charges, a revenue decoupling pilot program applicable to residential and small commercial customers, a re-allocation of revenue among PNM’s customer classes, a new

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December 31, 2016, 2015 and 2014

economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC due to issues identified in PNM’s 2016 renewable energy procurement plan. As ordered by the NMPRC, PNM filed supplemental testimony in the NM 2015 Rate Case demonstrating that PNM’s FPPAC is designed to properly recover its fuel and purchased power expenses. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 7). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“CSA”). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current CSA (Note 16), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million.

On August 4, 2016, the Hearing Examiner in the case issued a recommended decision (“RD”). The RD proposed an increase in non-fuel revenues of $41.3 million compared to the $121.5 million increase requested by PNM. Major components of the difference in the increase in non-fuel revenues proposed in the RD, included:


•	A ROE of 9.575% compared to the 10.5% requested by PNM

•

Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 7); the RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases

•

Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 7) and related property taxes, which were $1.5 million per year at that time; the RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes


•	Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 16); PNM’s share of the costs of installing the BDT equipment was $52.3 million of which $40.0 million was included in rate base in PNM’s rate request


•	Disallowing recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges from retail customers

The RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from refined coal (a third-party pre-treatment process) at SJGS. In addition, the RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The RD proposed approving PNM’s proposals for revised depreciation rates (with one exception), the inclusion of CWIP in rate base, and ratemaking treatment of the prepaid pension asset. The RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the RD.

The NMPRC issued an order on September 28, 2016 that authorized PNM to implement an increase in non-fuel rates of $61.2 million, effective for bills sent to customers after September 30, 2016. The order generally approved the RD, but with certain significant modifications. The modifications to the RD included:

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•	Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued


•	Full recovery of the rent expense and property taxes associated with the extended leases for capacity, aggregating 114.6 MW, in Palo Verde Units 1 and 2


•	Disallowance of the recovery of any future contribution for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases


•	Recovery of assumed operating and maintenance expense savings of $0.3 million annually related to BDT

On September 30, 2016, PNM filed a Notice of Appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which states PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. Specifically, PNM’s statement indicated it is appealing the following elements of the NMPRC’s order:


•	Disallowance of recovery of the full purchase price, representing fair market value, of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016


•	Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM


•	Disallowance of recovery of future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases


•	Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT

The issues that are being appealed by the various cross-appellants include:


•	The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2


•	The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners


•	The revised method to collect PNM’s fuel and purchased power costs under the FPPAC


•	The final rate design


•	The NMPRC allowing PNM to include the prepaid pension asset in rate base

GAAP requires that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicates it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. PNM estimates that it will take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order will remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case, that the minimum amount of loss is 15 months of capital cost recovery that the order disallowed for its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT, and that no amount within the range of possible loss is a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-

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tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not propose to challenge in its appeal) since PNM can no longer assert that those assets are probable of being recovered through the ratemaking process. The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Consolidated Statement of Earnings.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recorded in future periods. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of December 31, 2016, such losses could include:


•	The remaining costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity in excess of the recovery permitted under the NMPRC’s order; the net book value of such excess amount was $76.9 million, after considering the loss recorded in 2016


•	The undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity in PVNGS Unit 2 purchased by PNM in January 2016 was being leased by PNM; the net book value of these improvements was $39.9 million, after considering the loss recorded in 2016


•	The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $50.0 million, after considering the loss recorded in 2016

Also, PNM has evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $155.6 million (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) at December 31, 2016, after considering the loss recorded in 2016. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and prepaid pension asset in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have financial impact to PNM.

PNM is unable to predict the outcome of this matter.

New Mexico 2016 General Rate Case (“NM 2016 Rate Case”)

On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request are:


•	An increase in base non-fuel revenues of $99.2 million


•	Based on a FTY beginning January 1, 2018


•	ROE of 10.125%


•	Drivers of revenue deficiency


◦	Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 16)


◦	Infrastructure investments


◦	Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors


◦	Updates in the FERC/retail jurisdictional allocations

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•	Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation


◦	Increased customer and demand charges


◦	A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs

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 NM Supreme Court, 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 NM Supreme Court 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. PNM and the NMPRC filed for dismissal of the appeal and the NM Supreme Court 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 minimums of 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:

•

107 MW of PNM-owned solar PV facilities, including 23 MW constructed in 2014 and 40 MW constructed in 2015; the 2015 additions were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 16) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; wind and solar REC purchases in 2013; 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


•	A PPA through 2018 for the output of New Mexico Wind, having an aggregate capacity of 204 MW and 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


•	A PPA for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current output of the facility is 4 MW


•	Solar distributed generation, aggregating 62.7 MW at December 31, 2016, owned by customers or third parties from whom PNM purchases any net excess output and RECs


•	Solar and wind RECs as needed to meet the RPS requirements

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of

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December 31, 2016, 2015 and 2014

certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceedings were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. In the September 28, 2016 order in the NM 2015 Rate Case, the NMPRC ordered the cost of New Mexico Wind to be recovered through PNM’s renewable rider, rather than the FPPAC, and certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. PNM cannot predict the outcome of the show cause proceeding.

PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017 and will be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determines a variance is necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a Recommended Decision recommending that the plan be approved as filed and also found that a variance from the RCT is not required. The NMPRC approved the Recommended Decision on November 23, 2016.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $42.0 million, $41.9 million, and $31.9 million in 2016, 2015, and 2014.

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 order issued February 3, 2016 approving the 2016 renewable energy plan. In its 2017 renewable energy procurement plan discussed above, PNM proposed to collect $50.0 million through the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, is due to including recovery of the costs of procuring energy from New Mexico Wind through the rider, rather than through the FPPAC, which complies with the NMPRC’s order in PNM’s NM 2015 Rate Case. The 2017 rider adjustment was approved as part of the order issued November 23, 2016 approving the 2017 renewable energy plan.

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 the NMPRC-approved rate by 0.5%, PNM would be required to refund the excess to customers during May through December of the following year. The NMPRC-approved rate was 10.0% when the renewable rider was initially approved. PNM’s annual compliance filings with the NMPRC show that its jurisdictional equity return did not exceed the limitation through 2015. Preliminary calculations indicate PNM did not exceed such limitation in 2016.

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

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December 31, 2016, 2015 and 2014

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.

On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consists of ten programs with a total budget of $28.0 million. The application also seeks approval of an incentive of $2.4 million based on target savings of 75 GWh. The actual incentive will be based upon actual savings achieved. An unopposed stipulation settling all issues was filed on September 29, 2016. The stipulation establishes a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of its retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and a sliding scale profit incentive with a base level of 7.1% of program costs, equal to $1.8 million, if PNM achieves a minimum proscribed level of energy savings and increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. The NMPRC approved the stipulation on January 11, 2017.

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. The base level incentive in 2017 is estimated to be $1.8 million.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. 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 April 23, 2014, the NMPRC approved a stipulated agreement resolving PNM’s 2013 application. The settlement modified the FPPAC to reset the fuel factor quarterly rather than annually, changed the carrying charge to apply the same rate to both over and under collections in the balancing account, allowed PNM to retain 10% of off-system sales margin through December 31, 2016, resolved the ratemaking treatment for coal pre-treatment at SJGS until the next subsequent PNM rate case, required PNM to write-off $10.5 million (which PNM recorded in 2013) 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.

Integrated Resource Plan

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2014 IRP

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 then 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 asserted 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 SJGS 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 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. On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket will be closed with prejudice within thirty days unless good cause is shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter.

2017 IRP

The 2017 IRP will address a 20-year planning period, from 2017 through 2036, and will include an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. PNM held its initial public advisory meeting on the 2017 IRP on June 30, 2016. The public advisory process is proceeding in three phases: in the first, PNM will build assumptions and discuss scenarios and sensitivities; in the second, PNM will discuss its analysis; and in the third, PNM will discuss its draft IRP with the public advisory participants. NMPRC rules require PNM to file its 2017 IRP by July 3, 2017. In the NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 16, PNM is required to make a filing in 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down.

San Juan Generating Station Units 2 and 3 Retirement

On December 16, 2015, the NMPRC issued an order approving PNM’s retirement of SJGS Units 2 and 3 on December 31, 2017. On January 14, 2016, NEE filed an appeal of the order with the NM Supreme Court. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 16.

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. On February 12, 2016, PNM filed a motion to withdraw its application. On May 18, 2016, the NMPRC issued an order granting PNM’s request to withdraw the application and closing the case.

On April 26, 2016, PNM filed an application for an 80 MW gas plant to be located at SJGS, with an anticipated June 2018 in-service date. On October 13, 2016, PNM filed a motion to vacate the procedural schedule to allow PNM to assess the continued need for the plant in light of possible changed circumstances affecting loads and resources. On October 28, 2016, PNM filed a motion to withdraw its application and close the docket. As grounds for the motion, PNM stated that, based on its updated peak demand forecast, the 80 MW plant would not be needed in 2018. On December 1, 2016, the Hearing Examiner issued an order recommending that the NMPRC grant PNM’s motion to withdraw its application. The NMPRC has not yet acted on that recommendation. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities and during the 2017 IRP process discussed above. PNM’s current capital forecast includes an additional 40 MW of peaking capacity that would be operational in 2020 to meet requirements for operating reserves. PNM cannot predict the outcome of this proceeding.

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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, 2016, 2015 and 2014

Advanced Metering Infrastructure Application

On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application also asks the NMPRC to authorize the recovery of the cost of the project, up to $87.2 million, in future ratemaking proceedings, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation and the costs of customer education and severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. In December 2016, the Hearing Examiner issued an order lifting the suspension and issued a new procedural schedule. A hearing on the application began on February 27, 2017. PNM cannot predict the outcome of this matter.

Facebook Data Center Project

On July 8, 2016, PNM filed an application with the NMPRC for approval of:


•	Two new electric service rates


•	A PPA under which PNM would purchase renewable energy from PNMR Development


•	A special service contract to provide electric service to a prospective new customer, a large Internet company, that was considering locating a data center in PNM’s service area

The NMPRC approved PNM’s application on August 17, 2016. At that time, the new customer was also considering the state of Utah for the location of the data center. On September 15, 2016, PNM filed a notice informing the NMPRC that the customer, Facebook Inc., had announced that it was selecting a site in New Mexico for its new data center.

The customer’s service requirements include the acquisition by PNM of a sufficient amount of new renewable energy resources and RECs to match the energy and capacity requirements of the data center. PNM’s initial procurement will be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development will construct and own. The cost of the PPA will be passed through to the customer under a new rate rider. A new special service rate will be applied to the customer’s energy consumption in those hours of the month when the customer’s consumption exceeds the energy production from the new renewable resources. Construction of the first 10 MW of solar capacity is expected to be completed in early 2018, which will coincide with initial operations of the data center, with the remainder of the capacity completed by mid-2018.

The approval order included a provision requiring that in any future rate case filed by PNM requesting an increase in rates of any other customer class, the NMPRC shall determine whether or not any customer class will be subject to increased rates due to the new customer’s fixed “Contribution to Production Charge for System Supplied Energy” and, if so, the NMPRC shall determine whether or not PNM will be allowed to recover such increased costs in the form of increased rates to other customers. In the NM 2016 Rate Case filing discussed above, PNM indicated the Facebook arrangement did not result in increased rates to any other customer class.

Hazard Sharing Agreement

On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expires on May 31, 2017. Under the agreement, each party will sell the other party 100 MW of capacity and energy on a unit contingent basis, from each party’s designated primary resources, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State. Both purchases and sales are made at the same market index price. In 2016, PNM sold 482,342 MWh for $12.8 million and purchased 484,632 MWh for $12.9 million under the agreement. The agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM and Tri-State have entered into an additional agreement, under substantially identical terms, for a term of five years beginning June 1, 2017, subject to NMPRC approval. NMPRC approval was not required for the one-year agreement, but is required for the five-year agreement. On November 30, 2016, PNM filed an application with the NMPRC for approval of the five-year agreement. A public hearing on PNM’s request is scheduled to begin on March 23, 2017.

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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, 2016, 2015 and 2014

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.

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. On April 1, 2013, PNM made the required compliance filing. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. 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 annualized increase of $1.3 million above the rates approved in the previous rate case. On March 25, 2015, the ALJ issued an order 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. On March 17, 2016, FERC approved the settlement. PNM made the refunds required under the settlement in May 2016.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended PSA between PNM and NEC, PNM’s largest firm-requirements wholesale customer, 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.

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 its PSA with PNM. 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. FERC approved the settlement on January 21, 2016. Under the settlement agreement, PNM served 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 served all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC also paid certain third-party transmission costs that it did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM will serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Revenues from NEC under the PSA were $20.0 million, $27.1 million, and $28.4 million in the years ended December 31, 2016, 2015, and 2014. PNM’s NM 2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

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.

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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, 2016, 2015 and 2014

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. PNM’s NM 2015 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. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters.

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. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of February 21, 2017, 104 consumers 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 was not complete and the total program costs to date were $1.5 million below the original approved forecasts, TNMP did not request a change to its monthly surcharge amount. On January 8, 2016, the PUCT staff recommended that the PUCT approve TNMP’s reconciliation without adjustment and the PUCT accepted that recommendation on March 25, 2016. In connection with TNMP’s deployment of AMS, TNMP committed to file a general rate case no later than September 1, 2018. TNMP will include a final reconciliation of AMS costs in the 2018 filing.

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)
March 1, 2014	$	5.6	$	0.7
March 1, 2015	5.7		1.5
March 1, 2016	6.0		0.7
March 1, 2017	6.0		0.8

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

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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, 2016, 2015 and 2014

taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(In millions)
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
March 23, 2016	25.8		4.3
September 8, 2016	9.5		1.8

On January 20, 2017, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.8 million annually, based on an increase in rate base of $30.2 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. However, TNMP has not made a filing to adjust rates for additional investments in distribution assets. As discussed above, TNMP has committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates to reflect changes in investments in distribution assets until after the 2018 general rate case.

(18) Goodwill

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 has 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. Currently, the first step of the quantitative impairment test requires an entity to compare the fair value

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

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. In January 2017, the FASB issued Accounting Standards Update 2017-04 - Intangibles - Goodwill and Other (Topic 350) that eliminates the second step of the impairment analysis. The Company must adopt this ASU in 2020, but early adoption is permitted. Accordingly, if the first step of a quantitative goodwill impairment analysis performed after adoption indicates that the fair value of a reporting unit is less than its carrying value, the goodwill of that reporting unit would be impaired to the extent of that difference.

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. For the annual evaluations performed as of April 1, 2016, PNMR utilized a quantitative analysis for both the PNM and TNMP reporting units. For the annual evaluations performed as of April 1, 2015 and 2014, PNMR utilized a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit.

A discounted cash flow methodology was primarily used in the quantitative analysis to estimate the fair value of each reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate 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 annual evaluations performed as of April 1, 2016, 2015, and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. Since the April 1, 2016 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. The April 1, 2016, 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%, 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%, 18%, and 23% at April 1, 2016, 2015, and 2014. The 2016 quantitative evaluation indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by 32%. 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 TNMP’s fair value over carrying value to approximately 21% at April 1, 2016. The 2015 and 2014 qualitative analysis for TNMP included the consideration of various reporting unit specific factors as well as industry and macroeconomic factors to determine whether these factors were reasonably likely to have a material impact on the fair value of the reporting unit. Factors considered included the results of the April 1, 2012 quantitative analysis, which indicated that fair value exceeded carrying value of the reporting unit by approximately 26%, current and long-term forecasted financial results, regulatory environment, credit rating, interest rate environment, absolute and relative price of PNMR’s common stock, and operating strategy. TNMP believes it is operating within a generally favorable regulatory environment, its historical and forecasted financial results are positive, and its credit is perceived positively. Based on the analysis of the relevant factors, PNMR concluded that it was more likely than not that the fair value of the TNMP reporting unit exceeds its carrying value at April 1 2015 and 2014.

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, which was sold in 2011 was significantly impacted by depressed economic conditions and changes in the market in which it operated. As a result, goodwill impairments of $51.1 million for PNM, $34.5 million for TNMP, and an aggregate of $174.4 million for PNMR were recorded in 2008. Since 2008, the price of PNMR’s common stock has increased, improving the relationship between PNMR’s market capitalization and book value. In addition, improved regulatory treatment has been experienced by PNM in New Mexico and by TNMP in Texas. These factors resulted in more predictable earnings and increased fair values of the reporting units. Since 2008, the annual evaluations have not indicated that the fair values of the reporting units with recorded goodwill have decreased below their carrying values.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014


(19)	Accumulated Other Comprehensive Income (Loss)

AOCI reports a measure for accumulated changes in equity that result from transactions and other economic events other than transactions with shareholders. Information regarding AOCI is as follows:



	Accumulated Other Comprehensive Income (Loss)
	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, 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 after-tax change	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 after-tax change	(10,662		)	941			(9,721		)	—			44			(9,677		)
Balance at December 31, 2015	17,346			(88,822		)	(71,476		)	—			44			(71,432		)
Amounts reclassified from AOCI (pre-tax)	(22,139		)	5,504			(16,635		)	—			764			(15,871		)
Income tax impact of amounts reclassified	8,639			(2,148		)	6,491			—			(298		)	6,193
Other OCI changes (pre-tax)	778			(18,501		)	(17,723		)	—			(874		)	(18,597		)
Income tax impact of other OCI changes	(304		)	7,219			6,915			—			341			7,256
Net after-tax change	(13,026		)	(7,926		)	(20,952		)	—			(67		)	(21,019		)
Balance at December 31, 2016	$	4,320		$	(96,748	)	$	(92,428	)	$	—		$	(23	)	$	(92,451	)

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, 2016, 2015, and 2014, approximately 23.4%, 22.2%, and 24.4% of the amount reclassified were capitalized into construction work in process and approximately 2.4%, 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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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2016, 2015 and 2014

(20) Quarterly Operating Results (Unaudited)

Unaudited operating results by quarters for 2016 and 2015 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
2016
Operating revenues	$	310,961	$	315,391	$	400,374	$	336,225
Operating income	41,508		64,822		108,071		63,584
Net earnings	13,965		30,952		58,556		28,423
Net earnings attributable to PNMR	10,546		27,076		54,418		24,809
Net Earnings Attributable to PNMR per Common Share:
Basic	0.13		0.34		0.68		0.32
Diluted	0.13		0.34		0.68		0.31
2015
Operating revenues	$	332,868	$	352,887	$	417,433	$	335,894
Operating income (loss)	49,569		72,414		121,505		(119,138		)	⁽¹⁾
Net earnings (loss)	17,852		35,655		64,855		(87,284		)
Net earnings attributable (loss) to PNMR	14,340		31,673		61,045		(91,418		)
Net Earnings (Loss) Attributable to PNMR per Common Share:
Basic	0.18		0.40		0.77		(1.15		)
Diluted	0.18		0.40		0.76		(1.15		)
PNM
2016
Operating revenues	$	235,606	$	233,346	$	311,276	$	255,685
Operating income	23,297		41,760		80,057		42,976
Net earnings	7,561		19,793		44,990		19,594
Net earnings attributable to PNM	4,274		16,049		40,984		16,112
2015
Operating revenues	$	261,940	$	275,450	$	333,437	$	260,368
Operating income (loss)	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		)
TNMP
2016
Operating revenues	$	75,355	$	82,045	$	89,098	$	80,540
Operating income	18,554		23,375		28,359		21,353
Net earnings	7,456		10,508		13,853		9,855
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

⁽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 28, 2017, we reported on the consolidated balance sheets of PNM Resources, Inc. and subsidiaries (the Company) as of December 31, 2016 and 2015, 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, 2016. 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 28, 2017

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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 28, 2017, we reported on the consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2016 and 2015, 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, 2016. 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 28, 2017

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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 28, 2017, we reported on the consolidated balance sheets of Texas-New Mexico Power Company and subsidiaries (the Company) as of December 31, 2016 and 2015, 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, 2016. 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 28, 2017

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF EARNINGS



	Year ended December 31,
	2016			2015			2014
	(In thousands)
Operating Revenues	$	—		$	—		$	—
Operating Expenses	2,871			1,221			650
Operating income (loss)	(2,871		)	(1,221		)	(650		)
Other Income and Deductions:
Equity in earnings of subsidiaries	122,252			27,352			124,543
Other income	1,711			747			622
Net other income and deductions	123,963			28,099			125,165
Interest Charges	8,102			8,275			13,650
Earnings Before Income Taxes	112,990			18,603			110,865
Income Tax Expense (Benefit)	(3,859		)	2,963			(5,389		)
Net Earnings	$	116,849		$	15,640		$	116,254

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2016			2015			2014
	(In thousands)
Net Cash Flows From Operating Activities	$	5,702		$	1,375		$	22,744
Cash Flows From Investing Activities:
Utility plant additions	341			368			(474		)
Investments in subsidiaries	(98,343		)	(175,000		)	—
Cash dividends from subsidiaries	35,959			127,688			46,599
Net cash flows from investing activities	(62,043		)	(46,944		)	46,125
Cash Flows From Financing Activities:
Short-term loan	100,000			50,000			—
Repayment of short-term loan	(150,000		)	—			—
Short-term borrowings (repayments), net	84,500			41,000			600
Long-term borrowings	100,000			150,000			—
Repayment of long-term debt	—			(118,766		)	—
Proceeds from stock option exercise	7,028			5,619			6,999
Purchases to satisfy awards of common stock	(15,451		)	(17,720		)	(17,319		)
Dividends paid	(70,095		)	(63,723		)	(58,940		)
Other, net	(28		)	(782		)	81
Net cash flows from financing activities	55,954			45,628			(68,579		)
Change in Cash and Cash Equivalents	(387		)	59			290
Cash and Cash Equivalents at Beginning of Period	441			382			92
Cash and Cash Equivalents at End of Period	$	54		$	441		$	382
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	5,906		$	7,559		$	12,152
Income taxes paid (refunded), net	$	—		$	(730	)	$	(2,014	)

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

BALANCE SHEETS



	December 31,
	2016			2015
	(In thousands)
Assets
Cash and cash equivalents	$	54		$	441
Intercompany receivables	92,234			102,676
Other, net	233			524
Total current assets	92,521			103,641
Property, plant and equipment, net of accumulated depreciation of $12,291 and $11,276	26,366			26,707
Investment in subsidiaries	1,986,276			1,822,593
Other long-term assets	79,314			81,168
Total long-term assets	2,091,956			1,930,468
	$	2,184,477		$	2,034,109
Liabilities and Stockholders’ Equity
Short-term debt	$	226,100		$	191,600
Short-term debt-affiliate	8,819			8,819
Accrued interest and taxes	1,333			7,780
Other current liabilities	19,374			18,282
Total current liabilities	255,626			226,481
Long-term debt	249,895			149,860
Other long-term liabilities	3,004			2,955
Total liabilities	508,525			379,296
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,163,661			1,166,465
Accumulated other comprehensive income (loss), net of tax	(92,451		)	(71,432		)
Retained earnings	604,742			559,780
Total common stockholders’ equity	1,675,952			1,654,813
	$	2,184,477		$	2,034,109

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

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SCHEDULE II

PNM RESOURCES, INC. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS



			Additions				Deductions
Description	Balance at beginning of year		Charged to costs and expenses		Charged to other accounts		Write-offs and other		Balance at end of year
			(In thousands)
Allowance for doubtful accounts, year ended December 31:
2014	$	1,423	$	3,267	$	—	$	3,224	$	1,466
2015	$	1,466	$	3,358	$	—	$	3,427	$	1,397
2016	$	1,397	$	2,885	$	—	$	3,073	$	1,209

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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:
2014	$	1,423	$	3,275	$	—	$	3,232	$	1,466
2015	$	1,466	$	3,344	$	—	$	3,413	$	1,397
2016	$	1,397	$	2,871	$	—	$	3,059	$	1,209

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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:
2014	$	—	$	(8	)	$	—	$	(8	)	$	—
2015	$	—	$	14		$	—	$	14		$	—
2016	$	—	$	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, 2016 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, 2016 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, 2016 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, 2016 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 Eight Directors” in PNMR’s Proxy Statement relating to the annual meeting of stockholders to be held on May 16, 2017 (the “2017 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 2017 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 9, 2016.


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 / Nominating and Governance Committee – Interlocks and Insider Participation” in the 2017 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 2017 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 2017 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 2017 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2017 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 AND FINANCIAL STATEMENT SCHEDULES



(a) - 1.	See Index to Financial Statements under Part II, Item 8.

(a) - 2.	Financial Statement Schedules for the years 2016, 2015, and 2014 are omitted for the reason that they are not required or the information is otherwise supplied under Part II, Item 8.

(a) - 3-A.	Exhibits Filed:

Exhibit No		Description

10.1**	PNMR	2017 Director Compensation Summary

10.2**	PNMR	Second Amendment to the PNMR 2014 Performance Equity Plan effective January 1, 2017

10.3**	PNMR	Fourth Amendment to the PNMR Second Amended and Restated Omnibus Performance Equity Plan effective January 1, 2017

10.4**	PNMR	Master Amendment to Long-Term Performance Equity Plans executed January 10, 2017

10.5	PNMR	First Amendment to Guaranty Agreement, dated as of December 21, 2016, made by PNMR in favor of lenders under the BTMU Loan Agreement

10.6**	PNMR	Summary of PNMR Officer Paid Time Off Program

10.7**	PNMR	First Amendment to PNMR Executive Spending Account Plan effective January 1, 2011

10.8**	PNMR	PNMR Officer Long Term Disability Coverage Description for Prudential Policy effective January 1, 2012

10.9**	PNMR	Form of Indemnity Agreement for PNMR officers and directors

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

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101.PRE	PNMR	XBRL Taxonomy Extension Presentation Linkbase Document



(a) -3- B.		Exhibits Incorporated By Reference:

The documents listed below are being filed (as shown above) or have been previously filed on behalf of PNM Resources, PNM or TNMP and are incorporated by reference to the filings set forth below pursuant to Exchange Act Rule 12b-32 and Regulation S-K section 10, paragraph (d).



Exhibit No.	Description of Exhibit	Filed as Exhibit:	Registrant (s) File No:

Articles of Incorporation and By-laws
3.1	Articles of Incorporation of PNMR, as amended to date (Certificate of Amendment dated October 27, 2008 and Restated Articles of Incorporation dated August 3, 2006)	3.1 to PNMR’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 PNM’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 TNMP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005	2-97230 TNMP

3.4	Bylaws of PNMR, Inc. with all amendments to and including February 26, 2015	3.4 to PNMR’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 PNM’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 PNMR 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 PNMR’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

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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

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	Eleventh Supplemental Indenture, dated as of September 1, 2016, supplemental to Indenture dated as of March 11, 1998, between PNM and MUFG Union Bank, N.A. (formerly 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 September 27, 2016	1-6986 PNM

4.18	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

4.19	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

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4.20	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

4.21	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

4.22	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 PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011	1-6986 PNM

4.23	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

4.24	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
4.25	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

4.26	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

4.27	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

4.28	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

4.29	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

4.30	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

4.31	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

4.32	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

4.33	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

4.34	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

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Material Contracts
10.10	Credit Agreement dated as of October 31, 2011 among PNMR, the lenders party thereto, Wells Fargo Bank, National Association, as administrative agent and Union Bank, N.A., as syndication agent	10.1 to PNMR’s Current Report on Form 8-K filed October 31, 2011	1-32462 PNMR

10.11	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 PNMR’s Annual Report on Form 10-K for the year ended December 31, 2011	1-32462 PNMR

10.12	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 PNMR’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

10.13	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 PNMR’s Current Report on Form 8-K filed December 17, 2014	1-32462 PNMR

10.14	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

10.15	Fifth Amendment to Credit Agreement effective November 2, 2016 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent	10.1 to PNMR's Current Report on Form 8-K filed November 4, 2016	1-32462 PNMR

10.16	Term Loan Agreement dated December 21, 2016 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 December 21, 2016	1-32462 PNMR

10.17	Term Loan Agreement dated December 21, 2016 among PNMR, the lenders identified therein, and JPMorgan Chase Bank, N.A., as administrative agent	10.2 to PNMR's Current Report on Form 8-K filed December 21, 2016	1-32462 PNMR

10.18	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 (terminated December 21, 2016)	10.1 to PNMR’s Current Report on Form 8-K filed December 21, 2015	1-32462 PNMR

10.19	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

10.20	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

10.21	Second Amendment to Term Loan Agreement effective November 2, 2016 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent	10.3 to PNMR’s Current Report on Form 8-K filed November 4, 2016	1-32462 PNMR

10.22	Term Loan Agreement dated as of February 1, 2016 among NM Capital, as borrower and BTMU, as lender and administrative agent ("BTMU Loan Agreement")	10.1 to PNMR's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

10.23	Guaranty Agreement dated as of February 1, 2016 made by PNMR in favor of the lenders under the BTMU Loan Agreement	10.2 to PNMR's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

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10.24	First Amendment to the Guaranty Agreement dated as of December 21, 2016, made by PNMR in favor of the lenders under the BTMU Loan Agreement	10.5 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.25	Loan Agreement dated as of February 1, 2016 among WSJ, as borrower, the guarantors named therein, NM Capital, as lender, BTMU, as administrative agent, and MUFG Union Bank, N.A., as depository bank	10.3 to PNMR's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

10.26	Reclamation Bond Agreement dated January 31, 2016 between PNMR, Westmoreland, SJCC and Zurich American Insurance Company	10.4 to PNMR's Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

10.27	Termination Agreement and Release of Zurich American Insurance Company dated as of August 3, 2016 among PNMR, Westmoreland, SJCC and Zurich American Insurance Company	10.1 to PNMR's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016	1-32462 PNMR

10.28	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

10.29	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

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

10.31	Third Amendment to Credit Agreement effective November 2, 2016 among PNM, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent	10.2 to PNM’s Current Report on Form 8-K filed November 4, 2016	1-6986 PNM

10.32	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

10.33	First Amendment to Credit Agreement effective November 3, 2016 among PNM, the lenders party thereto and U.S. Bank, National Association, as administrative agent	10.5 to PNM's Current Report on Form 8-K filed November 4, 2016	1-6986 PNM

10.34	Term Loan Agreement dated as of May 20, 2016 among PNM, the lenders identified therein, and JPMorgan Chase Bank, N.A., as administrative agent	10.1 to PNM's Current Report on Form 8-K filed May 20, 2016	1-6986 PNM

10.35	First Amendment to Term Loan Agreement effective November 2, 2016 among PNM, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent	10.4 to PNM's Current Report on Form 8-K filed November 4, 2016	1-6986 PNM

10.36	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

10.37	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 TNMP’s Annual Report on Form 10-K for the year ended December 31, 2015	2-97230 TNMP

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10.38	Bond Purchase Agreement dated December 9, 2013 between TNMP and the purchasers named therein (for $80,000,000 4.03% First Mortgage Bonds, due 2024, Series 2014A)	10.1 to TNMP’s Current Report on Form 8-K filed December 10, 2013	2-97230 TNMP

10.39	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

10.40**	PNMR 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

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

10.42**	Second Amendment to PNMR 2014 Performance Equity Plan effective January 1, 2017	10.2 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

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

10.44**	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

10.45**	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

10.46**	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

10.47**	Fourth Amendment to the PNMR Second Amended and Restated Omnibus Performance Equity Plan effective January 1, 2017	10.3 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.48**	PNMR 2016 Officer Annual Incentive Plan dated March 22, 2016	10.6 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

10.49**	PNMR 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

10.50**	PNMR 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

10.51**	PNMR 2016 Long-Term Incentive Plan dated March 22, 2016	10.5 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016	1-32462 PNMR

10.52**	PNMR 2015 Long-Term Incentive Plan dated March 20, 2015	10.2 to PNMR's Quarterly Report on Form 10-Q for the quarter ended March 31, 2015	1-32462 PNMR

10.53**	Master Amendment to Long-Term Performance Equity Plan executed January 10, 2017	10.4 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

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10.54**	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 PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014	1-32462 PNMR

10.55**	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

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

10.57**	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 PNMR’s Annual Report on Form 10-K for the year ended December 31, 2013	1-32462 PNMR

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

10.59**	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

10.60**	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

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

10.62**	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

10.63**	2017 Director Compensation Summary	10.1 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.64**	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 PNMR’s Current Report on Form 8-K filed March 1, 2011	1-32462 PNMR

10.65**	Acknowledgment Form with attached Terms and Conditions for restricted stock rights awards granted to directors under the PNMR 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

10.66**	PNMR Executive Spending Account Plan (amended and restated effective January 1, 2011)	10.4 to PNMR’s Current Report on Form 8-K filed March 1, 2011	1-32462 PNMR

10.67**	First Amendment to PNMR Executive Spending Account Plan effective January 1, 2011	10.7 to PNMR's Current Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.68**	PNMR 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

10.69**	First Amendment to PNMR Executive Savings Plan II executed April 15, 2016	10.7 to PNMR's Quarterly Report on Form 10-Q for the quarter ended June 30, 2016	1-32462 PNMR

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10.70**	Summary of PNMR Officer Paid Time Off Program	10.6 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.71**	PNMR 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

10.72**	PNMR Non-Union Severance Pay Plan effective August 1, 2007 (amended and restated)	10.3 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007	1-32462 PNMR

10.73**	First Amendment to the PNMR 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

10.74**	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

10.75**	PNMR Officer Retention Plan executed March 28, 2012 as amended and restated effective as of January 1, 2012	10.7 to PNMR’s Quarterly Report in Form 10-Q for the quarter ended March 31, 2012	1-32462 PNMR

10.76**	PNMR Officer Life Insurance Plan dated April 28, 2004	10.24.1 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004	333-32170 PNMR

10.77**	First Amendment to PNMR Officer Life Insurance Plan dated December 16, 2004	10.27 to PNMR’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004.	333-32170 PNMR

10.78**	Second Amendment to PNMR Officer Life Insurance Plan executed April 15, 2007	10.5 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2007	1-32462 PNMR

10.79**	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

10.80**	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

10.81**	Fifth Amendment to the PNMR Officer Life Insurance Plan executed December 16, 2011	10.5 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2011	1-32462 PNMR

10.82**	PNMR Officers Long Term Disability Coverage Description for Prudential Policy effective January 1, 2012	10.8 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	333-32170 PNMR

10.83**	Form of Indemnity Agreement for PNMR officers and directors	10.9 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.84	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

10.85	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

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10.86	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

10.87	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

10.88	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

10.89	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

10.90	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

10.91	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

10.92	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

10.93	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

10.94	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

10.95	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

10.96	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

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10.97	Amendments No. 1 through No. 6 to Arizona Nuclear Power Project Participation Agreement	10.8.1 to PNM’s Annual Report on Form 10-K for fiscal year ended December 31, 1991	1-6986 PNM

10.98	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

10.99	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

10.100	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

10.101	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

10.102	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

10.103	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

10.104	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

10.105	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

10.106	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

10.107*	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

10.108	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

10.109	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

10.110*	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

10.111	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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10.112	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

10.113	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

10.114	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

10.115	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

10.116	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

10.117	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

10.118	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

10.119	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 PNM’s Annual Report on Form 10-K for the year ended December 31, 2002	1-6986 PNM

10.120	Stipulation dated February 28, 2005 in NMPRC Case No. 04-00315-UT regarding the application of PNMR and TNMP for approval of the TNP acquisition	10.134 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005	1-32462 PNMR/ TNMP

Subsidiaries
21	Certain subsidiaries of PNMR	21 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	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 PNM’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010	1-6986 PNM

* One or more additional documents, substantially identical in all material respects to this exhibit, have been entered into, relating to one or more additional sale and leaseback transactions. Although such additional documents may differ in other respects (such as dollar amounts and percentages), there are no material details in which such additional documents differ from this exhibit.

** Designates each management contract or compensatory plan or arrangement required to be identified pursuant to paragraph 3 of Item 15(a) of Form 10-K.

‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



			PNM RESOURCES, INC.
			(Registrant)

Date:	February 28, 2017	By	/s/ P. K. Collawn
			P. K. Collawn
			Chairman, President, and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



Signature	Capacity	Date


/s/ P. K. Collawn	Principal Executive Officer and Director	February 28, 2017
P. K. Collawn
Chairman, President, and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer	February 28, 2017
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 28, 2017
J. D. Tarry
Vice President, Finance and Controller

/s/ N.P. Becker	Director	February 28, 2017
N. P. Becker

/s/ E. R. Conley	Director	February 28, 2017
E. R. Conley

/s/ A. J. Fohrer	Director	February 28, 2017
A. J. Fohrer

/s/ S. M. Gutierrez	Director	February 28, 2017
S. M. Gutierrez

/s/ M. T. Mullarkey	Director	February 28, 2017
M. T. Mullarkey

/s/ D. K. Schwanz	Director	February 28, 2017
D. K. Schwanz

/s/ B. W. Wilkinson	Director	February 28, 2017
B. W. Wilkinson

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SIGNATURES



			PUBLIC SERVICE COMPANY OF NEW MEXICO
			(Registrant)

Date:	February 28, 2017	By	/s/ P. K. Collawn
			P. K. Collawn
			President and Chief Executive Officer



Signature	Capacity	Date

/s/ P. K. Collawn	Principal Executive Officer and Chairman of the Board	February 28, 2017
P. K. Collawn
President and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 28, 2017
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 28, 2017
J. D. Tarry
Vice President, Finance and Controller

/s/ R. N. Darnell	Director	February 28, 2017
R. N. Darnell

/s/ C. M. Olson	Director	February 28, 2017
C. M. Olson

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SIGNATURES



			TEXAS-NEW MEXICO POWER COMPANY
			(Registrant)

Date:	February 28, 2017	By	/s/ P. K. Collawn
			P. K. Collawn
			Chief Executive Officer



Signature	Capacity	Date

/s/ P. K. Collawn	Principal Executive Officer and Chairman of the Board	February 28, 2017
P. K. Collawn
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	February 28, 2017
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	February 28, 2017
J. D. Tarry
Vice President, Finance and Controller

/s/ R. N. Darnell	Director	February 28, 2017
R. N. Darnell

/s/ C. M. Olson	Director	February 28, 2017
C. M. Olson

/s/ J. N. Walker	Director	February 28, 2017
J. N. Walker

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