PNM RESOURCES INC - Annual Report: 2017 (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, 2017



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 each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated

filer

Accelerated

filer

Non-accelerated

filer (Do not check if a smaller reporting company)

Smaller reporting

company

Emerging growth company

PNMR

PNM

TNMP

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £

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

As of February 20, 2018, shares of common stock outstanding were:



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

On June 30, 2017, 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 $38.25 per share reported by The Wall Street Journal, was $3,046,751,118. 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 22, 2018.

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 - 11
COMPETITION			A - 11
EMPLOYEES			A - 12
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS			A - 12
SECURITIES ACT DISCLAIMER			A - 13
ITEM 1A. RISK FACTORS			A - 13
ITEM 1B. UNRESOLVED STAFF COMMENTS			A - 24
ITEM 2. PROPERTIES			A - 24
ITEM 3. LEGAL PROCEEDINGS			A - 25
ITEM 4. MINE SAFETY DISCLOSURES			A - 25
SUPPLEMENTAL ITEM – EXECUTIVE OFFICERS OF PNM RESOURCES, INC.			A - 25
PART II
ITEM 5. MARKET FOR PNMR’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES			A - 26
ITEM 6. SELECTED FINANCIAL DATA			A - 27
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			A - 30
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK			A - 73
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 OWNERSIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS			C - 2
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE			C - 2
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			C - 2
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES			D - 1
ITEM 16. FORM 10-K SUMMARY			D - 13
SIGNATURES			E - 1

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GLOSSARY



Definitions:
2014 IRP		PNM’s 2014 IRP
2017 IRP		PNM’s 2017 IRP
ABCWUA		Albuquerque Bernalillo County Water Utility Authority
ABO		Accumulated Benefit Obligation
AEP OnSite Partners		AEP OnSite Partners, LLC, a subsidiary of American Electric Power, Inc.
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
August RD		Recommended Decision in PNM’s NM 2015 Rate Case issued by the Hearing Examiner on August 4, 2016
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

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FIP		Federal Implementation Plan
Four Corners		Four Corners Power Plant
FPL		FPL Energy New Mexico Wind, LLC
FPPAC		Fuel and Purchased Power Adjustment Clause
FTY		Future Test Year
GAAP		Generally Accepted Accounting Principles in the United States of America
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 District Court		United States District Court for the District of New Mexico
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
NMRD		NM Renewable Development, LLC, owned 50% each by PNMR Development and AEP OnSite Partners, LLC
NOx		Nitrogen Oxides
NOPR		Notice of Proposed Rulemaking

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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
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 New Mexico Credit Facility		PNM’s $50.0 Million Unsecured Revolving Credit Facility
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 2017 New Mexico Credit Facility		PNM’s $40.0 Million Unsecured Revolving Credit Facility
PNM 2017 Senior Unsecured Note Agreement		PNM’s Agreement for the sale of Senior Unsecured Notes, aggregating $450.0 million
PNM 2017 Term Loan Agreement		PNM’s $200.0 Million Unsecured Term Loan
PNM 2018 SUNs		PNM’s Senior Unsecured Notes to be issued under the PNM 2017 Senior Unsecured Note Agreement
PNM Multi-draw Term Loan		PNM’s $125.0 Million Unsecured Multi-draw Term Loan 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		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

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Red Mesa Wind		Red Mesa Wind Energy Center
REP		Retail Electricity Provider
RFP		Request For Proposal
Rio Bravo		Rio Bravo Generating Station, formerly known as Delta
RMC		Risk Management Committee
ROE		Return on Equity
RPS		Renewable Energy Portfolio Standard
RSIP		Revised State Implementation Plan
S&P		Standard and Poor’s Ratings Services
SCE		Southern California Edison Company
SCPPA		Southern California Public Power Authority
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SJCC		San Juan Coal Company
SJGS		San Juan Generating Station
SJGS CSA		San Juan Generating Station Coal Supply Agreement
SJGS RA		San Juan Project Restructuring Agreement
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 2015 Bond Purchase Agreement		TNMP’s $60.0 Million First Mortgage Bonds
TNMP 2017 Bond Purchase Agreement		TNMP’s Agreement for the issuance of $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 for San Juan Generating Station
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

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

PNMR’s success in accomplishing these strategic goals is highly dependent on 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 general rate cases with the NMPRC in August 2015 and December 2016. The NMPRC issued rate orders in those cases in September 2016 and January 2018. TNMP plans to file a general rate case in May 2018. 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, including a Climate Change Report, related to the operations of PNM and TNMP and reflects PNMR’s commitment to do business in an ethical, open, and transparent manner.

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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 documents may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Further information about the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are available on its website, www.sec.gov. These reports are also available in print upon request from PNMR free of charge.

Also available on the Company’s website at http://www.pnmresources.com/corporate-governance.aspx and in print upon request from any shareholder are PNMR’s:


•	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


•	Restated Articles of Incorporation and Bylaws

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. PNM was incorporated in the State of New Mexico in 1917. PNM’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. The largest retail electric customer served by PNM accounted for 2.4% of its revenues for the year ended December 31, 2017. Other services provided by PNM include wholesale 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 transmission lines that are interconnected with other utilities in New Mexico, Texas, Arizona, Colorado, and Utah. Regulation encompasses the utility’s electric rates, service, accounting, issuances of securities, construction of major new generation, abandonment of existing 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.

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. Oral argument at the NM Supreme Court was held on October 30, 2017. Although appeals of regulatory actions of the NMPRC have priority at the NM Supreme Court, there is no required time frame for the court to act on the appeal. See Note 17.

In December 2016, PNM filed a general rate case (the “NM 2016 Rate Case”) with the NMPRC. The December 2016 application proposed a non-fuel revenue increase of $99.2 million above the October 1, 2016 rates to be effective on January 1, 2018. The requested increase was 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 were 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 proposed 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. In May 2017, PNM and several intervenors filed a stipulation that, subject to approval by the NMPRC, would reduce the requested non-fuel revenue increase to $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019. Among

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other things, the revised stipulation proposed to reduce the ROE to 9.575% and to provide a debt-only return on PNM’s investment in SCRs at Four Corners. Hearings on the revised stipulation were held in August 2017. On October 31, 2017, the Hearing Examiners to the NM 2016 Rate Case issued their Certification of Stipulation recommending approval of the agreed upon revised stipulation with certain modifications, including identifying PNM’s continuation in Four Corners as imprudent and recommending against PNM’s ability to collect a debt or equity return on certain investments in that facility. On December 20, 2017, the NMPRC issued an order partially adopting the Certification of Stipulation, which approved the requested non-fuel revenue increase of $62.3 million over two years, but including additional modifications to reflect the impact of federal tax reform in customer rates beginning in 2018, rather than in 2019 as proposed in the revised stipulation, and deferring further consideration regarding PNM’s prudence related to Four Corners to a future proceeding. On December 28, 2017, PNM filed a motion for rehearing asking the NMPRC to vacate the December 20, 2017 order and requesting oral argument. After rehearing, the NMPRC issued a new order partially adopting the Certification of Stipulation with certain modifications, which, after further clarification, allows PNM to collect a debt return, but not an equity return, on certain of PNM’s investments in Four Corners; defers further consideration regarding the prudency of PNM’s continued participation in Four Corners to PNM’s next general rate case; requires PNM to reduce the $62.3 million annual non-fuel revenue increase by $4.4 million; requires the annual impacts of federal tax reform, estimated to amount to $47.6 million, to be reflected in customer rates beginning in 2018; and requires 50% of the rate increase be implemented for service rendered (rather than for bills rendered as PNM had requested) on or after February 1, 2018 and the rest of the increase for service rendered on or after January 1, 2019. The order results in an annual non-fuel revenue increase of $10.3 million. On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case. The notice does not set forth the basis of the appeal, which, as required by the court’s rules, is to be filed by March 9, 2018. See Note 17.

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. Through 2017, PNM’s earned return on jurisdictional equity has not exceeded the limitation. 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.

FERC Regulated Wholesale Operations

Rates charged to wholesale electric transmission customers are based on a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The 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 formula rate for the following year. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate.

The low natural gas price environment has resulted in market prices for power being substantially lower that what PNM has been able to offer wholesale generation customers under the cost of service model that FERC requires PNM to use. Consequently, PNM requested FERC approval to enter into arrangements to sell electricity at wholesale prices within PNM’s balance authority area using rates based on market conditions. In October 2015, FERC denied PNM’s request. Accordingly, PNM has decided to stop pursuing wholesale generation contracts.

Operational Information

Weather-normalized retail electric KWh sales decreased by 0.9% in 2017 and 0.7% in 2016. The system peak demands for retail and firm-requirements customers were as follows:

System Peak Demands



	2017	2016	2015
	(Megawatts)
Summer	1,843	1,908	1,889
Winter	1,289	1,376	1,433

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

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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 48.2%, 9.9%, and 9.5% of PNM’s 2017 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 in January 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 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 bulk transmission facilities since 1985. PNM owns transmission capacity in an area of eastern New Mexico with large wind generation potential and in recent years there has been substantial interest by developers of wind generation to interconnect to PNM’s transmission system in this area. PNM plans to construct approximately $170 million of new transmission facilities by 2020 to provide additional transmission service to deliver power from these generation resources to customers in New Mexico and California.

PNM also generates and sells electricity into the wholesale market. Through December 31, 2017, PNM’s 134 MW share of Unit 3 at PVNGS was excluded from retail rates and was being sold in the wholesale market. 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 and also authorized PNM to acquire 65 MW of SJGS Unit 4 as merchant plant. See Note 16 and Note 17. Shareholders realize any earnings or losses from generating resources that are not included in retail rates. In addition, PNM 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 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 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 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.

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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 1.2% in 2017 and 3.0% in 2016. As of December 31, 2017, 101 active REPs receive transmission and distribution services from TNMP. In 2017, the three largest REP customers of TNMP accounted for operating revenues of 16%, 11%, and 10%. 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 and 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 $4.4 million in March 2015, $1.4 million in September 2015, $4.3 million in March 2016, $1.8 million in September 2016, $4.8 million in March 2017, and $4.7 million in September 2017. On January 30, 2018, TNMP filed an application to further update its transmission rates, which would increase revenues by $0.6 million annually. The application is pending before the PUCT. TNMP plans to file a general rate case in May 2018 and is prohibited from filing additional interim adjustments to its transmission rates while the general rate case is in progress. 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 the activities of 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, NM Capital, and NMRD are also included in Corporate and Other.

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SOURCES OF POWER

PNM

Generation Capacity

As of January 1, 2018, the total net generation capacity of facilities owned or leased by PNM was 2,102 MW. PNM also obtains power under long-term PPAs for the power produced by Valencia, New Mexico Wind, Red Mesa Wind, the Lightning Dock Geothermal facility, and the NMRD-owned solar facility.

PNM’s capacity in electric generating facilities, which are owned, leased, or under PPAs, in commercial service as of January 1, 2018 is:



			Generation
			Capacity
Type	Name	Location	(MW)
Coal	SJGS	Waterflow, New Mexico	562
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
Solar	NMRD-owned solar	Los Lunas, New Mexico	10
Wind	New Mexico Wind	House, New Mexico	204
Wind	Red Mesa Wind	Seboyeta, New Mexico	102
Geothermal	Lightning Dock Geothermal	Lordsburg, New Mexico	4
			2,580

Fossil‑Fueled Plants

SJGS is operated by PNM and, until December 2017, consisted of four units. As discussed in Note 16, SJGS Units 2 and 3 were retired in December 2017 and the ownership interests in SJGS Unit 4 were restructured as of December 31, 2017. The table below presents the rated capacities and ownership interests of each participant in each unit of SJGS before and after these events:



	Unit MW Capacity and Ownership Interests
	Prior to Restructuring								After Restructuring
	Unit 1		Unit 2		Unit 3		Unit 4		Unit 1		Unit 4
Capacity (MW)	340		340		497		507		340		507

PNM⁽¹⁾	50.000	%	50.000	%	50.000	%	38.457	%	50.000	%	77.297	%
Tucson	50.000		50.000		—		—		50.000		—
SCPPA	—		—		41.800		—		—		—
Tri-State	—		—		8.200		—		—		—
MSR	—		—		—		28.800		—		—
Anaheim	—		—		—		10.040		—		—
Farmington	—		—		—		8.475		—		8.475
Los Alamos	—		—		—		7.200		—		7.200
UAMPS	—		—		—		7.028		—		7.028
Total	100.000	%	100.000	%	100.000	%	100.000	%	100.000	%	100.000	%

⁽¹⁾ After restructuring includes a 12.8% interest held as a merchant plant .

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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. APS and NTEC are currently in discussions as to the future of the option transaction. See Note 16 for additional information about Four Corners.

PNM owns 100% of Reeves, Afton, Rio Bravo, Lordsburg, and La Luz and one-third of Luna. The remaining interests in Luna are owned equally by Tucson and Samchully Power & Utilities 1, LLC. PNM is entitled to the entire output of Valencia under a PPA. Reeves, Lordsburg, Rio Bravo, La Luz, and Valencia are used primarily for peaking power and transmission support. As discussed in Note 9, Valencia is a variable interest entity and is consolidated by PNM as required by GAAP.

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%, including portions that are leased to PNM, of the power and energy generated by PVNGS. 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. Currently, 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 for PNM to include PVNGS Unit 3 as a jurisdictional resource to serve New Mexico retail customers beginning in 2018 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 several utility-owned solar PV facilities between 2011 and 2015. In addition, PNM completed its solar-storage demonstration project, which has a generation capacity of 0.5 MW. At December 31, 2017, PNM owns a total of 107 MW of solar facilities. PNMR Development began construction of 30 MW of new solar capacity in 2017. In December 2017, interest in that 30 MW of solar capacity was transferred to NMRD, which is 50% owned by PNMR Development. As discussed in Note 17, PNM’s 2018 renewable energy procurement plan includes the addition of 50 MW of PNM-owned solar PV facilities to be constructed in 2018 and 2019. In January 2018, the United States imposed a 30% tariff on certain imported solar panels. PNM is currently unable to predict the impact, if any, of this tariff on these projects. 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	2017	2016	2015
SJGS	PNM	84.1%	76.5%	67.4%
Four Corners	APS	50.6%	62.0%	77.8%
PVNGS	APS	91.9%	91.4%	94.2%

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. SJGS and Four Corners are coal-fired generating plants that obtain their coal

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requirements from mines near the plants. An agreement for coal supply for SJGS, which expires on June 30, 2022, became effective on January 31, 2016. At that same time, an agreement to restructure the ownership in SJGS became effective. The restructuring agreement provided for certain participants in SJGS to exit ownership at December 31, 2017, by which time SJGS Units 2 and 3 were required to be permanently shut down. See Note 16 for a discussion of the restructuring of SJGS ownership. In December 2013, a 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 held under leases. See Nuclear Plant above and Note 7 regarding PNM’s actions related to these leases.

It is possible that other participants in the joint projects have circumstances and objectives that have changed from those existing at the time of becoming participants. The status of these joint projects is further complicated by the uncertainty surrounding the form of potential legislation and/or regulation of GHG, other air emissions, and CCBs, 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’s 2017 IRP, which was filed on July 3, 2017, indicates that it would be cost beneficial to PNM’s customers for PNM to retire its SJGS capacity in 2022 and for PNM to exit its ownership interest in Four Corners in 2031. See additional discussion of PNM’s 2017 IRP and PNM’s regulatory recovery of certain investments in Four Corners under the NM 2016 Rate Case, in Note 17. 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 a 25-year agreement to purchase all of the power and RECs generated by New Mexico Wind. PNM began receiving power from the project in June 2003. FPL owns and operates New Mexico Wind, which currently consists of 136 wind-powered turbines having an aggregate capacity of 204 MW on a site in eastern New Mexico. PNM also has a 20-year agreement to purchase energy and RECs from the Lightning Dock Geothermal facility built near Lordsburg, New Mexico. The current capacity of the facility is 4 MW. PNM’s 2018 renewable plan filing, which was approved by the NMPRC on November 15, 2017, included requests to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind and an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal. The PPAs now expire in 2044 for New Mexico Wind and 2042 for Lightning Dock Geothermal.

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.

PNM and Tri-State have a hazard sharing agreement, which expires on May 31, 2022. Under this agreement, each party sells the other party 100 MW of capacity and energy from a designated generation resource on a unit contingent basis, subject to certain performance guarantees. Both the purchases and sales are made at the same market index price. This 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. See Note 17 for details related to purchases and sales. Since PNM purchases and sells approximately the same amount of energy under the hazard sharing agreement, it is not included as a capacity resource in the above table.

As discussed in Note 1, PNMR Development and AEP OnSite Partners created NMRD on September 22, 2017 to pursue the acquisition, development, and ownership of renewable energy generation projects primarily in the State of New Mexico. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD, a limited liability company. In December 2017, PNMR Development made a contribution to NMRD of its interest in three 10 MW solar facilities and assigned its interests in several agreements related to those facilities to NMRD. AEP OnSite Partners made a cash contribution to NMRD equal to 50% of the value of the 30 MW solar capacity, which cash was then distributed from NMRD to PNMR Development. Power from the 30 MWs of solar capacity will be sold to PNM under 25-year PPAs to supply renewable energy to a new data center being constructed in PNM’s service territory by Facebook, Inc. (Note 17). At January 1, 2018, the first 10 MW of solar capacity was in commercial operation and the remaining capacity is expected to begin commercial operation by mid-2018.

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•	Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located near House, New Mexico, have a total capacity of 50 MW, and be operational at December 31, 2018


•	A 166 MW portion of the La Joya Wind Project, owned by Avangrid Renewables, LLC, which is expected to be located near Estancia, New Mexico and be operational in November 2020


•	Route 66 Solar Energy Center, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located west of Albuquerque, New Mexico, have a total capacity of 50 MW, and be operational in December 2021

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



	Year Ended December 31,
	2017		2016		2015
Purchased under long-term PPAs
MWh	1,574,716		1,211,852		599,562
Cost per MWh	$	29.02	$	28.26	$	22.18
Other purchased power
Total MWh	445,464		502,893		729,895
Cost per MWh	$	31.74	$	27.78	$	28.94

TNMP

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

FUEL AND WATER SUPPLY

PNM

The percentages (on the basis of KWh) of PNM’s generation of electricity, including Valencia, 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
2017	56.5	%	$	2.16	31.9	%	$	0.64	9.2	%	$	3.02
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

In 2017, 2016, and 2015, 2.4%, 2.5%, and 1.5% of PNM’s generation was from utility-owned solar, which has no fuel cost. In December 2017, SJGS Units 2 and 3 were retired and PNM assumed a greater interest in SJGS Unit 4, which results in a lower percentage of PNM’s electric generation capacity being fueled by coal. The generation mix for 2018 is expected to be 44.3% coal, 29.4% nuclear, 23.8% gas and oil, and 2.5% 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 coal supply contract for SJGS, which expires on June 30, 2022, became effective 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. In 2018 and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM must file its position in a NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022.

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In late December 2013, a fifteen-year coal supply contract for Four Corners, which began in July 2016, was executed. The average coal price per ton under the new contract was approximately 51% higher in the twelve months ended June 30, 2017 than in the twelve months ended June 30, 2016, excluding disputed amounts discussed in Note 16. The contract provides for pricing adjustments over its term based on economic indices.

See Note 16 for additional information about PNM’s coal supply. As discussed in Note 17, PNM’s 2017 IRP indicated retiring PNM’s remaining interest in SJGS in 2022 after the expiration of the current operating and coal supply agreements and exiting ownership in Four Corners after the end of its current coal supply agreement in 2031 would provide long-term cost savings to PNM’s customers.

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. It is likely PNM’s reliance on its natural gas generating resources will increase with the December 2017 retirement of SJGS Units 2 and 3, which will increase PNM’s exposure to fluctuations in natural gas prices although substantially all gas costs are recovered through the FPPAC.

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 PVNG participants have contracted for 100% of PVNGS’s requirements for uranium concentrates through 2023 and 50% of its requirements for 2024 and 2025. Additionally, PVNGS has contracts in various phases of negotiation to procure an additional 1.5 years supply of uranium concentrates, which would result in 100% of uranium concentrate requirements being assured through 2026. The PVNGS participants have also contracted for 100% of the requirements for conversion services through 2021 and 46% of its requirements for 2022 through 2025. Additional contracts are being negotiated for 4.3 years supply of conversion services, which would result in 100% of those services being assured through 2027. The PVNGS participants have also contracted for 100% of the requirements for enrichment services through 2020 and 20% of its enrichment services for 2021 through 2026. Additionally, PVNGS has several contracts in negotiation to procure an additional 4.3 years supply of enrichment services, which would result in 100% of those services being assured through 2021, 90% in 2022 and 80% in 2023 through 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) pursued legal actions for which settlements were reached. See Note 16 for information concerning these actions.

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

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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 of $7.9 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”


•	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”


•	Environmental Matters under the caption “Coal Supply”

COMPETITION

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

PNM is subject to varying degrees of competition in certain territories adjacent to or within the areas it serves. This competition comes from other utilities in its region as well as rural electric cooperatives and municipal utilities. PNM is involved in the generation and sale of electricity into the wholesale market 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.

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EMPLOYEES

The following table sets forth the number of employees of PNMR, PNM, and TNMP as of December 31, 2017:



	PNMR	PNM	TNMP
Corporate ⁽¹⁾	396	—	—
PNM	938	938	—
TNMP	365	—	365
Total	1,699	938	365

(1)Represents employees of PNMR Services Company.

As of December 31, 2017, PNM had 495 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, 2017, TNMP had 198 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 orders in PNM’s NM 2015 Rate Case and NM 2016 Rate Case, appeals of those orders, the deferral of the issue of PNM’s prudence of continuation of participation in Four Corners to PNM’s next rate case and recovery of PNM’s investments in that plant, and any actions resulting from PNM’s 2017 IRP 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 and NM 2016 Rate Case, including appeals, and TNMP’s rate case anticipated to be filed in May 2018 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

•

Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects, including the 2022 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 and any actions resulting from PNM’s 2017 IRP, including regulatory recovery of undepreciated investments in the event the NMPRC orders generating facilities to be retired before currently estimated


•	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 and NM 2016 Rate Case, appeals of those orders, and PNM’s 2017 IRP


•	Uncertainty regarding what actions PNM may take with respect to the generating capacity in PVNGS Units 1 and 2, which is under lease, at the expiration of the lease terms in 2023 and 2024, as well as the related treatment of the NMPRC for ratemaking purposes

•

The Company’s ability to access the financial markets in order to provide financing to repay or refinance debt as it comes due, as well as for ongoing operations and construction expenditures, 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 and NM 2016 Rate Case, including appeals

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


•	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


•	State and federal regulatory, legislative, executive, and judicial decisions and actions on ratemaking, tax, including the impacts and related uncertainties of tax reform enacted in 2017, and other matters


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


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


•	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


•	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, including investments in its generating plants. PNM and TNMP are in a period of significant capital expenditures, including costs of replacing generating capacity as coal-fired plants are retired. 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 2018-2022 to be $2,712.1 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:


•	Costs of asset construction for generation, transmission, and distribution systems necessary to provide electric service, including new generation and transmission resources, as well as the cost to remove and retire existing assets


•	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


•	Rate design that is not driven by economics, which could influence customer behavior


•	Unfavorable economic conditions


•	Reductions in costs of self-generation energy resources and energy efficiency technology


•	Reduced new sources of demand


•	Unpredictable weather patterns

In 2017 and 2016, PNM experienced decreases in weather-normalized retail sales of 0.9% and 0.7%. The sales decreases reflect a continued sluggish economy in New Mexico. However, economic conditions in Albuquerque appear to have stabilized. The Albuquerque metro area is showing employment growth, although it continues to be lower than the national average. The economy in New Mexico continues to have mixed indicators and experience softness.

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 these disallowances with the NM Supreme Court. Other parties to that rate case have filed cross-appeals to PNM’s appeal in order to appeal other decisions of the NMPRC regarding issues in the rate case. On October 30, 2017, the NM Supreme Court heard oral argument on the case, but has not yet rendered a decision on the appealed matters and there is no required time frame for a decision to be issued.

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 were implementation of the plan for SJGS to comply with the CAA,

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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 (Note 16). The requested increase also reflected new infrastructure investments, including the installation of SCRs at Four Corners, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. PNM also proposed 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. On May 23, 2017, PNM and several signatories filed a revised comprehensive stipulation, which reduced the non-fuel revenue increase to $62.3 million and provided that PNM would only earn a debt return on its investments in SCR technology at Four Corners. In January 2018, the NMPRC issued an order, which approved many aspects of the revised comprehensive stipulation with several modifications. These modifications include a requirement for PNM to reflect the impacts of recently enacted federal tax reform in rates beginning in 2018, a disallowance of PNM’s ability to collect an equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected additional capital improvements at Four Corners, and a requirement that PNM reduce the $62.3 million non-fuel revenue requested increase by $4.4 million. The NMPRC deferred further consideration regarding the prudency of PNM’s continuation of participation in Four Corners to PNM’s next rate case. On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case.

As discussed in Note 17, PNM filed its 2017 IRP on July 3, 2017. Key findings of the 2017 IRP include that retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers and that PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also provide long-term cost savings for customers. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. NMPRC approval of new generation resources through CCN filings would also be required. The NMPRC has issued regulatory orders requiring depreciation (and resultant regulatory recovery) of significant portions of these resources through estimated lives of 2053 for SJGS and 2041 for Four Corners. If the NMPRC approves the retirement of SJGS in 2022 and exiting Four Corners in 2031, PNM will have significant un-recovered investments in those plants. PNM would seek NMPRC approval to recover those investments from ratepayers. At December 31, 2017, the net book values of PNM’s investments in SJGS and Four Corners were $406.7 million and $165.3 million.

An adverse outcome in the NM 2015 Rate Case or the NM 2016 Rate Case, including the pending appeals of those orders before the NM Supreme Court, or the decision in PNM’s next rate case on the issue regarding the prudency of PNM’s continued participation in Four Corners could negatively impact PNM’s financial position, results of operation, and cash flows. Likewise, if the NMPRC does not authorize appropriate recovery of any remaining investments in SJGS and Four Corners at the time those resources cease to be used to provide service to New Mexico ratepayers, including required future investments, and does not authorize recovery of the costs of obtaining power to replace those resources, PNM’s financial position, results of operation, and cash flows could be negatively impacted.

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 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 for Four Corners was approximately 51% higher in the twelve months ended June 30, 2017 than in the twelve months ended June 30, 2016. The contracts provide for pricing adjustments over their terms based on economic indices. Although PNM believes substantially all costs under coal supply arrangements would continue to be recovered through the FPPAC, there can be no assurance that full recovery will 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 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 26.7% 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 required the shutdown of SJGS Units 2 and 3 by December 31, 2017 and the shutdown was completed by that date. 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

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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 NM Supreme Court were to negate the BART Approval, it is unclear what the impact would be since SJGS Units 2 and 3 have been retired and ownership of SJGS has been restructured.

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 SJGS CSA for coal supply at SJGS described in Note 16 expires on June 30, 2022. PNM has the option to extend the SJGS 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.

As discussed in Note 17, PNM’s 2017 IRP indicates that retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements and exiting ownership in Four Corners after the current coal supply agreement expires in 2031 would provide long-term cost savings for PNM’s customers. The 2017 IRP addresses a 20-year planning period, from 2017 through 2036, and includes an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing.

The restructuring of SJGS ownership and obtaining the new coal supply for SJGS were integral components of the process to achieve compliance with the CAA at SJGS. The effectiveness of the new SJGS 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 Four Corners or their early retirement would require approval of the NMPRC and would require PNM to obtain power from other sources in order to serve the needs of its customers. There can be no assurance that the NMPRC would approve early retirement or that recovery of any undepreciated investments through rates charged to customers would be authorized. In addition, there can be no assurance that adequate sources of replacement 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 obtaining those resources would be economic. 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 and Four Corners, 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 SJGS and/or Four Corners or the ability of individual participants to continue participation in them.

PNMR’s utilities are subject to numerous federal, state, and local environmental laws and regulations, including those related to climate change, which may impose significant compliance costs and may significantly limit or affect their operations and financial results.

Environmental policies and regulations remain significant concerns for PNMR. 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 it would be affected if existing environmental laws and regulations were to be repealed, 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.

Under the Obama Administration, EPA’s Clean Power Plan mandated standards of performance that would limit carbon dioxide emissions from existing power plants. Individual states would develop and implement plans to ensure compliance with the proposed standards. Currently, the Clean Power Plan is stayed and under review. The Trump Administration has also proposed to repeal the Clean Power Plan and is considering a possible replacement rule. In addition, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. Therefore, PNMR is dealing with an uncertain regulatory and policy environment. While EPA and other federal agencies may be seeking to reduce climate change regulations,

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some state agencies, environmental advocacy groups, and other organizations have been focusing considerable attention on GHG from power generation facilities. PNM currently depends on fossil-fueled generation for a significant portion of its electricity. As discussed under Climate Change Issues, this type of generation could be subject to future EPA or state regulations requiring GHG reductions. This includes new, existing, and modified or reconstructed EGUs. The uncertainty regarding climate change regulation presents challenges and represents a possible shift of greater authority to the states to make decisions and issue and enforce regulations. Federal and/or state 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 at SJGS and are continuing at Four Corners for the installation of control technology resulting in operating costs increases. 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 changes in regulatory policy under the Trump 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, but not limited to: location, construction, and operation of facilities; the purchase of power under long-term contracts; conditions of service; the issuance of securities; and rates charged to customers. FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. 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 underutilization of 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 usage. 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

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•	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 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. PNM generates power at central station power plants to achieve economies of scale and produce power at a cost that is competitive with rates established through the regulatory process. 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. Advances in the capabilities for energy storage could also have impacts on power production by PNM as it would be increasingly simple to reduce peak usage by dispatching battery systems. This could result in demand reduction that could negatively impact revenue and/or result in underutilized assets that had been built to serve peak usage. If these technologies become cost competitive and achieve economies of scale, PNM’s energy sales could be eroded, and the value of its generating facilities could be reduced. Advances in technology could also change the channels through which electric customers purchase or use power, which could reduce the Company’s sales and revenues or increase expenses. These advances can also create more uncertainty in load shapes and forecasts, which could have implications for generation and system planning.

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.

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 in accordance with GAAP. These estimates include many assumptions about future events and are inherently imprecise. As discussed in Note 17, PNM’s 2017 IRP indicates that retiring PNM’s share of SJGS in 2022 and exiting PNM’s ownership interest in Four Corners in 2031 would provide long-term cost savings for customers. Should those events occur, the costs of reclamation for the coal mines serving those plants would increase and the increases could be significant. In the event any of these costs exceed current estimates, results of operations could be negatively impacted unless the NMPRC authorizes recovery of the additional costs from ratepayers. 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 NMPRC decision in the NM 2015 Rate Case, oral argument has been held, and the appeal is

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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.

The costs of decommissioning any nuclear power plant are substantial. PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS, including portions under lease both during and after termination of the leases. 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. As indicated above, SJGS Units 2 and 3 were shut down in December 2017. Also, PNM’s 2017 IRP indicates that retiring PNM’s share of SJGS in 2022 and that PNM exiting its ownership interest in Four Corners in 2031 would also provide long-term cost savings for customers. These actions will increase PNM’s dependency on other generation resources, particularly PVNGS, and will reduce PNM’s flexibility in managing those resources. 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 SJGS and Four Corners 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 utility industry in which the Company operates is 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, or unauthorized access, which could occur as a result of malicious compromise, 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

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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 19.1% 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 increasing inspection regime that could ultimately result in the shutdown of a unit, 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, particularly if PNM’s power plants are not performing as anticipated. In addition, SJGS units 2 and 3 were shut down in December 2017 and PNM’s 2017 IRP indicates that it would save customers money for PNM to shut down the remaining two units of SJGS in 2022 and to exit ownership in Four Corners in 2031. SJGS and Four Corners comprise a significant portion of PNM’s base load generation capacity and their retirement would increase reliance on other existing or new generating resources. Market forces, competitive forces, or adverse regulatory actions may require PNM to purchase capacity on the open market or build additional generation capabilities. Regulators or market conditions may not permit PNM to pass all of these purchases or construction costs on to customers. If that occurs, PNM may not be able to fully recover these costs or there may be a lag between when costs are incurred and when regulators permit recovery in customers’ rates. These situations could have negative impacts on results of operations and cash flows.

General Economic and Weather Factors

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

Economic activity 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,

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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.

Uncertainties regarding the impacts and implementation of recent United States tax reform legislation may negatively impact PNMR’s, PNM’s, and TNMP’s businesses, financial position, results of operations, and cash flows.

On December 22, 2017, comprehensive changes in United States federal income taxes were enacted through legislation commonly known as the Tax Cuts and Jobs Act (the “Tax Act”). Among other things, the Tax Act reduces the federal corporate income tax rate from 35% to 21% effective January 1, 2018, eliminates federal bonus depreciation for utilities effective September 28, 2017, and, effective January 1, 2018, limits interest deductibility for non-utility businesses and limits the deductibility of certain officer compensation. In December 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides guidance to address the application of GAAP to reflect the Tax Act in circumstances where all information and analysis of the Tax Act is not yet available or complete. This bulletin provides for up to a one-year period in which to complete the required analyses and accounting for the impacts of the Tax Act.

In accordance with GAAP, the Company adjusted its deferred tax assets and liabilities as of December 31, 2017 resulting in increases in regulatory liabilities related to adjustments of net deferred tax liabilities associated with regulated activities, which will be returned to PNM’s and TNMP’s ratepayers over time, and increases in income tax expense related to adjustments of net deferred tax assets related to items excluded from regulated activities. The Company believes it has made reasonable estimates of the effects of the Tax Act as of December 31, 2017 and reflected the impacts in the Consolidated Financial Statements.

The Company currently believes that the impacts of the Tax Act will not significantly impact the future earnings of regulated activities due to the ratemaking process. However, cash flows will be reduced in the near term due to less cash being received from customer billings as the benefits of the reduced corporate income tax are passed on to ratepayers, but without a corresponding reduction in income taxes paid due to the Company having a net operating loss carryforward for income taxes purposes. In addition, the income tax benefit of net losses for the unregulated activities of PNMR, primarily interest expense on holding company debt, will be negatively impacted by the reduced rate. Furthermore, there is uncertainty regarding the interpretation of the provision of the Tax Act that limits the deductibility of interest for non-utility businesses under the interest expense allocation methodology that is generally used by the utility industry.

It is possible that changes to U.S. Treasury regulations, IRS interpretations of the provisions of the Tax Act, actions by the NMPRC, PUCT, and FERC, or the Company’s further analysis of historical records could cause the estimates of the impacts recorded as of December 31, 2017 to change or cause the Company’s current assessment of future impacts to change. Any such change could adversely affect the Company’s financial position, results of operations, and cash flows.

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 the court system, 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.

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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, the Company’s financing agreements generally include a covenant to maintain a debt-to-capital ratio that does not exceed 65%, PNM has various financial covenants that limit the transfer of assets, through dividends or other means and the Federal Power Act imposes certain restrictions on dividends paid by public utilities, including that dividends cannot be paid from paid-in capital.

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, including the outcome of appeals of those decisions


•	Conditions imposed by the NMPRC, PUCT, or Federal Power Act


•	The effect of federal regulatory decisions and legislative acts


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


•	Future growth plans and the related capital requirements


•	Other business considerations

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

As discussed in MD&A – Liquidity and Capital Resources, PNMR and its subsidiaries rely on access to both short-term and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations. 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 2018-2022 to be $2,712.1 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 attacks, 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.

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PNMR, PNM, and TNMP cannot be sure that any of their current credit 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. On January 16, 2018, S&P changed the outlook for PNMR, PNM and TNMP from stable to negative while affirming the investment grade ratings of each entity. Downgrades or changing requirements could result in increased borrowing costs due to higher interest rates on current borrowings or 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.

Through 2017, the Company targeted 21% of its pension trust funds and 70% of its trust funds for other postretirement benefits to be invested in marketable equity securities. Historically, over one-half of funds held in the NDT and mine reclamation trusts have been invested in marketable equity securities. Due to the current funded status of the NDT and recent overall market performance, PNM began re-balancing the NDT investment portfolio with a target of 85% fixed income (debt) securities. The re-balancing was completed in January 2018 and increases the exposure of the NDT investment portfolio to interest rate risk. The Company is also contemplating decreasing its allocation target beginning in 2018 for liability matching fixed-income securities in the pension trusts from 65% to 50%. 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. In addition, a change in GAAP requires that all changes in the fair value of equity securities recorded on the Company’s balance sheet be reflected in earnings beginning in 2018, which could result in increased volatility in earnings.

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 the Critical Accounting Policies and Estimates section of MD&A. Long-lived assets are also assessed whenever indicators of impairment exist. Factors that affect the long-term value of these assets, including treatment by regulators in ratemaking proceedings, 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 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

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•	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, 2017, PNM owned, or jointly owned, 3,200 miles of electric transmission lines, 6,063 miles of distribution overhead lines, 5,828 miles of underground distribution lines (excluding street lighting), and 254 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 owns and 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. 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 vehicles, service facilities, and office locations throughout its service territory. As of December 31, 2017, TNMP owned 978 miles of overhead electric transmission lines, 7,119 miles of overhead distribution lines, 1,241 miles of underground distribution lines, and 116 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


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Santa Fe Generating Station


•	Coal Supply – Four Corners – Four Corners Coal Supply Arbitration


•	Continuous Highwall Mining Royalty Rate


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication


•	Rights-of-Way Matter


•	Navajo Nation Allottee Matters


•	Sales Tax Audits

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 Plans


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


•	PNM – Advanced Metering Infrastructure Application


•	TNMP – Transmission Cost of Service Rates


•	TNMP – Order Related to Changes in Federal Income Tax 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 23, 2018 and offices held with PNMR for the past five years are as follows:



Name	Age	Office	Initial Effective Date
P. K. Collawn	59	Chairman, President, and Chief Executive Officer	January 2012
C. N. Eldred	64	Executive Vice President and Chief Financial Officer	July 2007
P. V. Apodaca	66	Senior Vice President, General Counsel, and Secretary	January 2010
R. N. Darnell	60	Senior Vice President, Public Policy	January 2012
J. D. Tarry	47	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
C. M. Olson	60	Senior Vice President, Utility Operations	February 2018
		Vice President, Utility Operations	December 2016
		Vice President, Generation – PNM	November 2012

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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 2017 and 2016, by quarter, are as follows:



Quarter Ended	Range of Sales Prices				Dividends Declared Per Share
	High		Low		Dividends Declared Per Share
2017
March 31	$	37.60	$	33.45	$	0.2425
June 30	40.00		36.30		0.2425
September 30	42.95		37.35		0.2425
December 31	45.50		40.20		0.2650
Fiscal Year	45.50		33.45		0.9925
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

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 $0.22 per share in July 2016 and $0.2425 per share in July 2017, 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 $0.22 per share in September 2016 and $0.2425 per share in September 2017, which are reflected as being in the third quarter above. On February 23, 2018, the Board declared a quarterly dividend of $0.2650 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 20, 2018, there were 8,946 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 2017 and 2016. 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
	2017			2016			2015			2014			2013
	(In thousands except per share amounts and ratios)
Total Operating Revenues	$	1,445,003		$	1,362,951		$	1,439,082		$	1,435,853		$	1,387,923
Net Earnings	$	95,419		$	131,896		$	31,078		$	130,909		$	115,556
Net Earnings Attributable to PNMR	$	79,874		$	116,849		$	15,640		$	116,254		$	100,507
Net Earnings Attributable to PNMR per Common Share
Basic	$	1.00		$	1.47		$	0.2		$	1.46		$	1.26
Diluted	$	1.00		$	1.46		$	0.2		$	1.45		$	1.25
Cash Flow Data
Net cash flows from operating activities	$	524,462		$	415,454		$	386,874		$	414,876		$	386,587
Net cash flows from investing activities	$	(466,163	)	$	(699,375	)	$	(544,528	)	$	(485,329	)	$	(331,446	)
Net cash flows from financing activities	$	(58,847	)	$	242,392		$	175,431		$	96,194		$	(61,593	)
Total Assets	$	6,646,103		$	6,471,080		$	6,009,328		$	5,790,237		$	5,426,858
Long-Term Debt, including current installments	$	2,437,645		$	2,392,712		$	2,091,948		$	1,962,385		$	1,730,749
Common Stock Data
Market price per common share at year end	$	40.45		$	34.30		$	30.57		$	29.63		$	24.12
Book value per common share at year end	$	21.28		$	21.04		$	20.78		$	21.61		$	21.01
Tangible book value per share at year end	$	17.79		$	17.55		$	17.28		$	18.12		$	17.52
Average number of common shares outstanding – diluted	80,141			80,132			80,139			80,279			80,431
Dividends declared per common share	$	0.9925		$	0.9025		$	0.8200		$	0.7550		$	0.6800
Capitalization
PNMR common stockholders’ equity	40.9		%	41.1		%	44.0		%	46.6		%	49.0		%
Preferred stock of subsidiary, without mandatory redemption requirements	0.3			0.3			0.3			0.3			0.3
Long-term debt	58.8			58.6			55.7			53.1			50.7
	100.0		%	100.0		%	100.0		%	100.0		%	100.0		%

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2017		2016			2015			2014		2013
	(In thousands)
PNM Revenues
Residential	$	419,105	$	395,490		$	427,958		$	411,412	$	411,579
Commercial	408,354		394,150			437,279			428,085		415,621
Industrial	58,851		56,650			75,308			73,002		74,552
Public authority	23,604		23,174			26,202			25,278		25,745
Economy service	30,645		31,121			35,132			39,123		32,909
Transmission	45,932		34,267			33,216			38,284		38,228
Firm-requirements wholesale	4,468		22,497			31,263			38,313		42,370
Other sales for resale ⁽¹⁾	101,897		70,375			63,195			82,508		67,538
Mark-to-market activity	1,317		(1,645		)	(5,270		)	5,996		293
Other	10,057		9,834			6,912			5,913		7,477
Total PNM Revenues	$	1,104,230	$	1,035,913		$	1,131,195		$	1,147,914	$	1,116,312
TNMP Revenues
Residential	$	126,587	$	124,462		$	120,771		$	114,826	$	111,373
Commercial	106,503		103,174			102,956			99,701		95,098
Industrial	18,140		17,427			16,316			15,049		13,084
Other	89,543		81,975			67,844			58,363		52,056
Total TNMP Revenues	$	340,773	$	327,038		$	307,887		$	287,939	$	271,611

⁽¹⁾ Includes sales to Tri-State under hazard sharing agreement (Note 17).



PNM MWh Sales
Residential	3,136,066	3,189,527	3,185,363	3,169,071	3,304,350
Commercial	3,774,417	3,831,295	3,800,472	3,874,292	3,954,774
Industrial	850,914	875,109	957,308	984,130	1,041,160
Public authority	250,500	249,860	246,496	251,187	266,368
Economy service	722,501	805,733	796,430	758,629	719,342
Firm-requirements wholesale	87,600	429,345	444,495	527,597	654,135
Other sales for resale ⁽¹⁾	3,632,137	2,899,322	2,110,947	2,271,480	2,061,851
Total PNM MWh Sales	12,454,135	12,280,191	11,541,511	11,836,386	12,001,980
TNMP MWh Sales
Residential	2,936,291	2,933,938	2,912,019	2,802,768	2,796,661
Commercial	2,793,263	2,742,366	2,654,102	2,583,664	2,472,979
Industrial	3,202,528	2,976,800	2,804,919	2,708,151	2,576,762
Other	94,767	98,596	100,999	102,118	104,516
Total TNMP MWh Sales	9,026,849	8,751,700	8,472,039	8,196,701	7,950,918

⁽¹⁾ Includes sales to Tri-State under hazard sharing agreement (Note 17).

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PNM RESOURCES, INC. AND SUBSIDIARIES
COMPARATIVE OPERATING STATISTICS
	2017		2016		2015		2014		2013
PNM Customers
Residential	465,950		462,921		459,353		455,907		453,218
Commercial	56,655		56,357		56,107		55,853		55,447
Industrial	239		247		250		249		251
Economy service	1		1		1		1		1
Other sales for resale	36		36		39		39		34
Other	931		887		908		911		928
Total PNM Customers	523,812		520,449		516,658		512,960		509,879
TNMP Consumers
Residential	207,788		204,744		202,359		199,963		196,799
Commercial	39,814		39,817		39,014		38,033		37,460
Industrial	82		66		70		70		70
Other	1,948		1,993		2,018		2,044		2,070
Total TNMP Consumers	249,632		246,620		243,461		240,110		236,399
PNM Generation Statistics
Net Capability – MW, including PPAs ⁽¹⁾	2,580		2,791		2,787		2,707		2,572
Coincidental Peak Demand – MW	1,843		1,908		1,889		1,878		2,008
Average Fuel Cost per MMBTU	$	1.704	$	1.821	$	2.168	$	2.415	$	2.237
BTU per KWh of Net Generation	10,396		9,975		10,456		10,422		10,308

⁽¹⁾2017 amount is reflective of the shutdown of SJGS Units 2 and 3 in December 2017 and restructured ownership of SJGS Unit 4 as of December 31, 2017

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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 773,000 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 is viewed positively by credit rating agencies and that improvements in the Company’s ratings could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR. Additional information about rate filings is provided in Note 17.

State Regulation

New Mexico 2015 Rate Case – On September 28, 2016, the NMPRC issued an order that authorized 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 in August 2016 proposing an increase in non-fuel revenues of $41.3 million (the “August 2016 RD”). The NMPRC’s September 26, 2016 order approved many aspects of the August 2016 RD, including the determination that PNM was imprudent in purchasing 64.1 MW of previously leased capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT

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equipment on SJGS Units 1 and 4. However, the order also made certain significant modifications to the August 2016 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 contributions 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 continued the renewable energy rider and approved certain aspects of PNM’s proposals regarding rate design, but did 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 credited 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 approved PNM’s proposals for revised depreciation rates (with certain exceptions), 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. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated 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 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

NEE, NMIEC, and ABCWUA filed notices of cross appeal to PNM’s appeal. 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 “prepaid pension asset” in rate base

NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court, which 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.

On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court was held on October 30, 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.

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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 indicated 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 originally estimated that it would 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, at September 30, 2016, PNM recorded a pre-tax regulatory disallowance of $11.3 million, representing 15 months of capital cost recovery for the period October 1, 2016 through December 31, 2017 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. The NM Supreme Court did not render a decision on the case by December 31, 2017, the end of the originally estimated 15 month period. As of December 31, 2017, PNM updated its evaluation of the issues it is appealing in the NM Supreme Court. Although PNM cannot predict the ultimate outcome of this matter, PNM’s evaluation continues to indicate it is reasonably possible that PNM will be successful on the issues it is appealing and that it will take a minimum of an additional seven months from December 31, 2017 for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. On December 31, 2017, PNM recorded an additional pre-tax regulatory disallowance of $3.1 million, representing seven months of capital cost recovery on its investments the order disallowed. Additional losses will be recorded if the estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues is further extended.

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. If PNM’s appeal is unsuccessful, PNM would record additional pre-tax losses related to any unsuccessful issues. The December 31, 2017 book values of PNM’s investments that the order disallowed, after considering the losses recorded through December 31, 2017, were $75.3 million for the 64.1 MW of purchased capacity in PVNGS Unit 2, $39.1 million for the PVNGS Unit 2 disallowed capital improvements, and $49.4 million for the BDT equipment.

PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost 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 $151.1 million at December 31, 2017 (which amount includes $75.3 million that is the subject of PNM’s appeal discussed above) after considering the losses recorded through December 31, 2017. 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 a financial impact to PNM.

New Mexico 2016 Rate Case – 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 were:


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


•	Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application)


•	A 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, including environmental upgrades at Four Corners


◦	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

After NMPRC ordered settlement discussions were held, PNM and representatives of several intervenors reached an agreement on the parameters for a settlement in this proceeding. In May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form and allowing the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised

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stipulation that addressed the issues raised by the Hearing Examiners in their order. NEE was the sole party opposing the revised stipulation. The terms of the revised stipulation included:


•	A revenue increase totaling $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019


•	A ROE of 9.575%


•	Full recovery of PNM’s investment in SCRs at Four Corners with a debt-only return


•	An agreement not to seek to adjust non-fuel base rate changes to be effective prior to January 1, 2020


•	An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws and to true-up PNM’s cost of debt


•	Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate to the extent attributable to PNM’s retail operations


•	PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket


•	PNM would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028

A public hearing on the revised stipulation was held in August 2017. On October 31, 2017, the Hearing Examiners issued a Certification of Stipulation recommending modifications to the revised stipulation that would identify PNM’s decision to continue its participation in Four Corners as imprudent, not allow PNM to collect a debt or equity return on $148.1 million of investments in SCRs and other projects at Four Corners, and to temporarily disallow recovery of $36.8 of PNM’s projected capital improvements at SJGS. On December 20, 2017, the NMPRC issued an order approving the Certification of Stipulation with certain changes, which included requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt be implemented effective January 1, 2018 rather than January 1, 2019 and deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding.

On December 28, 2017, PNM filed a motion requesting rehearing and asking the NMPRC to vacate their December 20, 2017 order. Several signatories to the revised stipulation filed a separate motion for rehearing asking that the NMPRC approve the revised stipulation without modification. NEE filed a response urging the NMPRC to reject PNM’s motion. On January 3, 2018, the NMPRC vacated its December 20, 2017 order and granted the motions for rehearing, which was held on January 10, 2018. The NMPRC issued an order dated January 10, 2018 that approved the Certification of Stipulation with certain changes, which included allowing PNM to recover its $148.1 million of investments in SCR and other projects at Four Corners with a debt-only return (but maintaining the recommended disallowance of an equity return), deferring further consideration regarding the prudency of PNM’s decisions to continue its participation in Four Corners to PNM’s next general rate case, requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt be implemented in 2018 rather than January 1, 2019, and requiring PNM to reduce its requested $62.3 million increase in non-fuel revenues by $9.1 million.

On January 16, 2018, PNM requested clarifying changes to that order to adjust the $9.1 million reduction to $4.4 million, asserting that $4.7 million of the reduction was duplicative. PNM’s request was approved by the NMPRC. After implementation of changes to the federal corporate income tax rate and cost of debt, the order results in a net increase to PNM’s non-fuel revenue requirement of $10.3 million. PNM implemented 50% of the approved increase for service rendered, rather than bills rendered, on or after February 1, 2018 and will implement the rest of the increase for service rendered on or after January 1, 2019. GAAP requires PNM to recognize a loss reflecting that it will earn a debt-only return on $148.1 million of investments at Four Corners rather than a full return. Accordingly, PNM recorded a pre-tax regulatory disallowance of $27.9 million as of December 31, 2017.

On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case. The notice does not set forth the basis of the appeal, which, as required by the court’s rules, is to be filed by March 9, 2018. PNM cannot predict the outcome of this matter.

Advanced Metering – In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its 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 has 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, currently estimated to be $95.1 million, as well as to

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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. During a March 2017 hearing, it was identified that the proposed meter contractor may not have complied with certain New Mexico contractor licensing requirements. PNM subsequently filed testimony regarding that matter as ordered by the Hearing Examiner and requested a new procedural schedule to allow it to issue a new RFP for contracting work related to the meter installation and to update its cost-benefit analysis. An additional hearing was held in October 2017. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. PNM cannot predict the outcome of this matter.

PVNGS Unit 3 – Through December 31, 2017, PNM’s 134 MW interest in PVNGS Unit 3 was excluded from NMPRC jurisdictional rates. The power generated from that interest was sold into the wholesale market and any earnings or losses were 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 (Note 17).

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 costs, and the CTC. The NMPRC has approved PNM recovering fuel costs through the FPPAC, as well as 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. TNMP currently anticipates filing its general rate case in May 2018 using a 2017 calendar year test period. New rates are anticipated to become effective during January 2019.

FERC Regulation

Rates PNM charges wholesale transmission customers and wholesale generation services customers are subject to traditional rate regulation by FERC. For a number of years, PNM allocated a portion of its generation assets to serve FERC wholesale generation services customers. The low natural gas price environment resulted in market prices for power being 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 had not been earning an adequate return on the assets required to serve wholesale generation contracts. Consequently, PNM decided to stop pursuing wholesale generation contracts. Currently, PNM has no full-requirements wholesale generation customers.

Rates charged to wholesale electric transmission are based on a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The 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.

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 could 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. 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, which FERC approved in January 2016. Under the agreement, PNM served all of NEC’s load through December 31, 2015 at rates that were 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. The PSA terminated on December 31, 2016. In 2017, PNM served 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 2017, 2016 and 2015, revenues from NEC were $4.5 million, $20.0 million, and $27.1 million. Although the settlement agreement negatively impacted results of operations in 2017, PNM mitigated 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

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2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC.

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 6% earnings growth for the period 2018 through 2021. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that excludes from GAAP earnings 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

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	%
December 2017	9	%

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. In June 2017, Moody’s changed the outlook for PNMR and PNM from stable to positive while maintaining a stable outlook for TNMP. In January 2018, S&P changed the outlook for PNMR, PNM, and TNMP from stable to negative.

Business and Strategic 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. The Company 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 is 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.

Utility Plant and Strategic Investments

Utility Plant Investments – During the 2015 to 2017 period, PNM and TNMP together invested $1,552.0 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. PNM completed the 40 MW natural gas-fired La Luz peaking generating station located near Belen, New Mexico in December 2015. PNM also completed installation of SNCR and BDT equipment on SJGS Units 1 and 4 in early 2016 and the addition of 40 MW of PNM-owned solar

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PV facilities in 2015. 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.

Strategic Investments – In 2017, PNMR Development and AEP OnSite Partners created NM Renewable Development, LLC (“NMRD”) to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. Abundant renewable resources, large tracts of affordable land, and strong government and community support make New Mexico a favorable location for renewable generation. New Mexico has the 2^nd highest technical potential of the 48 contiguous states for utility scale solar photovoltaics as noted in 2015 by the National Renewable Energy Laboratory, while New Mexico is 6^th for technical potential for land-based wind. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. Through NMRD, PNMR anticipates being able to provide additional renewable generation solutions to customers within and surrounding its regulated jurisdictions through partnering with a subsidiary of one of the United States’ largest electric utilities. The formation of this joint venture provides a more efficient use of PNMR’s capital to support new renewable investment opportunities while maintaining the necessary capital to support investments required by PNM’s regulated jurisdictions. NMRD’s current renewable energy capacity under contract is 31.8 MW. This includes 11.8 MW of solar PV facilities currently in operation, consisting of 10 MW required to supply energy to a new data center in PNM’s service territory (Note 17) and 1.8 MW to supply energy to Columbus Electric Cooperative located in southwest New Mexico. At December 31, 2017, NMRD also had 20 MW of solar PV facilities under construction, which will be completed in mid-2018 and will also be used to supply the new data center. NMRD is actively exploring opportunities for additional renewable projects. In addition, NMRD will evaluate potential bid opportunities for future renewable projects, including large-scale projects to serve future data center and other customer needs.

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 filed its 2017 IRP on July 3, 2017. Under 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. The 2017 IRP analyzed several scenarios utilizing assumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP include:


•	Retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers


•	PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also provide long-term cost savings for customers


•	The best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity; the mix could include energy storage if the economics support it and wind energy provided additional transmission capacity becomes available


•	Significant increases in future wind energy supplies will likely require new transmission capacity to be built from eastern New Mexico to PNM’s service territory


•	PNM should retain the currently leased capacity in PVNGS, which would avoid replacement with carbon-emitting generation


•	PNM should continue to develop and implement energy efficiency and demand management programs


•	PNM should assess the costs and benefits of participating in the California Energy Imbalance Market


•	PNM should analyze its current Reeves Generating Station to consider possible technology improvements to phase out the older generators and replace them with new, more flexible supplies or energy storage

Several parties filed protests to the 2017 IRP. The issues addressed in the protests include PNM’s future interest in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. Likewise, NMPRC approval of new generation resources through CCN filings would be required. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

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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 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

PNMR’s Sustainability Portal provides key environmental and sustainability information related to PNM’s and TNMP’s operations and is available at http://www.pnmresources.com/about-us/sustainability-portal.aspx. The portal also contains a Climate Change Report, which outlines plans to be coal-free by 2031 (subject to regulatory approval). This could enable an 87% reduction in CO₂ emissions in 2040 compared to 2012 levels. This is a significantly greater reduction than that required of New Mexico under EPA’s Clean Power Plan.

SJGS

Regional Haze Rule Compliance Plan – In December 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 were retired in December 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:


•	Retired SJGS Units 2 and 3 (PNM’s ownership interest was 418 MW) in December 2017 and will recover, over 20 years, 50% ($125.5 million) of their undepreciated net book value at that date and earn a regulated return on those costs


•	Acquired an additional 132 MW in SJGS Unit 4 under an approved CCN, 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 (an aggregate of $20.7 million) (see New Mexico Rate Cases above and Note 17)


•	Was 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 ($154.9 million)


•	Acquired 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)


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

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 (“SJGS CSA”). PNM recorded additional pre-tax losses of $3.7 million in 2016 and reversed previously recorded losses of $4.0 million in 2017 resulting from revised estimates of these items. Additional information about the SJGS 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 2015 order. The NM Supreme Court has taken no action on the appeal and there is no required time frame for the court to act on the appeal. 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.

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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 (“SJGS RA”) sets forth the agreement among the SJGS owners regarding ownership restructuring. Key provisions of the SJGS RA include:

•

Capacity acquisition – On December 31, 2017, PNM was to acquire 132 MW and PNMR Development was to acquire 65 MW of the exiting owners’ capacity in SJGS Unit 4. PNMR Development assigned the rights and obligations related to the 65 MW to PNM effective on December 31, 2017, to facilitate dispatch of power from that capacity. As ordered by the NMPRC, PNM will treat the 65 MW as merchant utility plant that will be excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022.


•	Coal inventory – The SJGS RA also sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and supplied coal to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement provided economic benefits that were passed on to PNM’s customers through the FPPAC.

•

Coal supply – The SJGS RA became effective contemporaneously with the effectiveness of the new SJGS CSA. The effectiveness of the new SJGS 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 matures on February 1, 2021 and had an initial interest rate of 7.25% plus LIBOR, which escalates over time. Such rate is 12.25% plus LIBOR for the period from February 1, 2018 through January 31, 2019. WSJ must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. As of February 20, 2018, the balance of the Westmoreland Loan was $51.0 million.

•

Coal mine reclamation – Under the terms of the SJGS 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. On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order sets out two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order rescinds various actions undertaken by the previous administration and directs the EPA Administrator to review and if appropriate suspend, revise, or rescind the Clean Power Plan, as well as other environmental regulations. On October 10, 2017, EPA issued a proposal to repeal the Clean Power Plan based on a legal interpretation of the CAA under which the Clean Power Plan exceeds EPA’s statutory authority. EPA published the proposed repeal rule on October 16, 2017 and is accepting public comments until April 26, 2018. In addition, EPA published an advanced NOPR on December 28, 2017 to take comment on whether EPA should adopt a rule to replace the Clean Power Plan and what such a replacement rule might include, for which public comments were due February 26, 2018.

PNM estimates that implementation of the BART plan at SJGS, as well as potentially exiting ownership in the remaining units at SJGS (as well as Four Corners), as discussed above, should provide significant steps for New Mexico to meet its ultimate compliance with Section 111(d) under the Clean Power Plan or any replacement rule. PNM is unable to predict the impact of this rule on its fossil-fueled generation.

Because of environmental upgrades completed in 2009, SJGS has a mercury removal efficiency of 98% and mercury emissions are well below the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. Major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury.

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Between 2006 and 2017, SJGS has reduced NOx emissions by 41%, SO₂ by 70%, particulate matter by 61%, and mercury by 98%.

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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, 2017, PNM had 107 MW of utility-owned solar capacity. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 81.6 MW at December 31, 2017. 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 New Mexico Wind, a 204 MW wind facility, and began purchasing the output of Red Mesa Wind, an existing 102 MW wind energy center, on January 1, 2015. PNM has a 20-year agreement to purchase energy from the Lightning Dock Geothermal facility built near Lordsburg, New Mexico. The geothermal facility, which has a current capacity of 4 MW, began providing power to PNM in January 2014. 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 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. The NMPRC approved the plan on November 23, 2016. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM requested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018; continuation of customer REC purchase programs; and other purchases of RECs to ensure annual compliance with the RPS. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that PNM be required to issue another all-renewables RFP allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM disagreed with the Hearing Examiner’s recommendations and filed exceptions contesting the Hearing Examiner’s proposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and rejecting the Hearing Examiner’s recommendations. NMIEC filed an appeal with the NM Supreme Court objecting to the fuel allocation methodology. NEE filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. PNM filed a motion to intervene. The NM Supreme Court granted the motions to intervene. NMIEC filed a motion for a partial stay and PNM filed a response opposing the request. A briefing schedule has not been determined. PNM cannot predict the outcome of this matter.

In late 2017, PNM entered into three separate 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply additional renewable power to Facebook, Inc. These PPAs are subject to NMPRC approval and PNM made a filing requesting approval on January 17, 2018 (Note 17). These PPAs include the purchase of the power and RECs from a 50 MW wind project to be operational at December 31, 2018, a 166 MW wind project to be operational in November 2020, and a 50 MW solar project to be operational in December 2021.

PNM will continue to procure renewable resources while balancing the impact to customers’ electricity costs 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 2017, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 78 GWh. This is equivalent to the annual consumption of approximately 11,500 homes in PNM’s service territory. PNM’s load management and annual energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2017 resulted in energy savings totaling an estimated 21 GWh. This is equivalent to the annual consumption of approximately 2,300 homes in TNMP’s service territory. In April 2016 and again in April 2017, 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.

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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 and wind 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 2017, 18 of the Company’s 23 facilities met the solid waste diversion goal of a 60% diversion rate, while recycling at least the same number of waste streams as 2016. The Company expects to continue to do well in this area in the future.

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, community partners, regulators, intervenors, legislators, and shareholders. PNM continues to focus its efforts to enhance 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 customers, identifying and establishing valued services and programs, and proactively communicating and engaging with customers at regional and community levels.

The Company has leveraged a number of 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. In May 2017, a chat function was added to PNM’s website to allow customers options when communicating with its customer service representatives and an online management system was launched to expedite solar interconnection applications from retail customers. The website continues 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. In September 2016, PNMR launched a dedicated sustainability portal on its corporate website www.pnmresources.com to provide additional information regarding the Company’s environmental and other sustainability efforts. The site provides the key corporate governance and sustainability information related to the operations of PNM and TNMP. In January 2018, PNM added a Climate Change Report to this portal. The information is presented under four main headings: Environment, Social, Economic, and Governance.

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. In August 2017, Hurricane Harvey made landfall in the gulf coast region and TNMP worked diligently to restore power safely and efficiently for affected customers. In addition, PNMR made donations to support relief and restoration efforts in the gulf coast region. TNMP employees who were impacted by Hurricane Harvey were provided emergency crisis funds supported by the PNM Resources Foundation and other employee donations.

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 Company contacts that support their important service needs.

PNMR has a long tradition of supporting the communities it serves in New Mexico and Texas. The Company demonstrates its core value of caring through the PNM Resources Foundation, corporate giving, widespread employee volunteerism, and PNM’s low-income assistance programs. In addition to the extensive engagement both PNM and TNMP have with nonprofit organizations in their communities, the PNM Resources Foundation provides more than $1 million in grant funding each year across New Mexico and Texas. These grants help nonprofits collaborate more efficiently and support community projects such as providing software coding camps to underserved youths, funding murals in neighborhoods, and by providing employee matching and volunteer grants. In 2017, “A New Century of Service” grants, which celebrate PNM’s 100th anniversary, funded 62 community projects to build a better future for local communities. In December 2017, PNM announced an additional $1.0 million in donations to the PNM Resources Foundation to support future economic and educational programs in New Mexico.

PNM provides funds to support nonprofits in New Mexico focused in the areas of economic development, education, and the environment. One of PNM’s most important outreach programs is tailored for low-income customers. In 2017, PNM hosted

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44 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, and services for seniors. Additionally, through its Good Neighbor Fund, PNM provided $0.5 million of assistance with electric bills to 3,804 families in 2017 and offered financial literacy training to further support customers.

Volunteerism is an important facet of the PNMR culture. In 2017, more than 800 PNM and TNMP employees and retirees contributed approximately 10,800 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 2017 and 2016, PNM experienced decreases in weather-normalized retail load of 0.9% and 0.7%, reflecting a continued sluggish economy in New Mexico. However, economic conditions in Albuquerque appear to have stabilized. The Albuquerque metro area is showing employment growth, but continues to be lower than the national average. Also, some of the previously announced successful economic development efforts, such as the selection of a site within PNM’s New Mexico service territory for a data center by Facebook, Inc., appear to have started their hiring process. There also have been some expansions of existing businesses, particularly in healthcare, education, and professional services. The economy in New Mexico continues to have mixed indicators and experience softness.

TNMP – In 2017 and 2016, TNMP experienced increases in volumetric weather normalized retail load of 1.2% and 3.0%. Most of TNMP’s industrial and larger commercial customers are billed based on their peak demand. Demand-based load, excluding retail transmission customers, increased 4.0% and 2.4% in 2017 and 2016. The Texas economy continues to grow, primarily due to its diverse base, which offsets some of the impacts of Hurricane Harvey. Because TNMP’s service territory is geographically dispersed and was largely on the edges of the storm, a smaller percentage of customers were impacted by the hurricane as compared to some other utilities. The relocation of some national and global corporate headquarters to the Dallas-Fort Worth area has led to growth in commercial customers and also contributes to growth in residential and small business customers. TNMP continues to add 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 $79.9 million, or $1.00 per diluted share in the year ended December 31, 2017 compared to $116.8 million, or $1.46 per diluted share in 2016. Among other things, earnings in 2017 benefited from additional revenues due to the rate increase approved in the NM 2015 Rate Case at PNM, higher revenues under FERC formula transmission rates and new transmission customers at PNM, rate increases and increased load at TNMP, lower plant maintenance costs at PNM, higher gains on available-for-sale securities, higher AFUDC due to higher levels of construction expenditures at PNM, and excess tax benefits related to stock compensation recognized under a new accounting standard (Note 13). These increases were more than offset by decreased load at PNM, milder weather at PNM and TNMP, lower revenue from NEC at PNM, greater regulatory disallowances at PNM, increased depreciation and property taxes due to increased plant in service at PNM and TNMP and higher depreciation rates approved in PNM’s NM 2015 Rate Case, and lower interest income on the Westmoreland Loan and from the IRS, as well as the additional income taxes resulting from the reduction in the federal corporate income tax rate (Note 11) and increased pre-tax earnings. 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 2022. 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 2022. Both facilities provide for short-term borrowings and letters of credit. In addition, PNM has a $40.0 million revolving credit facility, which expires in December 2022, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2022. Total availability for PNMR on a consolidated basis was $522.3 million at February 20, 2018. On February 26, 2018, PNMR Development entered into a $24.5 million revolving credit facility that matures on February 25, 2019. 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.

PNMR projects that its consolidated capital requirements, consisting of construction expenditures and dividends, will total $3,136.8 million for 2018-2022. The construction expenditures include estimated amounts for environmental upgrades at Four Corners, 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, an anticipated expansion of

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PNM’s transmission system, and the initial costs of replacement resources related to the potential shutdown of SJGS Units 1 and 4 in 2022.

In July 2017, PNM entered into the PNM 2017 Senior Unsecured Note Agreement, under which $450.0 million of the PNM 2018 SUNs are to be issued in 2018 and the proceeds will be used to repay $450.0 million of currently outstanding Senior Unsecured Notes on their maturity dates in 2018. After considering these financings, PNMR has consolidated maturities and repayments of short-term and long-term debt aggregating $357.3 million in the period from January 1, 2018 through December 31, 2018. Furthermore the $200.0 million PNM 2017 Term Loan Agreement matures in January 2019 and TNMP has $172.3 million of first mortgage bonds that are due in April 2019. 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 2018-2022 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 for the next twelve months. The Company is in compliance with its debt covenants.

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
	2017		2016		2015		2017/2016			2016/2015
	(In millions, except per share amounts)

Net earnings attributable to PNMR	$	79.9	$	116.8	$	15.6	$	(37.0	)	$	101.2
Average diluted common and common equivalent shares	80.1		80.1		80.1		—			—
Net earnings attributable to PNMR per diluted share	$	1.00	$	1.46	$	0.20	$	(0.46	)	$	1.26

The components of the changes in net earnings attributable to PNMR by segment are:



	Change
	2017/2016			2016/2015
	(In millions)
PNM	$	(5.0	)	$	92.7
TNMP	(6.1		)	(0.3		)
Corporate and Other	(25.9		)	8.9
Net change	$	(37.0	)	$	101.2

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 defines utility margin 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

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under PNM’s FPPAC. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.

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The following table summarizes the operating results for PNM:



	Year Ended December 31,									Change
	2017			2016			2015			2017/2016			2016/2015
	(In millions)
Electric operating revenues	$	1,104.2		$	1,035.9		$	1,131.2		$	68.3		$	(95.3	)
Cost of energy	321.7			299.7			391.1			22.0			(91.4		)
Utility margin	782.6			736.2			740.1			46.4			(3.9		)
Operating expenses	423.0			414.7			591.0			8.3			(176.3		)
Depreciation and amortization	147.0			133.4			115.7			13.6			17.7
Operating income	212.5			188.1			33.4			24.4			154.7
Other income (deductions)	39.1			32.2			33.5			6.9			(1.3		)
Interest charges	(82.7		)	(87.5		)	(80.0		)	4.8			(7.5		)
Segment earnings (loss) before income taxes	169.0			132.9			(13.1		)	36.1			146.0
Income (taxes) benefit	(81.6		)	(40.9		)	12.8			(40.7		)	(53.7		)
Valencia non-controlling interest	(15.0		)	(14.5		)	(14.9		)	(0.5		)	0.4
Preferred stock dividend requirements	(0.5		)	(0.5		)	(0.5		)	—			—
Segment earnings (loss)	$	71.9		$	76.9		$	(15.8	)	$	(5.0	)	$	92.7

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



	Year Ended December 31,			Change
	2017	2016	2015	2017/2016		2016/2015
	(Gigawatt hours, except customers)
Residential	3,136.1	3,189.5	3,185.4	(53.4	)	4.1
Commercial	3,774.4	3,831.3	3,800.5	(56.9	)	30.8
Industrial	850.9	875.1	957.3	(24.2	)	(82.2	)
Public authority	250.5	249.9	246.5	0.6		3.4
Economy service ⁽¹⁾	722.5	805.7	796.4	(83.2	)	9.3
Firm-requirements wholesale ⁽²⁾	87.6	429.3	444.5	(341.7	)	(15.2	)
Other sales for resale ⁽³⁾	3,632.1	2,899.3	2,110.9	732.8		788.4
	12,454.1	12,280.2	11,541.5	174.0		738.6
Average retail customer (thousands)	522.0	518.6	514.9	3.4		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 utility margin so there is only a minor impact in utility margin resulting from providing ancillary services.


⁽²⁾	Decrease in 2017 reflects reduced sales to NEC (Note 17) and loss of other firm-requirements wholesale customers.


⁽³⁾	Increases in 2017 and 2016 include the hazard sharing agreement with Tri-State (Note 17). Increase is also due to more power available for off-system sales, primarily related to SJGS and Four Corners, as well as power that was previously sold to NEC and other firm-requirements wholesale customers. Substantially all of the margin from off-system sales is returned to customers through the FPPAC.

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Operating Results – 2017 Compared to 2016

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2017
		Change
Utility margin:		(In millions)

	Rate relief – Additional revenue due to rate increase approved by the NMPRC on September 28, 2016 and certain fuel costs being passed through the FPPAC	$	51.9
	Customer usage/load – PNM’s weather normalized retail KWh sales decreased 0.9%, due to decreased sales to residential, commercial, and industrial customers	(5.9		)
	Weather – Milder weather; heating degree days were 8.9% lower, partially offset by higher cooling degree days of 2.0%	(3.8		)
	Leap Year – Decrease in revenue due to additional day in 2016	(1.6		)
	Transmission – Higher revenues under formula transmission rates and the addition of new customers	12.1
	Wholesale contracts – Primarily due to NEC (Note 17)	(7.8		)
	Unregulated margin – Higher hedged prices for PVNGS Unit 3 power sales	3.9
	Rate riders – Includes renewable energy and energy efficiency riders, which are partially offset in operating expenses, depreciation and amortization, and interest charges	(1.9		)
	Net unrealized economic hedges – Losses related to hedges of NEC power sales, partially offset by gains related to hedges of PVNGS	(1.3		)
	Other	0.8
	Net Change	$	46.4

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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, 2017
		Change
Operating expenses:		(In millions)

	2017 regulatory disallowance due to the NMPRC’s January 17, 2018 order in PNM’s NM 2016 Rate Case (Note 17)	$	27.9
	Regulatory disallowances due to the NMPRC’s September 28, 2016 order in PNM’s NM 2015 Rate Case (Note 17)	(8.1		)
	Regulatory disallowances due to change in estimated write-offs associated with the SJGS BART determination and ownership restructuring (Note 16)	(7.8		)
	Lower plant maintenance costs at SJGS, Four Corners, and PVNGS, partially offset by increased costs at gas-fired plants	(3.8		)
	Implementation of process improvement initiatives in 2016 associated with reducing future costs	(3.7		)
	Lower employee related expenses and outside consulting costs	(3.4		)
	Lower rent expense associated with PVNGS leases (Note 7)	(0.9		)
	Higher capitalized administrative and general expenses due to higher construction spending	(1.7		)
	Higher allocated corporate depreciation, primarily related to computer software	5.4
	Training costs associated with new software implementation	1.1
	Contribution to the PNM Resources Foundation	1.0
	Higher property taxes due to increased utility plant in service	0.9
	Higher environmental expenses	0.5
	Other	0.9
	Net Change	$	8.3



Depreciation and amortization:

	Higher depreciation rates approved by the NMPRC in PNM’s 2015 NM Rate Case, including the impacts of impairments (Note 17)	$	6.1
	Increased utility plant in service	6.8
	Other	0.7
	Net Change	$	13.6

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		Year Ended December 31, 2017
		Change
Other income (deductions):		(In millions)

	Higher gains on available-for-sale securities in the NDT and coal mine reclamation trusts	$	7.6
	Higher equity AFUDC, primarily due to increased levels of construction expenditures	4.5
	Interest income from third party transmission service provider due to FERC ruling	1.0
	Lower income from “refined coal” (a third-party pre-treatment process); income is now passed through to customers as ordered in PNM’s NM 2015 Rate Case	(3.8		)
	2016 interest income from IRS, net of related expenses (Note 11)	(2.9		)
	Other	0.5
	Net Change	$	6.9



Interest charges:

	Lower interest on $146.0 million of PCRBs refinanced in September 2016	$	2.6
	Lower interest on $57.0 million of PCRBs refinanced in June 2017	0.6
	Lower short term debt borrowings	0.8
	Higher debt AFUDC as a result of higher construction spending	1.0
	Other	(0.2		)
	Net Change	$	4.8



Income taxes:

	Increase due to higher segment earnings before income taxes	$	(13.8	)
	Impacts of increase in equity AFUDC	1.7
	Regulatory recovery of prior year impairments of state net operating loss carryforwards due to NMPRC orders in PNM rate cases (Note 17) (net of amortization)	0.3
	Impacts of phased-in reduction in New Mexico corporate income tax rates	2.0
	Decrease due to excess tax benefits related to stock compensation awards (Note 13)	1.7
	Impairments of state NOL carryforwards	(0.9		)
	Impact of change in federal corporate income tax rate	(29.6		)
	Other impairments and valuation allowances	(2.1		)
	Net Change	$	(40.7	)

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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
	Higher 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	)

TNMP

TNMP defines utility margin 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 on to customers through a transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.

The following table summarizes the operating results for TNMP:



	Year Ended December 31,									Change
	2017			2016			2015			2017/2016			2016/2015
	(In millions)
Electric operating revenues	$	340.8		$	327.0		$	307.9		$	13.8		$	19.1
Cost of energy	85.8			80.9			73.5			4.9			7.4
Utility margin	255.0			246.2			234.4			8.8			11.8
Operating expenses	98.2			93.4			88.1			4.8			5.3
Depreciation and amortization	63.1			61.1			56.3			2.0			4.8
Operating income	93.6			91.6			90.0			2.0			1.6
Other income (deductions)	3.6			3.2			3.7			0.4			(0.5		)
Interest charges	(30.1		)	(29.3		)	(27.7		)	(0.8		)	(1.6		)
Segment earnings before income taxes	67.1			65.5			66.1			1.6			(0.6		)
Income (taxes)	(31.5		)	(23.8		)	(24.1		)	(7.7		)	0.3
Segment earnings	$	35.6		$	41.7		$	42.0		$	(6.1	)	$	(0.3	)

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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,			Percentage Change
	2017	2016	2015	2017/2016		2016/2015
Volumetric load⁽¹⁾ (GWh)
Residential	2,936.6	2,933.9	2,912.0	0.1	%	0.8	%
Commercial and other	34.0	42.4	49.3	(19.8	)%	(14.0	)%
Total volumetric load	2,970.6	2,976.3	2,961.3	(0.2	)%	0.5	%
Demand-based load ⁽²⁾ (MW)	16,599.5	15,564.8	14,781.3	6.6	%	5.3	%
Average retail consumers (thousands) ⁽³⁾	248.3	245.3	241.6	1.2	%	1.5	%


⁽¹⁾	Volumetric load consumers are billed on KWh usage.


⁽²⁾	Demand-based load includes consumers billed on a monthly KW peak and also includes retail transmission customers that are primarily billed under rate riders.


⁽³⁾	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 – 2017 compared to 2016

The following table summarizes the significant changes to utility margin:



		Year Ended December 31, 2017
		Change
Utility margin:		(In millions)

	Rate relief – Transmission cost of service rate increases in March and September of 2017 and 2016	$	6.7
	Retail customer usage/load – Weather normalized retail KWh sales increased 1.2%, primarily related to the residential class; the average number of retail consumers increased 1.2%	0.6
	Demand based customer usage/load – Higher demand-based revenues for large commercial and industrial retail consumers; billed demand, excluding retail transmission customers, increased 4.0%	2.5
	Wholesale transmission load – Increased coincidental peak load for third-party transmission customers	1.3
	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	(1.4		)
	Weather – Milder weather in 2017; heating degree days were 13.1% lower	(0.8		)
	Other	(0.1		)
	Net Change	$	8.8

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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, 2017
		Change
Operating expenses:		(In millions)

	Higher allocated corporate depreciation, primarily related to computer software	$	1.9
	Higher outside consulting costs, including vegetation management	2.8
	Higher property taxes due to increased utility plant in service	1.4
	Higher employee related expenses	0.4
	Training costs associated with new software implementation	0.4
	Higher capitalized administrative and general expenses due to higher construction spending in 2017	(1.3		)
	2016 lease abandonment costs associated with building consolidation efforts	(1.0		)
	Other	0.2
	Net Change	$	4.8



Depreciation and amortization:

	Increased utility plant in service	$	3.0
	Reduced CTC amortization and AMS depreciation	(1.0		)
	Net Change	$	2.0



Other income (deductions):

	Higher CIAC	$	0.2
	2016 interest income from IRS, net of related expenses (Note 11)	(0.3		)
	Other	0.5
	Net Change	$	0.4



Interest charges:

	Increase due to the issuance of $60.0 million of long-term debt in February 2016	$	(0.2	)
	Increase due to the issuance of $60.0 million of long-term debt in August 2017	(0.7		)
	Higher debt AFUDC	0.3
	Other	(0.2		)
	Net Change	$	(0.8	)



Income taxes:

	Increase due to higher segment earnings before income taxes	$	(0.5	)
	Decrease due to excess tax benefits related to stock compensation awards (Note 13)	0.6
	Impact of change in federal corporate income tax rate	(7.9		)
	Other	0.1
	Net Change	$	(7.7	)

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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

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)

	Higher 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 CIAC, partially offset by higher equity AFUDC and interest income from IRS (Note 17)	$	(0.5	)

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

	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

Corporate and Other

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



	Year Ended December 31,									Change
	2017			2016			2015			2017/2016			2016/2015
				(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—
Utility margin	—			—			—			—			—
Operating expenses	(22.1		)	(12.8		)	(14.9		)	(9.3		)	2.1
Depreciation and amortization	21.8			14.5			13.9			7.3			0.6
Operating income (loss)	0.4			(1.7		)	0.9			2.1			(2.6		)
Other income (deductions)	4.2			10.4			(0.6		)	(6.2		)	11.0
Interest charges	(14.8		)	(11.8		)	(7.2		)	(3.0		)	(4.6		)
Segment earnings (loss) before income taxes	(10.3		)	(3.2		)	(6.9		)	(7.1		)	3.7
Income (taxes) benefit	(17.3		)	1.5			(3.7		)	(18.8		)	5.2
Segment earnings (loss)	$	(27.6	)	$	(1.7	)	$	(10.6	)	$	(25.9	)	$	8.9

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 increased corporate depreciation rates and computer software. Substantially all depreciation and amortization expense is offset in operating expenses as a result of allocation of these costs to other business segments.

Operating results – 2017 compared to 2016

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



		Year ended December 31, 2017
		Change
Other income (deductions):		(In millions)

	Decrease in interest income on the Westmoreland Loan (Note 16)	$	(3.7	)
	2016 interest income from IRS, net of related expenses (Note 11)	(0.8		)
	Increase in donations, including the PNM Resources Foundation	(1.5		)
	Other	(0.2		)
	Net Change	$	(6.2	)

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		Year ended December 31, 2017
		Change
Interest charges:		(In millions)

	Issuance of the $100.0 million 2016 Two-Year Term Loan in December 2016	$	(2.0	)
	Issuance of the $100.0 million 2016 One-Year Term Loan in December 2016	(1.9		)
	Higher short term borrowings and interest rates	(2.4		)
	Repayment of a $150.0 million PNMR term loan in December 2016	2.0
	Decrease in interest expense on the BTMU Loan Agreement (Note 6)	1.2
	Other	0.1
	Net Change	$	(3.0	)



Income taxes:

	Increase in benefit due to change in segment (earnings) loss before income taxes	$	2.7
	Impact of change in federal corporate income tax rate	(20.0		)
	Other impairments and valuation allowances	(1.1		)
	Other	(0.4		)
	Net Change	$	(18.8	)

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	)

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		Year ended December 31, 2016
		Change
Income taxes:		(In millions)

	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

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

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



	Year Ended December 31,									Change
	2017			2016			2015			2017/2016			2016/2015
	(In millions)
Net cash flows from:
Operating activities	$	524.5		$	415.5		$	386.9		$	109.0		$	28.6
Investing activities	(466.2		)	(699.4		)	(544.5		)	233.2			(154.9		)
Financing activities	(58.8		)	242.4			175.4			(301.2		)	67.0
Net change in cash and cash equivalents	$	(0.5	)	$	(41.5	)	$	17.8		$	41.0		$	(59.3	)

Cash Flows from Operating Activities

Changes in PNMR’s cash flow 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, including the effects of the seasonal nature of the Company’s operations, also impact operating cash flows.

Cash Flows from Investing Activities

The changes in PNMR’s cash flows from investing activities relate primarily to changes in utility plant additions. Cash flows from investing activities also include activity related to the Westmoreland Loan and NMRD. Major components of PNMR’s cash inflows and (outflows) from investing activities are shown below:

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	Year Ended December 31,									Change
	2017			2016			2015			2017/2016			2016/2015
Cash (Outflows) for Utility Plant Additions	(In millions)
PNM:
Generation	$	(74.4	)	$	(84.3	)	$	(193.6	)	$	9.9		$	109.3
Transmission and distribution	(173.4		)	(127.2		)	(182.0		)	(46.2		)	54.8
Purchase of previously leased capacity in PVNGS Unit 2	—			(163.3		)	—			163.3			(163.3		)
Four Corners SCRs	(34.9		)	(40.9		)	—			6.0			(40.9		)
Nuclear fuel	(26.4		)	(29.8		)	(29.2		)	3.4			(0.6		)
	(309.1		)	(445.5		)	(404.8		)	136.4			(40.7		)

TNMP:
Transmission	(60.7		)	(71.5		)	(49.7		)	10.8			(21.8		)
Distribution	(83.5		)	(39.4		)	(58.7		)	(44.1		)	19.3
AMS	(1.3		)	(11.6		)	(16.2		)	10.3			4.6
	(145.5		)	(122.5		)	(124.6		)	(23.0		)	2.1

Corporate and Other:
Computer hardware and software	(19.9		)	(31.0		)	(21.0		)	11.1			(10.0		)
PNMR Development utility plant additions	(25.9		)	(1.1		)	(8.2		)	(24.8		)	7.1
	(45.8		)	(32.1		)	(29.2		)	(13.7		)	(2.9		)
	$	(500.4	)	$	(600.1	)	$	(558.6	)	$	99.7		$	(41.5	)

Cash Inflows (Outflows) on the Westmoreland Loan
Loan origination	$	—		$	(122.3	)	$	—		$	122.3		$	(122.3	)
Principal payments	38.4			30.0			—			8.4			30.0
	$	38.4		$	(92.3	)	$	—		$	130.7		$	(92.3	)

Cash Inflows (Outflows) Related to NMRD
Investments in NMRD	$	(4.1	)	$	—		$	—		$	(4.1	)	$	—
Disbursements from NMRD	12.4			$	—		—			12.4			—
	$	8.3		$	—		$	—		$	8.3		$	—

Cash Flow from Financing Activities

The changes in PNMR’s cash flows from financing activities include:


•	In 2015, PNMR borrowed $150.0 million under the PNMR 2015 Term Loan Agreement and repaid $118.8 million of 9.25% Senior Unsecured Notes with the proceeds; PNMR also increased its borrowings under the PNMR Term Loan Agreement from $100.0 million to $150.0 million


•	In 2015, PNM issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes and repaid a $175.0 million term loan with the proceeds; PNM also drew the remaining capacity of $25.0 million under the $125.0 million PNM Multi-draw Term Loan


•	In 2016, PNMR borrowed $100.0 million under the PNMR One-Year Term Loan (included in short-term borrowings) and $100.0 million under the PNMR Two-Year Loan and repaid the PNMR Term Loan Agreement with the proceeds


•	In 2016, PNM borrowed $175.0 million under the PNM 2016 Term Loan Agreement and repaid the PNM Multi-draw Term Loan with the proceeds


•	NM Capital received net proceeds of $122.5 million under the $125.0 million BTMU Term Loan Agreement in 2016 and utilized the proceeds to provide funds for the Westmoreland Loan; in accordance with the BTMU Term Loan Agreement, NM Capital made principal payments of $42.1 million in 2017 and $32.8 million in 2016


•	In 2017, PNM borrowed $200.0 million under the PNM 2017 Term Loan Agreement and repaid the PNM 2016 Term Loan Agreement with the proceeds


•	PNM successfully remarketed PCRBs of $57.0 million in 2017, $146.0 million in 2016, and $39.3 million in 2015


•	TNMP issued $60.0 million of 3.22% first mortgage bonds in 2017 and $60.0 million of 3.53% first mortgage bonds in 2016

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•	Short-term borrowings increased $18.3 million in 2017 compared to an increase of $86.5 million in 2016 and an increase of $95.0 million in 2015, resulting in a net decrease in cash flows from financing activities of $68.2 million in 2017 and $8.5 million in 2016


•	In 2017, PNM had net repayments of amounts received under transmission interconnection arrangements of $9.4 million compared to net amounts received in 2016 of $4.3 million and net amounts repaid of $2.3 million in 2015

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 a single 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. The Company is in compliance with its debt covenants.

As discussed in Note 16, NM Capital, a wholly-owned subsidiary of PNMR, entered into the $125.0 million BTMU Term Loan Agreement with The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender and administrative agent. The BTMU Term Loan Agreement has a maturity of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 4.13% at December 31, 2017. The principal balance outstanding under the BTMU Term Loan Agreement was $50.1 million at December 31, 2017 and $45.1 million at February 20, 2018. 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 (Note 16) to a ring-fenced, bankruptcy-remote, special-purpose entity, which is a subsidiary of Westmoreland, to finance Westmoreland’s purchase of SJCC.

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 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).

At January 1, 2017, PNM had $37.0 million of outstanding PCRBs, which have a final maturity of June 1, 2040, and $20.0 million of outstanding PCRBs, which have a final maturity of June 1, 2042. These PCRBs were subject to mandatory tender for remarketing on June 1, 2017 and were successfully remarketed on that date. Both series are now subject to mandatory tender for remarketing on June 1, 2022.

On June 14, 2017, TNMP entered into an agreement, which provided that TNMP would issue $60.0 million aggregate principal amount of 3.22% first mortgage bonds on or about August 25, 2017. TNMP issued the 2017 Series A Bonds on August 24, 2017 and used the proceeds to reduce short-term and intercompany debt and for general corporate purposes.

On July 20, 2017, PNM entered into the $200.0 million PNM 2017 Term Loan Agreement, which bears interest at a variable rate and must be repaid on or before January 18, 2019. PNM used the proceeds of the PNM 2017 Term Loan Agreement to prepay the $175.0 million PNM 2016 Term Loan Agreement, which was to mature on November 17, 2017, and to reduce short-term borrowings.

On July 28, 2017, PNM entered into the PNM 2017 Senior Unsecured Note Agreement with institutional investors for the sale of $450.0 million aggregate principal amount of eight series of Senior Unsecured Notes (the “PNM 2018 SUNs”) offered in private placement transactions. PNM has agreed to issue $350.0 million of the PNM 2018 SUNs (at fixed annual interest rates ranging from 3.15% to 4.50% for terms between 5 and 30 years) on or about May 15, 2018 and $100.0 million of the PNM 2018 SUNs (at fixed annual interest rates of 3.78% and 4.60% for terms of 10 and 30 years) on or about August 1, 2018. The issuances of the PNM 2018 SUNs are subject to the satisfaction of customary conditions. PNM will use the gross proceeds from the PNM 2018 SUNs to pay $350.0 million of PNM’s 7.95% Senior Unsecured Notes that mature on May 15, 2018 and $100.0 million of PNM’s 7.50% Senior Unsecured Notes that mature on August 1, 2018.

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On December 21, 2016, PNMR entered into two term loan agreements: (1) the $100.0 million PNMR 2016 One-Year Term Loan that was to mature on December 21, 2017; and (2) the $100.0 million PNMR 2016 Two-Year Term Loan 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. On December 15, 2017, PNMR amended the PNMR 2016 One-Year Term Loan to extend the maturity date to December 14, 2018.

At December 31, 2017, variable interest rates were 2.34% for the PNMR 2015 Term Loan Agreement, 2.32% for the PNMR 2016 One-Year Term Loan (as extended), 2.32% for the PNMR 2016 Two-Year Term Loan, and 2.29% for the PNM 2017 Term Loan Agreement.

PNMR has 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 $150.0 million PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through its maturity on March 9, 2018. In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million, of its variable rate debt. The Finance Committee of the Board has authorized management to enter into additional transactions to hedge against exposure to changes in interest rates on its variable rate debt of up to an additional notional amount of $150.0 million.

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 2018-2022 are:



	2018		2019-2022		Total
	(In millions)
Construction expenditures	$	500.2	$	2,211.9	$	2,712.1
Dividends on PNMR common stock	84.4		337.7		422.1
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	585.1	$	2,551.7	$	3,136.8

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 $7.9 million at Four Corners, $72.8 million for 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, approximately $170 million for an anticipated expansion of PNM’s transmission system, and approximately $100 million in 2021 and $300 million in 2022 for the costs of replacement resources related to the potential shutdown of SJGS Units 1 and 4 in 2022. See Note 17. Expenditures for the expansion of PNM’s transmission system and SJGS replacement resources are subject to obtaining necessary approvals of the NMPRC. PNM will be required to file CCN applications with the NMPRC to obtain those approvals. Expenditures for environmental upgrades are estimated to be $7.9 million in 2018. 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, 2017, PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements and the borrowings discussed in Financing Activities above.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt and term loans that must be paid or refinanced at maturity. The $150.0 million PNMR 2015 Term Loan Agreement matures on March 9, 2018, the $100.0 million PNM 2016 One-Year Term Loan (as extended) matures on December 14, 2018, and the $100 million PNM 2016 Two-Year Term Loan matures on December 21, 2018. Also, $350.0 million of PNM Senior Unsecured Notes mature on May 15, 2018 and $100.0 million of PNM Senior Unsecured Notes mature on August 1, 2018. As described above, PNM entered into the PNM 2017 Senior Unsecured Note Agreement on July 28, 2017. Proceeds from the $450.0 million of the PNM 2018 SUNs to be issued under that agreement will be used to repay the senior unsecured notes that mature on May 15, 2018 and

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August 1, 2018. The BTMU Term Loan Agreement requires that NM Capital 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 $10.6 million on the BTMU Term Loan Agreement in the year ended December 31, 2018, including $5.0 million paid on February 1, 2018. Note 6 contains additional information about the maturities of long-term debt. PNMR and PNM anticipate that funds to repay these 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 in the public or private capital markets, 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. Currently, 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. PNMR and PNM entered into agreements to extend the maturity of the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility to October 31, 2022. 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, 2022. On September 25, 2017, the TNMP Revolving Credit Facility was amended and restated to extend its maturity from September 18, 2018 to September 23, 2022. PNM had the $50.0 million PNM 2014 New Mexico Credit Facility with banks having a significant presence in New Mexico that was scheduled to expire on January 8, 2018. On December 12, 2017, PNM entered into the PNM 2017 New Mexico Credit Facility, a similar $40.0 million unsecured revolving credit facility to replace the PNM 2014 New Mexico Credit Facility. The PNM 2017 New Mexico Credit Facility expires on December 12, 2022. 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 Company expects that it will be able to extend or replace these credit facilities under similar terms and conditions prior to their expirations.

The revolving credit facilities and the PNM 2017 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. Information regarding the range of borrowings for each facility is as follows:



	Three Months Ended				Year Ended December 31
	December 31, 2017				2017				2016				2015
Range of Borrowings	Low		High		Low		High		Low		High		Low		High
	(In millions)
PNM:
PNM Revolving Credit Facility	$	—	$	65.0	$	—	$	65.0	$	—	$	135.0	$	—	$	48.4
PNM New Mexico facilities ⁽¹⁾	—		—		—		26.0		—		50.0		—		20.0
TNMP Revolving Credit Facility	—		23.8		—		53.0		—		70.0		—		64.0
PNMR Revolving Credit Facility	117.7		194.7		111.8		235.3		40.0		179.5		—		45.3

⁽¹⁾ Includes both the PNM 2014 New Mexico Credit Facility and the PNM 2017 New Mexico Credit Facility

At December 31, 2017, the average interest rates were 2.76% for the PNMR Revolving Credit Facility and 2.59% for the PNM Revolving Credit Facility. There were no borrowings outstanding under the PNM 2017 New Mexico Facility or the TNMP Revolving Credit Facility at December 31, 2017.

The Company currently believes that its capital requirements for at least the next twelve months can be met through internal cash generation, existing, extended, or new credit arrangements, and access to public and private capital markets. The Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2018-2022

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period. This could include new debt and/or equity issuances. The Company currently anticipates utilizing a three-year at-the-market equity issuance program to raise equity beginning in 2020 to partially fund capital requirements. This at-the-market program should provide a flexible, efficient, and low-cost way to issue equity as needed. The Company also expects to issue new debt periodically to fund capital investments. 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 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.

PNMR currently has no senior unsecured notes outstanding. 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. In June 2017, Moody’s changed the outlook for PNMR and PNM from stable to positive while maintaining a stable outlook for TNMP. On January 16, 2018, S&P changed the outlook for PNMR, PNM, and TNMP from stable to negative while affirming the ratings set forth below for all the entities. As of February 20, 2018, ratings on the Company’s securities were as follows:



	PNMR	PNM	TNMP
S&P
Issuer 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. However, the ultimate outcomes from PNM’s NM 2015 Rate Case and NM 2016 Rate Case, including the pending appeals before the NM Supreme Court, 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 each rating is subject to revision or withdrawal at any time by the rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements as of February 20, 2018 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 2017 New Mexico Credit Facility	—		40.0		—		40.0
Total financing capacity	$	300.0	$	440.0	$	75.0	$	815.0
Amounts outstanding as of February 20, 2018:
Revolving credit facility	$	182.4	$	57.4	$	23.9	$	263.7
PNM 2017 New Mexico Credit Facility	—		20.0		—		20.0
Letters of credit	6.4		2.5		0.1		9.0
Total short-term debt and letters of credit	188.8		79.9		24.0		292.7
Remaining availability as of February 20, 2018	$	111.2	$	360.1	$	51.0	$	522.3
Invested cash as of February 20, 2018	$	0.9	$	—	$	—	$	0.9

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 20, 2018, PNM and TNMP had no intercompany borrowings from PNMR.

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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.

On February 26, 2018, PNMR Development entered into a $24.5 million revolving credit facility that matures on February 25, 2019. The facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development anticipates using the facility to finance its participation in NMRD (Note 1).

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 $475.0 million of Senior Unsecured Notes that expires in May 2020.

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)
2018	$	18,139
2019	18,139
2020	18,139
2021	18,139
2022	18,139
Thereafter	10,705
Total	$	101,400

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, 2017. See Note 7 for further details about the Company’s significant leases.



	Payments Due
Contractual Obligations	2018		2019-2020		2021-2022		2023 and Thereafter		Total
	(In thousands)
Long-term debt^(a)	$	257,293	$	510,866	$	367,650	$	1,295,698	$	2,431,507
Interest on long-term debt^(b)	110,771		159,647		132,460		708,144		1,111,022
Operating leases ^(c)	26,802		50,846		50,244		60,708		188,600
Transmission service arrangements	16,956		21,102		17,793		9,440		65,291
Coal contracts^(d)	104,782		224,477		192,507		375,941		897,707
Coal mine decommissioning^{(e) (f)}	10,689		22,469		24,498		157,772		215,428
Nuclear decommissioning funding requirements^(f)	2,637		5,274		5,274		—		13,185
SJGS decommissioning funding requirements	—		—		16,920		—		16,920
Outsourcing	4,555		3,430		—		—		7,985
Pension and retiree medical^(g)	1,936		3,778		9,092		—		14,806
Equity contributions to NMRD^(h)	7,700		—		—		—		7,700
Construction expenditures ⁽ⁱ⁾	500,205		1,027,235		1,184,627		—		2,712,067
Total^(j)	$	1,044,326	$	2,029,124	$	2,001,065	$	2,607,703	$	7,682,218


^(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, 2017 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 commitments to fund NMRD for its contractual construction obligations


⁽ⁱ⁾	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

^(j)

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 $9.4 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 and Tri-State hazard sharing agreement 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 2017 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

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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.

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	2017		2016
PNMR common equity	40.9	%	41.1	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	58.8	%	58.6	%
Total capitalization	100.0	%	100.0	%
PNM
PNM common equity	46.0	%	46.0	%
Preferred stock	0.4	%	0.4	%
Long-term debt	53.6	%	53.6	%
Total capitalization	100.0	%	100.0	%
TNMP
Common equity	56.9	%	58.5	%
Long-term debt	43.1	%	41.5	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

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 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.

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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. Management has recently published, with Board oversight, a Climate Change Report available at http://www.pnmresources.com/about-us/sustainability-portal.aspx, that details PNM’s efforts to transition to a coal-free generation portfolio. The Board considers issues associated with climate change, the Company’s GHG exposures, and the financial consequences that might result from potential federal and/or state regulation of GHG.

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 or climate change related regulation on its assets and operations.

GHG Exposures

In 2017, GHG associated with PNM’s interests in its fossil-fueled 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 2015, the latest year for which EPA has published final data, were approximately 6.6 billion metric tons (in CO₂ equivalents), of which approximately 5.4 billion metric tons were CO₂.

As of January 1, 2018, approximately 67.9% 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. This reflects the retirement of SJGS Units 2 and 3 that occurred in December 2017 and the restructuring of ownership in SJGS Unit 4. These events reduced PNM’s entitlement in SJGS from 783 MW to 562 MW and will cause the Company’s output of GHG to decrease in 2018 compared to 2017. Many factors affect the amount of GHG emitted, including plant performance, economic dispatch, and the availability of renewable resources. For example, between 2007 and 2017, production from New Mexico Wind has varied from a high of 580 GWh in 2011 to a low of 405 GWh in 2014. Variations are primarily due to how much and how often the wind blows. In addition, if PVNGS experienced prolonged outages or if PNM’s entitlement from PVNGS were reduced, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG.

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. 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 SJGS Units 2 and 3 is expected to result in a reduction of GHG for the entire station of approximately 50%, including an overall reduction of approximately 40% of GHG from the Company’s owned interests. In addition, as discussed in Note 17, PNM’s 2017 IRP indicates exiting ownership in the remaining SJGS units in 2022 and Four Corners in 2031 would provide long-term cost savings to its customers and would further reduce PNM’s GHG. PNM owns utility-scale solar generation with a total generation capacity of 107 MW. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and, since January 2015, has purchased 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 providing power to PNM in January 2014. The current capacity of the geothermal facility is 4 MW. On November 15, 2017 the NMPRC approved PNM’s 2018 renewable energy procurement plan (Note 17). As a result, PNM will acquire an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; and PNM will construct 50 MW of new solar facilities in 2018. Additionally, PNM has a customer distributed solar generation program that represented 81.6 MW at December 31, 2017. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 180 GWh. PNM has offered its customers a comprehensive portfolio of energy efficiency and load management programs since 2007, with a budget of $23.6 million for the 2018 program year. Cumulative annual savings from these programs were approximately 625 GWh of electricity through 2017. Over the next 20 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 9,600 GWh of electricity, which will avoid at least 5.2 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.

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.

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Other Climate Change Risks

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 generating 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. During the third quarter of 2017, Hurricane Harvey had significant impacts on the Gulf Coast region, including certain areas serviced by TNMP. While Hurricane Harvey did not have a significant impact on TNMP’s facilities, the hurricane impacted customer usage and could impact future usage or create resource constraints that could delay or disrupt the supply of materials necessary to maintain historical levels of system reliability.

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 for emissions from new motor vehicles, 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, the PSD construction permit and Title V operating permit programs, to avoid impacting millions of small GHG emitters. On June 23, 2014, the US Supreme Court found EPA lacked authority to “tailor” the CAA’s unambiguous numerical thresholds of 100 or 250 tons per year, and thus held EPA may not require a source to obtain a PSD permit solely on the basis of its potential GHG emissions. However, the court upheld EPA’s authority to apply the PSD program for GHGs to “anyway” sources – those sources that have to comply with the PSD program for other non-GHG pollutants.

On June 25, 2013, then 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.

On August 3, 2015, EPA responded to the Climate Action Plan by issuing three separate but related actions: (1) the final Carbon Pollution Standards for new, modified, and reconstructed power plants (under Section 111(b)); (2) the final Clean Power Plan for existing power plants (under Section 111(d)); and (3) a proposed federal plan associated with the final Clean Power Plan.

EPA’s Carbon Pollution Standards for new sources (those constructed after January 8, 2014) established separate standards for gas- and coal-fired units. The standards reflect the degree of emission limitation achievable through the application of what EPA determined to be the best system of emission reduction (“BSER”) demonstrated for each type of unit. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, EPA finalized a standard based on efficient natural gas combined cycle technology. The final standards for coal-fired power plants vary depending on whether the unit is new, modified, or reconstructed.

The final Clean Power Plan established numeric “emission standards” for existing electric generating units – 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.

Multiple states, utilities, and trade groups filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. The DC Circuit first refused to stay the rule, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. As a result, the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a 10-judge

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en banc panel. However, before the DC Circuit could issue an opinion, President Trump took office and his administration asked the court to hold the case in abeyance while the rule is re-evaluated, which the court granted.

On March 28, 2017, President Trump issued an Executive Order titled “Promoting Energy Independence and Economic Growth.” Among its goals are to “promote clean and safe development of our Nation’s vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.” The order rescinds several key pieces of the Obama Administration’s climate agenda, including the Climate Action Plan and the Final Guidance on Consideration of Climate Change in NEPA Reviews. It directs agencies to review and suspend, revise or rescind any regulations or agency actions that potentially burden the development or use of domestically produced energy resources.

Most notably, the order directs EPA to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Carbon Pollution Standards for new, reconstructed or modified electric utilities, (2) the Clean Power Plan, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. In response, the EPA signed a NOPR to repeal the Clean Power Plan on October 10, 2017. The notice proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. EPA recently announced that it will continue to accept comments on that proposed interpretation until April 26, 2018. Any final rule will likely be subject to judicial review. EPA indicated it has not determined whether it will promulgate a new rule under section 111(d) or what form a new rule would take, but it did seek comment on that question in a separate advanced notice of proposed rulemaking published December 28, 2017.

PNM is unable to predict the impact to the Company of this Executive Order or the potential repeal of the Clean Power Plan. It is uncertain the direction EPA will take, if any, to replace the existing rule. If a future regulation limiting GHG from fossil-fueled EGUs is adopted, such regulations could impact PNM’s existing and future fossil-fueled EGUs. The existing Carbon Pollution Standards covering new sources could also impact PNM’s generation fleet, although that rule remains under review by EPA and the DC Circuit.

Federal Legislation

Prospects for enactment in Congress of legislation imposing a new or enhanced regulatory program to address climate change are highly unlikely in 2018.

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. As discussed in Note 17, in its 2017 IRP, PNM analyzed resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assumed SJGS will cease operations by the end of 2022. The key findings of the 2017 IRP include that exiting SJGS in 2022 would provide long-term cost benefits to PNM’s customers and that PNM exiting its ownership interest in Four Corners in 2031 would also save customers money. The materials presented in the IRP process are available at www.pnm.com\irp.

On August 30, 2017, Western Resource Advocates provided the NMPRC with a presentation on a proposed rulemaking for the adoption of a clean energy standard in New Mexico and a suggestion that the NMPRC issue a NOPR. The NMAG’s office and Prosperity Works joined in the petition. The proposed clean energy standard, if adopted, would require utilities to reduce carbon emissions by four percent per year for the next 20 years. The NMPRC has convened a series of workshops to develop a clean energy standard rule that could be proposed for a future rulemaking proceeding. The major topic areas discussed at the workshops are: jurisdictional and other legal issues; selection of the timeframe for the emissions baseline year to be used, unspecified power, and electric vehicle credits; and cost responsibilities, benefits, reasonable cost threshold, impact on rates, compliance issues, reliability impacts and unintended consequences. Workshops are scheduled to continue in 2018.

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International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994. The objective of the treaty is to “stabilize greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” Parties 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.

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, then 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 former administration to have the United States achieve economy-wide reductions of around 80% by 2050. The former 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. The United States was one of 189 nations that offered intended NDCs. 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, 174 countries have ratified the Paris Agreement. On June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. In his public statement, he indicated that the United States would "begin negotiations to reenter either the Paris Accord or a .... new transaction on terms that are fair to the United States, its businesses, its workers, its people, its taxpayers." To date there have been no specific details as to how this will be accomplished.

PNM will continue to monitor the United States’ involvement in international accords, but the potential impact that such accords may have on the Company cannot be determined at this time.

Assessment of Legislative/Regulatory Impacts

The Company has assessed, and continues to assess, the impacts of climate change legislation and 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 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.

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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. The Trump Administration has indicated that the provisions of the Dodd-Frank Reform Act will be reviewed and certain regulations may be rolled back, but no formal action has been taken yet. At this time, PNM cannot predict the ultimate impact the Dodd-Frank Reform Act may have on PNM’s financial condition, results of operations, cash flows, or liquidity.

Other Matters

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Unbilled Revenues

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

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Regulatory Accounting

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

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

The Company has made adjustments to regulatory assets and liabilities 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 2017, the Company utilized a qualitative 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, 2017. Since the annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. The annual testing was based on certain critical estimates and assumptions. Changes in the estimates or the use of different assumptions could affect the determination of fair value and the conclusion of impairment for each reporting unit.

Application of the qualitative goodwill impairment test requires evaluating various events and circumstances to determine whether it is not more likely than not that the fair value of a reporting unit is less than its carrying amount. As a part of the Company’s goodwill qualitative testing process for a reporting unit, various factors that are specific to the reporting unit as well as industry and macroeconomic factors are evaluated in order to determine whether these factors are reasonably likely to have a material impact on the fair value of the reporting unit. Examples of the factors that were considered in the qualitative testing of the goodwill include the results of the most recent quantitative impairment test, current and long-term forecasted financial results, regulatory environment, credit rating, changes in the interest rate environment, and operating strategy for the reporting unit. Based on the qualitative analysis performed in 2017 for both the PNM and TNMP reporting units, the Company concluded that there were no changes that were reasonably likely to cause the fair value of the reporting units to be less than their carrying value and determined that there was no impairment of goodwill. Although the Company believes all relevant factors were considered in the qualitative impairment analysis to reach the conclusion that goodwill is not impaired, significant changes in any one of the assumptions could produce a significantly different result potentially leading to the recording of an impairment that could have significant impacts on the results of operations and financial position of the Company.

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 80% of PNM’s ARO liability. A 10% increase in the estimates of future de

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commissioning costs at current price levels would have increased the ARO liability by $10.7 million at December 31, 2017. PVNGS Units 1 and 2 are included in PNM’s retail rates while PVNGS Unit 3 was excluded through 2017, but is 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 $5.3 million at December 31, 2017. 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.

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 for additional information, including a discussion of the impacts of tax reform under the Tax Cuts and Jobs Act enacted on December 22, 2017.

MD&A FOR PNM

RESULTS OF OPERATIONS

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

MD&A FOR TNMP

RESULTS OF OPERATIONS

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

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE 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


•	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, 2017 and 2016, 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, 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.



	Year Ended December 31,
	2017			2016
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	2,885		$	4,576
Amount realized on contracts delivered during period	(2,640		)	(316		)
Changes in fair value	(235		)	(1,261		)
Net mark-to-market change recorded in earnings	(2,875		)	(1,577		)
Net change recorded as regulatory liability	(104		)	(114		)
Net fair value at end of period	$	(94	)	$	2,885

All of the fair values as of December 31, 2017 were determined based on prices provided by external sources other than actively quoted market prices. All of the mark-to-market amounts will settle in 2018.

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 wholesale activities not covered by the FPPAC 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

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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, 2017, the high, low, and average VaR amounts were $0.7 million, $0.1 million, and $0.3 million. 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. At December 31, 2017 and December 31, 2016, the VaR amounts for the PNM wholesale portfolio were $0.3 million and $0.6 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 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 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 2017 or 2016.

PNM has significantly reduced its market risk exposure through the inclusion of PVNGS Unit 3 in New Mexico retail rates and the hedging, through June 2022, of 36 MW of the 65 MW of SJGS Unit 4, which is treated as merchant plant. As a result, PNM is reviewing its risk level and associated processes, including the use of VaR as a risk metric.

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, 2017



Rating ⁽¹⁾	Credit Risk Exposure⁽²⁾		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	2,534	1	$	650
Non-investment grade	1		—	—
Split ratings	210		—	—
Internal ratings:
Investment grade	84		—	—
Non-investment grade	3,027		1	2,957
Total	$	5,856		$	3,607


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

⁽²⁾

The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers and the Tri-State hazard sharing agreement), forward sales, and short-term sales. The gross 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, 2017, PNMR held $0.9 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of December 31, 2017 was $3.0 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

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mining operations of SJCC. PNMR is exposed to credit risk under these arrangements in the event of default by WSJ. As of February 20, 2018, remaining required principal payments under the Westmoreland Loan are $2.7 million in 2018 (after reflecting the $5.6 million paid on February 1, 2018), $8.6 million in 2019, $23.3 million in 2020, and $16.4 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 not 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 1.6%, 1.3%, and 3.5%, if interest rates were to decline by 50 basis points from their levels at December 31, 2017. In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. At February 20, 2018, PNMR, PNM, and TNMP had $182.4 million, $57.4 million, and $23.9 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 $20.0 million under the $40.0 million PNM 2017 New Mexico Credit Facility at February 20, 2018. The revolving credit facilities, the PNM 2017 New Mexico Credit Facility, the $150.0 million PNMR 2015 Term Loan Agreement, the $100.0 million PNMR 2016 One-Year Term Loan Agreement (as extended), the $100.0 million PNMR 2016 Two-Year Term Loan Agreement, the $200.0 million PNM 2017 Term Loan Agreement, and the $125.0 million BTMU Term Loan Agreement bear interest at variable rates. On February 20, 2018, interest rates on borrowings averaged 2.83% for the PNMR Revolving Credit Facility, 2.48% for the PNMR 2015 Term Loan Agreement, 4.32% for the BTMU Term Loan Agreement, 2.39% for the PNMR 2016 One-Year Term Loan Agreement (as extended), 2.35% for the PNMR 2016 Two-Year Term Loan Agreement, 2.71% for the PNM Revolving Credit Facility, 2.70% for the PNM 2017 New Mexico Credit Facility, 2.30% for the PNM 2017 Term Loan Agreement, and 2.33% for the TNMP Revolving Credit Facility. The Company is exposed to interest rate risk to the extent of future increases in variable interest rates. However, as discussed in Note 6, PNMR has entered into hedging arrangements to effectively establish fixed interest rates on the PNMR 2015 Term Loan Agreement and $150.0 million of variable rate debt.

The investments held by PNM in trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits had an estimated fair value of $967.0 million at December 31, 2017, of which 55.8% were fixed-rate debt securities that subject PNM to risk of loss of fair value with increases in market interest rates. If interest rates were to increase by 50 basis points from their levels at December 31, 2017, the decrease in the fair value of the fixed-rate securities would be 6.8%, or $36.7 million. Due to the funded status of the nuclear decommissioning trust and overall market performance, PNM began to re-balance the decommissioning investment portfolio in late 2017 to increase the percentage of the investments in fixed income (debt) securities to approximately 85%. The portfolio re-balancing was completed in early 2018 and is expected to increase the exposure related to interest rate risk and reduce the equity market risk referenced below. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $73.7 million at December 31, 2017, of which 59.2% 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, 2017, the decrease in the fair value of the fixed-rate securities would be 8.2%, or $3.6 million.

PNM and TNMP do not directly recover or return through rates any losses or gains on the securities, including equity and alternative investments discussed below, in the trusts for decommissioning, reclamation, pension benefits, and other post-employment benefits. However, the overall performance of these trusts does enter into the periodic determinations of expense and funding levels, which are factored into the rate making process to the extent applicable to regulated operations. 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, 2017. These equity securities expose PNM and TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 30.3% and 25.5% of the securities held by the various PNM and TNMP trusts as of December 31, 2017. A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $29.3 million for PNM and $1.9 million for TNMP.

Alternatives Investment Risk

The Company had 13.6% of its pension assets invested in the alternatives asset class as of December 31, 2017. 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 Cash Flows		B - 24
Consolidated Balance Sheets		B - 26
Consolidated Statements of Changes in Common Stockholder’s Equity		B - 28
Notes to Consolidated Financial Statements		B - 29
Supplementary Data:
Schedule I - Condensed Financial Information of Parent Company		B - 123
Schedule II - Valuation and Qualifying Accounts		B - 126

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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, 2017.

The effectiveness of our internal control over financial reporting as of and for the year ended December 31, 2017 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their audit report 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

B - 2

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

Management assessed the effectiveness of PNM’s internal control over financial reporting based on the Internal Control – Integrated Framework (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, 2017.

/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, 2017.

/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 Stockholders and Board of Directors

PNM Resources, Inc.:

Opinions on the Consolidated Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of PNM Resources, Inc. and subsidiaries (the Company) as of December 31, 2017 and 2016, 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, 2017, the related notes and financial statement Schedule I – Condensed Financial Information of Parent Company and Schedule II – Valuation and Qualifying Accounts (collectively, the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Basis for Opinion

The Company’s management is responsible for these consolidated financial statements, 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 consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

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

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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.

/s/ KPMG LLP

We have served as the Company’s auditor since 2013.

Albuquerque, New Mexico

March 1, 2018

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Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors

Public Service Company of New Mexico:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Public Service Company of New Mexico and subsidiaries (the Company) as of December 31, 2017 and 2016, 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, 2017, the related notes and Schedule II – Valuation and Qualifying Accounts (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2013.

Albuquerque, New Mexico

March 1, 2018

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Report of Independent Registered Public Accounting Firm

The Stockholder and Board of Directors

Texas‑New Mexico Power Company:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Texas‑New Mexico Power Company and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of earnings, 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, 2017, the related notes and Schedule II – Valuation and Qualifying Accounts (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

/s/ KPMG LLP

We have served as the Company’s auditor since 2013.

Albuquerque, New Mexico

March 1, 2018

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EARNINGS



	Year Ended December 31,
	2017			2016			2015
	(In thousands, except per share amounts)
Electric Operating Revenues	$	1,445,003		$	1,362,951		$	1,439,082
Operating Expenses:
Cost of energy	407,479			380,596			464,649
Administrative and general	186,345			191,514			179,100
Energy production costs	137,450			146,187			176,752
Regulatory disallowances and restructuring costs	27,036			15,011			167,471
Depreciation and amortization	231,942			209,110			185,919
Transmission and distribution costs	71,576			66,227			69,157
Taxes other than income taxes	76,690			76,321			71,684
Total operating expenses	1,138,518			1,084,966			1,314,732
Operating income	306,485			277,985			124,350
Other Income and Deductions:
Interest income	15,916			22,293			6,498
Gains on available-for-sale securities	27,161			19,517			16,060
Other income	19,515			17,796			26,833
Other (deductions)	(15,693		)	(13,784		)	(12,728		)
Net other income and deductions	46,899			45,822			36,663
Interest Charges	127,625			128,633			114,860
Earnings before Income Taxes	225,759			195,174			46,153
Income Taxes	130,340			63,278			15,075
Net Earnings	95,419			131,896			31,078
(Earnings) Attributable to Valencia Non-controlling Interest	(15,017		)	(14,519		)	(14,910		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Net Earnings Attributable to PNMR	$	79,874		$	116,849		$	15,640
Net Earnings Attributable to PNMR per Common Share:
Basic	$	1.00		$	1.47		$	0.20
Diluted	$	1.00		$	1.46		$	0.20

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,
	2017			2016			2015
	(In thousands)
Net Earnings	$	95,419		$	131,896		$	31,078
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(10,927), $(304), and $(4,310)	17,233			474			6,688
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $6,816, $8,639, and $11,181	(10,751		)	(13,500		)	(17,350		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $(919), $7,219, and $1,726	2,699			(11,282		)	(2,679		)
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,504), $(2,148), and $(2,332)	3,948			3,356			3,620
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $(388), $341, and $(28)	612			(533		)	44
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $(225), $(298), and $0	356			466			—
Total Other Comprehensive Income (Loss)	14,097			(21,019		)	(9,677		)
Comprehensive Income	109,516			110,877			21,401
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(15,017		)	(14,519		)	(14,910		)
Preferred Stock Dividend Requirements of Subsidiary	(528		)	(528		)	(528		)
Comprehensive Income Attributable to PNMR	$	93,971		$	95,830		$	5,963

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,
	2017			2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	95,419		$	131,896		$	31,078
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	268,194			242,033			222,861
Deferred income tax expense	130,528			63,805			16,451
Net unrealized (gains) losses on commodity derivatives	2,875			1,577			5,188
Realized (gains) on available-for-sale securities	(27,161		)	(19,517		)	(16,060		)
Stock based compensation expense	6,194			5,634			4,863
Regulatory disallowances and restructuring costs	27,036			15,011			167,471
Allowance for equity funds used during construction	(9,516		)	(4,949		)	(10,430		)
Other, net	2,329			3,060			3,934
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(1,846		)	2,543			(3,298		)
Materials, supplies, and fuel stock	1,473			(4,169		)	(180		)
Other current assets	32,298			(2,469		)	29,370
Other assets	(5,486		)	(42,864		)	2,369
Accounts payable	14,468			3,159			(32,269		)
Accrued interest and taxes	(327		)	3,345			4,957
Other current liabilities	(6,513		)	(12,509		)	2,633
Other liabilities	(5,503		)	29,868			(42,064		)
Net cash flows from operating activities	524,462			415,454			386,874
Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(500,461		)	(600,076		)	(558,589		)
Proceeds from sales of available-for-sale securities	637,492			522,601			252,174
Purchases of available-for-sale securities	(650,284		)	(538,383		)	(262,548		)
Return of principal on PVNGS lessor notes	—			8,547			21,694
Investments in NMRD	(4,077		)	—			—
Disbursements from NMRD	12,415			—			—
Investment in Westmoreland Loan	—			(122,250		)	—
Principal repayments on Westmoreland Loan	38,360			30,000			—
Other, net	392			186			2,741
Net cash flows from investing activities	(466,163		)	(699,375		)	(544,528		)

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,
	2017			2016			2015
	(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	18,300			86,500			95,000
Long-term borrowings	317,000			603,500			463,605
Repayment of long-term debt	(274,070		)	(303,793		)	(333,066		)
Proceeds from stock option exercise	1,739			7,028			5,619
Awards of common stock	(13,929		)	(15,451		)	(17,720		)
Dividends paid	(77,792		)	(70,623		)	(64,251		)
Valencia’s transactions with its owner	(17,742		)	(17,006		)	(17,049		)
Amounts received under transmission interconnection arrangements	11,879			7,171			27
Refunds paid under transmission interconnection arrangements	(21,290		)	(2,830		)	(2,338		)
Other, net	(2,942		)	(2,104		)	(4,396		)
Net cash flows from financing activities	(58,847		)	242,392			175,431
Change in Cash and Cash Equivalents	(548		)	(41,529		)	17,777
Cash and Cash Equivalents at Beginning of Year	4,522			46,051			28,274
Cash and Cash Equivalents at End of Year	$	3,974		$	4,522		$	46,051
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	120,955		$	115,043		$	103,382
Income taxes paid (refunded), net	$	625		$	(307	)	$	(1,890	)

Supplemental schedule of noncash investing and financing activities:
(Increase) decrease in accrued plant additions	$	(25,261	)	$	18,345		$	(19,080	)
Contribution of utility plant to NMRD	$	24,829

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,
	2017		2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	3,974	$	4,522
Accounts receivable, net of allowance for uncollectible accounts of $1,081 and $1,209	90,473		87,012
Unbilled revenues	54,055		58,284
Other receivables	17,582		28,245
Current portion of Westmoreland Loan	3,576		38,360
Materials, supplies, and fuel stock	66,502		73,027
Regulatory assets	2,933		3,855
Commodity derivative instruments	1,088		5,224
Income taxes receivable	6,879		6,066
Other current assets	47,358		73,444
Total current assets	294,420		378,039
Other Property and Investments:
Long-term portion of Westmoreland Loan	53,064		56,640
Available-for-sale securities	323,524		272,977
Equity investment in NMRD	16,510		—
Other investments	503		547
Non-utility property	3,404		3,404
Total other property and investments	397,005		333,568
Utility Plant:
Plant in service, held for future use, and to be abandoned	7,238,285		6,944,534
Less accumulated depreciation and amortization	2,592,692		2,334,938
	4,645,593		4,609,596
Construction work in progress	245,933		208,206
Nuclear fuel, net of accumulated amortization of $43,524 and $43,905	88,701		86,913
Net utility plant	4,980,227		4,904,715
Deferred Charges and Other Assets:
Regulatory assets	600,672		501,223
Goodwill	278,297		278,297
Commodity derivative instruments	3,556		—
Other deferred charges	91,926		75,238
Total deferred charges and other assets	974,451		854,758
	$	6,646,103	$	6,471,080

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,
	2017			2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	305,400		$	287,100
Current installments of long-term debt	256,895			273,348
Accounts payable	121,383			86,705
Customer deposits	11,028			11,374
Accrued interest and taxes	62,357			61,871
Regulatory liabilities	2,309			3,609
Commodity derivative instruments	1,182			2,339
Dividends declared	21,240			19,448
Other current liabilities	53,850			59,314
Total current liabilities	835,644			805,108
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	2,180,750			2,119,364
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	547,210			940,650
Regulatory liabilities	933,578			455,649
Asset retirement obligations	146,679			127,519
Accrued pension liability and postretirement benefit cost	94,003			125,844
Commodity derivative instruments	3,556			—
Other deferred credits	131,706			140,545
Total deferred credits and other liabilities	1,856,732			1,790,207
Total liabilities	4,873,126			4,714,679
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)	1,157,665			1,163,661
Accumulated other comprehensive income (loss), net of income taxes	(95,940		)	(92,451		)
Retained earnings	633,528			604,742
Total PNMR common stockholders’ equity	1,695,253			1,675,952
Non-controlling interest in Valencia	66,195			68,920
Total equity	1,761,448			1,744,872
	$	6,646,103		$	6,471,080

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, 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, as originally reported	1,163,661			(92,451		)	604,742			1,675,952			68,920			1,744,872
Cumulative effect adjustment (Note 13)	—			—			10,382			10,382			—			10,382
Balance at January 1, 2017, as adjusted	1,163,661			(92,451		)	615,124			1,686,334			68,920			1,755,254
Reclassification of stranded income taxes resulting from tax reform (Note 11)	—			(17,586		)	17,586			—			—			—
Net earnings before subsidiary preferred stock dividends	—			—			80,402			80,402			15,017			95,419
Total other comprehensive income	—			14,097			—			14,097			—			14,097
Subsidiary preferred stock dividends	—			—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—			—			(79,056		)	(79,056		)	—			(79,056		)
Proceeds from stock option exercise	1,739			—			—			1,739			—			1,739
Awards of common stock	(13,929		)	—			—			(13,929		)	—			(13,929		)
Stock based compensation expense	6,194			—			—			6,194			—			6,194
Valencia’s transactions with its owner	—			—			—			—			(17,742		)	(17,742		)
Balance at December 31, 2017	$	1,157,665		$	(95,940	)	$	633,528		$	1,695,253		$	66,195		$	1,761,448

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,
	2017			2016			2015
	(In thousands)
Electric Operating Revenues	$	1,104,230		$	1,035,913		$	1,131,195
Operating Expenses:
Cost of energy	321,677			299,714			391,131
Administrative and general	172,446			169,209			161,953
Energy production costs	137,450			146,187			176,752
Regulatory disallowances and restructuring costs	27,036			15,011			167,471
Depreciation and amortization	147,017			133,447			115,717
Transmission and distribution costs	42,370			39,657			43,642
Taxes other than income taxes	43,709			44,598			41,149
Total operating expenses	891,705			847,823			1,097,815
Operating income	212,525			188,090			33,380
Other Income and Deductions:
Interest income	8,454			10,173			6,574
Gains on available-for-sale securities	27,161			19,517			16,060
Other income	13,527			12,088			19,347
Other (deductions)	(10,002		)	(9,539		)	(8,493		)
Net other income and deductions	39,140			32,239			33,488
Interest Charges	82,697			87,469			79,950
Earnings (Loss) before Income Taxes	168,968			132,860			(13,082		)
Income Taxes (Benefit)	81,555			40,922			(12,758		)
Net Earnings (Loss)	87,413			91,938			(324		)
(Earnings) Attributable to Valencia Non-controlling Interest	(15,017		)	(14,519		)	(14,910		)
Net Earnings (Loss) Attributable to PNM	72,396			77,419			(15,234		)
Preferred Stock Dividends Requirements	(528		)	(528		)	(528		)
Net Earnings (Loss) Available for PNM Common Stock	$	71,868		$	76,891		$	(15,762	)

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,
	2017			2016			2015
	(In thousands)
Net Earnings (Loss)	$	87,413		$	91,938		$	(324	)
Other Comprehensive Income (Loss):
Unrealized Gains on Available-for-Sale Securities:
Unrealized holding gains arising during the period, net of income tax (expense) of $(10,927), $(304), and $(4,310)	17,233			474			6,688
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $6,816, $8,639, and $11,181	(10,751		)	(13,500		)	(17,350		)
Pension Liability Adjustment:
Experience gains (losses), net of income tax (expense) benefit of $(919), $7,219, and $1,726	2,699			(11,282		)	(2,679		)
Reclassification adjustment for amortization of experience (gains) losses recognized as net periodic benefit cost, net of income tax expense (benefit) of $(2,504), $(2,148), and $(2,332)	3,948			3,356			3,620
Total Other Comprehensive Income (Loss)	13,129			(20,952		)	(9,721		)
Comprehensive Income (Loss)	100,542			70,986			(10,045		)
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(15,017		)	(14,519		)	(14,910		)
Comprehensive Income (Loss) Attributable to PNM	$	85,525		$	56,467		$	(24,955	)

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,
	2017			2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings (loss)	$	87,413		$	91,938		$	(324	)
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	180,500			166,047			150,538
Deferred income tax expense	82,549			53,119			(2,836		)
Net unrealized (gains) losses on commodity derivatives	2,875			1,577			5,188
Realized (gains) on available-for-sale securities	(27,161		)	(19,517		)	(16,060		)
Regulatory disallowances and restructuring costs	27,036			15,011			167,471
Allowance for equity funds used during construction	(8,664		)	(4,163		)	(10,430		)
Other, net	2,615			3,046			2,794
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(419		)	4,769			(2,515		)
Materials, supplies, and fuel stock	3,542			(3,924		)	381
Other current assets	32,775			1,127			23,693
Other assets	15,121			(23,880		)	4,194
Accounts payable	9,736			5,614			(31,139		)
Accrued interest and taxes	21,523			(9,601		)	(5,343		)
Other current liabilities	(11,099		)	(12,136		)	(275		)
Other liabilities	(9,389		)	20,119			(33,503		)
Net cash flows from operating activities	408,953			289,146			251,834
Cash Flows From Investing Activities:
Utility plant additions	(309,142		)	(445,464		)	(404,840		)
Proceeds from sales of available-for-sale securities	637,492			522,601			252,174
Purchases of available-for-sale securities	(650,284		)	(538,383		)	(262,548		)
Return of principal on PVNGS lessor notes	—			8,547			21,694
Other, net	33			171			2,935
Net cash flows from investing activities	(321,901		)	(452,528		)	(390,585		)

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,
	2017			2016			2015
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(21,200		)	61,000			—
Long-term borrowings	257,000			321,000			313,605
Repayment of long-term debt	(232,000		)	(271,000		)	(214,300		)
Equity contribution from parent	—			28,142			175,000
Valencia’s transactions with its owner	(17,742		)	(17,006		)	(17,049		)
Dividends paid	(61,223		)	(4,670		)	(94,968		)
Amounts received under transmission interconnection arrangements	11,879			7,171			27
Refunds paid under transmission interconnection arrangements	(21,290		)	(2,830		)	(2,338		)
Other, net	(1,692		)	(1,239		)	(3,568		)
Net cash flows from financing activities	(86,268		)	120,568			156,409

Change in Cash and Cash Equivalents	784			(42,814		)	17,658
Cash and Cash Equivalents at Beginning of Year	324			43,138			25,480
Cash and Cash Equivalents at End of Year	$	1,108		$	324		$	43,138

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	77,960		$	82,514		$	69,936
Income taxes paid (refunded), net	$	(23,391	)	$	(967	)	$	(1,450	)

Supplemental schedule of noncash investing activities:
(Increase) decrease in accrued plant additions	$	(11,792	)	$	22,433		$	(17,469	)

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,
	2017		2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,108	$	324
Accounts receivable, net of allowance for uncollectible accounts of $1,081 and $1,209	67,227		65,003
Unbilled revenues	43,869		48,289
Other receivables	14,541		25,514
Affiliate receivables	9,486		8,886
Materials, supplies, and fuel stock	60,859		64,401
Regulatory assets	2,139		3,442
Commodity derivative instruments	1,088		5,224
Income taxes receivable	3,410		25,807
Other current assets	39,904		67,355
Total current assets	243,631		314,245
Other Property and Investments:
Available-for-sale securities	323,524		272,977
Other investments	283		316
Non-utility property	96		96
Total other property and investments	323,903		273,389
Utility Plant:
Plant in service, held for future use, and to be abandoned	5,501,070		5,359,211
Less accumulated depreciation and amortization	2,029,534		1,809,528
	3,471,536		3,549,683
Construction work in progress	204,079		158,122
Nuclear fuel, net of accumulated amortization of $43,524 and $43,905	88,701		86,913
Net utility plant	3,764,316		3,794,718
Deferred Charges and Other Assets:
Regulatory assets	459,239		365,413
Goodwill	51,632		51,632
Commodity derivative instruments	3,556		—
Other deferred charges	75,286		68,149
Total deferred charges and other assets	589,713		485,194
	$	4,921,563	$	4,867,546

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,
	2017			2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	39,800		$	61,000
Current installments of long-term debt	23			231,880
Accounts payable	77,094			55,566
Affiliate payables	22,875			23,183
Customer deposits	11,028			11,374
Accrued interest and taxes	33,945			34,819
Regulatory liabilities	784			3,517
Commodity derivative instruments	1,182			2,339
Dividends declared	132			132
Other current liabilities	31,633			33,551
Total current liabilities	218,496			457,361
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	1,657,887			1,399,489
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	449,012			748,666
Regulatory liabilities	754,441			423,701
Asset retirement obligations	145,707			126,601
Accrued pension liability and postretirement benefit cost	86,124			114,427
Commodity derivative instruments	3,556			—
Other deferred credits	106,442			118,980
Total deferred credits and liabilities	1,545,282			1,532,375
Total liabilities	3,421,665			3,389,225
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			1,264,918
Accumulated other comprehensive income (loss), net of income taxes	(97,093		)	(92,428		)
Retained earnings	254,349			225,382
Total PNM common stockholder’s equity	1,422,174			1,397,872
Non-controlling interest in Valencia	66,195			68,920
Total equity	1,488,369			1,466,792
	$	4,921,563		$	4,867,546

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, 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 contribution 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 contributions 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
Reclassification of stranded income taxes resulting from tax reform (Note 11)	—		(17,794		)	17,794			—			—			—
Net earnings	—		—			72,396			72,396			15,017			87,413
Total other comprehensive income	—		13,129			—			13,129			—			13,129
Dividends declared on preferred stock	—		—			(528		)	(528		)	—			(528		)
Dividends declared on common stock	—		—			(60,695		)	(60,695		)	—			(60,695		)
Valencia’s transactions with its owner	—		—			—			—			(17,742		)	(17,742		)
Balance at December 31, 2017	$	1,264,918	$	(97,093	)	$	254,349		$	1,422,174		$	66,195		$	1,488,369

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,
	2017			2016			2015
	(In thousands)

Electric Operating Revenues	$	340,773		$	327,038		$	307,887
Operating Expenses:
Cost of energy	85,802			80,882			73,518
Administrative and general	39,828			39,423			36,755
Depreciation and amortization	63,146			61,126			56,285
Transmission and distribution costs	29,206			26,570			25,515
Taxes other than income taxes	29,187			27,396			25,781
Total operating expenses	247,169			235,397			217,854
Operating income	93,604			91,641			90,033
Other Income and Deductions:
Other income	4,994			4,629			4,240
Other (deductions)	(1,443		)	(1,427		)	(504		)
Net other income and deductions	3,551			3,202			3,736
Interest Charges	30,084			29,335			27,681
Earnings before Income Taxes	67,071			65,508			66,088
Income Taxes	31,512			23,836			24,125
Net Earnings	$	35,559		$	41,672		$	41,963

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,
	2017			2016			2015
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	35,559		$	41,672		$	41,963
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	64,939			62,866			57,909
Deferred income tax expense	27,275			12,662			20,883
Allowance for equity funds used during construction and other, net	(1,120		)	(772		)	18
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(1,427		)	(2,226		)	(783		)
Materials and supplies	(2,069		)	(245		)	(561		)
Other current assets	(1,253		)	(621		)	3,928
Other assets	(20,967		)	(19,126		)	(2,310		)
Accounts payable	2,419			(2,040		)	(1,782		)
Accrued interest and taxes	(15,962		)	12,690			4,317
Other current liabilities	(2,236		)	298			1,019
Other liabilities	1,334			6,822			(9,823		)
Net cash flows from operating activities	86,492			111,980			114,778
Cash Flows From Investing Activities:
Utility plant additions	(145,495		)	(122,518		)	(124,584		)
Net cash flows from investing activities	(145,495		)	(122,518		)	(124,584		)

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,
	2017			2016			2015
	(In thousands)

Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	—			(59,000		)	54,000
Short-term borrowings (repayments) – affiliate, net	(4,600		)	(7,200		)	(10,900		)
Long-term borrowings	60,000			60,000			—
Equity contribution from parent	50,000			50,000			—
Dividends paid	(44,389		)	(31,817		)	(33,248		)
Other, net	(979		)	(775		)	(46		)
Net cash flows from financing activities	60,032			11,208			9,806
Change in Cash and Cash Equivalents	1,029			670			—
Cash and Cash Equivalents at Beginning of Year	671			1			1
Cash and Cash Equivalents at End of Year	$	1,700		$	671		$	1
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	29,251		$	26,766		$	26,216
Income taxes paid, (refunded) net	$	21,436		$	660		$	290

Supplemental schedule of noncash investing and financing activities:
(Increase) decrease in accrued plant additions	$	(15,737	)	$	(1,271	)	$	(5	)

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,
	2017		2016
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1,700	$	671
Accounts receivable	23,246		22,009
Unbilled revenues	10,186		9,995
Other receivables	2,860		2,090
Affiliate receivables	336		—
Materials and supplies	5,643		8,626
Regulatory assets	794		413
Other current assets	1,131		1,031
Total current assets	45,896		44,835
Other Property and Investments:
Other investments	220		231
Non-utility property	2,240		2,240
Total other property and investments	2,460		2,471
Utility Plant:
Plant in service and plant held for future use	1,504,778		1,380,584
Less accumulated depreciation and amortization	460,858		429,397
	1,043,920		951,187
Construction work in progress	34,350		16,978
Net utility plant	1,078,270		968,165
Deferred Charges and Other Assets:
Regulatory assets	141,433		135,810
Goodwill	226,665		226,665
Other deferred charges	6,046		5,277
Total deferred charges and other assets	374,144		367,752
	$	1,500,770	$	1,383,223

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,
	2017		2016
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	—	$	4,600
Accounts payable	29,812		16,709
Affiliate payables	667		3,793
Accrued interest and taxes	29,619		45,581
Regulatory liabilities	1,525		92
Other current liabilities	2,450		2,134
Total current liabilities	64,073		72,909
Long-term Debt, net of Unamortized Premiums, Discounts, and Debt Issuance Costs	480,620		420,875
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	126,415		245,785
Regulatory liabilities	179,137		31,948
Asset retirement obligations	793		754
Accrued pension liability and postretirement benefit cost	7,879		11,417
Other deferred credits	7,448		6,300
Total deferred credits and other liabilities	321,672		296,204
Total liabilities	866,365		789,988
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	504,166		454,166
Retained earnings	130,175		139,005
Total common stockholder’s equity	634,405		593,235
	$	1,500,770	$	1,383,223

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		Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
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
Net earnings	—		—		35,559			35,559
Equity contributions from parent	—		50,000		—			50,000
Dividends declared on common stock	—		—		(44,389		)	(44,389		)
Balance at December 31, 2017	$	64	$	504,166	$	130,175		$	634,405

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, 2017, 2016 and 2015


(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 2016 and 2015 Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2017 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, 2017, 2016 and 2015

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.

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. See New Accounting Pronouncements below.

Utility Plant

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

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 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:



	Year ended December 31
	2017		2016		2015
PNM
Electric plant	2.52	%	2.33	%	2.27	%
Common, intangible, and general plant	8.36	%	5.40	%	4.66	%
TNMP	3.57	%	3.66	%	3.65	%

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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, 2017, 2016 and 2015

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 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 debt AFUDC is recorded in interest charges and the equity AFUDC is recorded in other income on the Consolidated Statements of Earnings.

For the years ended December 31, 2017, 2016, and 2015, PNM recorded $6.3 million, $5.3 million, and $7.8 million of debt AFUDC and $8.7 million, $4.2 million, and $10.4 million of equity AFUDC. TNMP recorded $1.2 million, $0.9 million, and $0.5 million of debt AFUDC and $0.9 million, $0.8 million, and zero of equity AFUDC.

Capitalized Interest

The Company capitalizes interest on its construction projects and major computer software projects not subject to the computation of AFUDC. Capitalized interest is recorded in interest charges. Interest was capitalized at the overall weighted average borrowing rate of 5.9%, 6.1%, and 6.6% for 2017, 2016, and 2015. In 2017, 2016, and 2015, capitalized interest was $1.3 million, $1.8 million, and $1.5 million for PNMR consolidated; $0.6 million, $0.8 million, and $0.8 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
	2017		2016		2017		2016		2017		2016
	(In thousands)
Coal	$	16,714	$	19,940	$	16,714	$	19,940	$	—	$	—
Materials and supplies	49,788		53,087		44,145		44,461		5,643		8,626
	$	66,502	$	73,027	$	60,859	$	64,401	$	5,643	$	8,626

Investments

In 1985 and 1986, PNM entered into eleven operating leases for interests in certain PVNGS generation facilities (Note 7). The 10.3% and 10.15% lessor notes that were issued by the owners of the assets subject to these leases were subsequently purchased and held by the PVNGS Capital Trust, which was consolidated by PNM. The PVNGS Capital Trust held certain of the lessor notes to their maturities in January 2015 and January 2016. Upon final maturity of the lessor notes, the PVNGS Capital Trust ceased to exist. The PVNGS lessor notes were carried at amortized cost.

PNM holds investment securities in the NDT for the purpose of funding its share of the decommissioning costs of PVNGS and 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, 2017, 2016, and 2015, PNM recorded impairment losses on the available-for-sale securities held in the NDT and coal mine reclamation trusts of $7.1 million, $13.9 million, and $10.4 million. No gains or losses are deferred as regulatory assets or liabilities. Through December 31, 2017, 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

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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, 2017, 2016 and 2015

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.

Investment in NM Renewable Development, LLC

On September 22, 2017, PNMR Development and AEP OnSite Partners created NMRD to pursue the acquisition, development, and ownership of renewable energy generation projects, primarily in the state of New Mexico. PNMR Development and AEP OnSite Partners each have a 50% ownership interest in NMRD. In December 2017, PNMR Development made a contribution to NMRD of its interest in three 10 MW solar facilities it was constructing and assigned its interests in several agreements related to those facilities to NMRD. The facilities had a book value of $24.8 million, which approximated fair value at that time. AEP OnSite Partners made a cash contribution to NMRD equal to 50% of the value of the 30 MW solar capacity, amounting to $12.4 million, which cash was then distributed from NMRD to PNMR Development. During 2017, PNMR Development and AEP OnSite Partners each made cash contributions of $4.1 million to NMRD for its construction activities. At December 31, 2017, NMRD’s renewable energy capacity under contract is 31.8 MW, which includes 11.8 MW of solar PV facilities in operation, consisting of 10 MW required to supply energy to a new data center in PNM’s service territory (Note 17) and 1.8 MW to supply energy to Columbus Electric Cooperative located in southwest New Mexico, and 20 MW of solar PV under construction. PNMR accounts for its investment in NMRD using the equity method of accounting because PNMR’s ownership interest results in significant influence, but not control, over NMRD and its operations. PNMR records as income its percentage share of earnings or loss of NMRD and carries its investment at cost, adjusted for its share of undistributed earnings or losses.

For the year ended December 31, 2017, NMRD revenues, expenses, and net income were each less than $0.1 million. At December 31, 2017, NMRD had $6.0 million in cash, $30.9 million of property, plant, and equipment, $3.9 million in accounts payable, and $33.0 million of owners’ equity. NMRD anticipates it will complete the remaining 20 MW of solar PV facilities under construction by mid-2018, which is anticipated to be funded by additional equity contributions.

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 billed 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, 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 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.

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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, 2017, 2016 and 2015

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, 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 related to long-term are reflected as part of the debt liabilities on the Consolidated Balance Sheets.

Derivatives

The Company records derivative instruments, including energy contracts, on 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 criteria are met. For qualifying hedges, an entity must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. GAAP provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of AOCI and be reclassified into earnings in the period during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the portion of the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. See Note 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. 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 and PVNGS Unit 3 was excluded through December 31, 2017, but is included beginning in 2018. See Note 15 and Note 16. See Note 17 for information concerning the treatment of nuclear decommissioning for the leased portions of PVNGS 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 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

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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, 2017, 2016 and 2015

instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred.

The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability by assessing a range of reasonably likely costs for each identified site using currently available information and the probable level of involvement and financial condition of other potentially responsible parties. These estimates are based on assumptions regarding the costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. The ultimate cost to clean up the Company’s identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. Amounts recorded for environmental expense in the years ended December 31, 2017, 2016, and 2015, as well as the amounts of environmental liabilities at December 31, 2017 and 2016 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 for additional information, including a discussion of the impacts of tax reform under the Tax Cuts and Jobs Act enacted on December 22, 2017.

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. The Company does not expect difficulty in adopting these standards by their required effective dates.

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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, 2017, 2016 and 2015

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

In May 2014, the FASB issued ASU 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. ASU 2014-09 also revises the disclosure requirements regarding revenue. Since the issuance of ASU 2014-09, the FASB issued a one-year deferral of the effective date and 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 will replace most existing revenue recognition guidance in GAAP. ASU 2014-09 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 will adopt ASU 2014-09 effective as of January 1, 2018, its required effective date, using the modified retrospective method of adoption.

The Company has monitored the activities of the FASB and other non-authoritative groups regarding certain issues specific to the power and utility industry. These specific issues include the impacts of the new guidance on accounting for CIAC and the presentation of revenues associated with “alternative revenue programs,” which primarily result from certain of the Company’s approved rate rider programs. The appropriate authoritative accounting organization has given tentative approval of the utility industry’s positions on all power and utility specific issues. The Company has substantially completed its assessment of ASU 2014-09 and does not anticipate a cumulative effect adjustment on the date of adoption or changes to the amount and timing of its current revenue recognition practices. The Company believes its existing policies, processes, information technology infrastructure, and internal controls properly capture and report revenue in accordance with ASU 2014-09.

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 2016-01, which makes targeted improvements to GAAP regarding financial instruments. ASU 2016-01 eliminates the requirement to classify investments in equity securities with readily determinable fair values into trading or available-for-sale categories and requires those equity securities to be measured at fair value with changes in fair value recognized in net earnings rather than in OCI. Unrealized gains, net of income taxes, recorded in AOCI related to equity securities will be reclassified to retained earnings as a cumulative effect adjustment. ASU 2016-01 also revises certain presentation and disclosure requirements. Under ASU 2016-01, accounting for investments in debt securities remains essentially unchanged.

PNM currently classifies all 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 ASU 2016-01 effective as of January 1, 2018, its required effective date. On January 1, 2018, PNMR and PNM will record a cumulative effect adjustment, net of income taxes, to increase retained earnings by $11.1 million with an offset to AOCI. Future changes in the fair value of equity securities will be recorded in earnings.

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

In February 2016, the FASB issued ASU 2016-02 to provide guidance on the recognition, measurement, presentation, and disclosure of leases. ASU 2016-02 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, whereas other leases will be required to be accounted for as financing arrangements similar to the accounting treatment for capital leases under current GAAP. ASU 2016-02 also revises certain disclosure requirements. At adoption, ASU 2016-02 requires that leases be recognized and measured as of the earliest period presented using a modified retrospective approach with all periods presented being restated and presented under the new guidance. The ASU allows entities to apply certain practical expedients to arrangements that exist upon adoption or expired during the periods presented.

As further discussed in Note 7, the Company has operating leases of office buildings, vehicles, and equipment. The Company also routinely enters into land easements and right-of-way agreements. PNM also has operating lease interests in PVNGS Units 1 and 2 that will expire in January 2023 and 2024.

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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, 2017, 2016 and 2015

The Company, along with others in the utility industry, is continuing to monitor the activities of the FASB and other non-authoritative groups regarding industry specific issues for further clarification. The Company has formed a project team, conducted outreach activities across its lines of business, and made significant progress in identifying arrangements, in addition to its existing operating lease arrangements, that may be classified as leases under ASU 2016-02. It is likely the arrangements currently classified as leases will continue to be recognized as leases under ASU 2016-02. It is possible that other contractual arrangements not previously meeting the lease definition may contain elements that qualify as leases and that previously identified operating leases may be classified as financing leases under ASU 2016-02. The Company is in the process of analyzing each of the identified contractual arrangement to determine if it contains lease elements under the new standard and quantifying the potential impacts of identified lease arrangements. The Company is also evaluating the practical expedients, if any, it will elect upon adoption. The Company anticipates this process will continue into 2018. The Company will adopt this standard effective as of January 1, 2019, its required effective date.

In January 2018, the FASB issued ASU 2018-01, which clarifies that land easements are to be evaluated under ASU 2016-02, but provides an additional optional practical expedient to not evaluate existing or expired land easements that were not accounted for as leases under the current guidance. The Company has numerous land easements and right-of-way agreements that would fall under this clarification. The only such agreement that has been accounted for as a lease under current guidance is the right-of-way agreement with the Navajo Nation (Note 7). The Company anticipates it will elect to use the practical expedient for its existing and expired land easements upon adoption of ASU 2016-02.

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 2016-13, which 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 the remaining lives of the assets. The Company anticipates adopting ASU 2016-13 effective as of January 1, 2020 although early adoption is permitted beginning on January 1, 2019. 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 its financial statements.

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

In November 2016, the FASB issued ASU 2016-18, which requires that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statements of cash flows and adds disclosures necessary to reconcile such amounts to cash and cash equivalents on the balance sheets. ASU 2016-18 does not provide a definition of what should be considered restricted cash. Upon adoption, ASU 2016-18 requires the use of a retrospective transition method for each period presented. The Company has substantially completed its analysis of ASU 2016-18 and will adopt the standard effective as of January 1, 2018, its required effective date. During 2015, PNM received a deposit of $8.2 million from a third party that was restricted for PNM’s construction of transmission interconnection facilities for that party. PNM recorded the deposit in Other deferred charges and it was not included in cash on the Consolidated Statements of Cash Flows. Construction of the interconnection was completed in 2018, at which time $7.1 million was refunded to the third party. Other amounts considered to be restricted cash under ASU 2016-18 were insignificant. In 2018, PNM will reclassify amounts related to restricted cash on the Consolidated Statements of Cash Flows in accordance with ASU 2016-18 and provide the required additional disclosures.

Accounting Standards Update 2017-04 – Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment

In January 2017, the FASB issued ASU 2017-04 to simplify the annual goodwill impairment assessment process. Currently, the first step of a quantitative impairment test requires an entity to compare the fair value of each reporting unit containing goodwill 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. ASU 2017-04 eliminates the second step of the impairment analysis. Accordingly,

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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, 2017, 2016 and 2015

if the first step of a quantitative goodwill impairment analysis performed after adoption of ASU 2017-04 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. The Company anticipates it will adopt ASU 2017-04 for impairment testing after January 1, 2020, its required effective date, although early adoption is permitted. However, if there is an indication of potential impairment of goodwill as a result of an impairment assessment prior to 2020, the Company will evaluate the impact of ASU 2017-04 and could elect to early adopt this standard.

Accounting Standards Update 2017-07 – Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07 to improve the presentation of net periodic pension and other postretirement benefit costs. Currently, the Company presents all of its net periodic benefit costs, net of amounts capitalized to construction and other accounts, as administrative and general expenses on its statements of earnings. The amendments in ASU 2017-07 require the service cost component of net benefit costs be presented in the same line item or items as employees’ compensation. The other components of net benefit cost (the “non-service cost components”) are required to be presented in the income statement separately from the service cost component and outside of operating income with disclosures identifying where the non-service cost components have been presented. ASU 2017-07 also limits capitalization to only the service cost component of benefit costs. PNMR and its subsidiaries maintain qualified defined benefit pension and OPEB plans. Currently, net periodic benefit cost for the Company’s defined benefit pension plans do not include a service cost component and there is only a minor amount of service cost for the OPEB plans. Additional information about the Company’s benefit plans is discussed in Note 12. ASU 2017-07 requires retrospective presentation of the service and non-service cost components of net benefit costs in the income statement and prospective application regarding the capitalization of only the service cost component of net benefit costs. The Company will adopt the standard effective as of January 1, 2018, its required effective date. In 2017 and 2016, PNM recorded pre-tax Administrative and general expenses of $4.7 million and $3.0 million and TNMP recorded less than $0.1 million and less than $0.1 million related to their non-service cost components of net periodic benefit costs. Beginning in 2018, such costs will be reclassified to Other (deductions) on the Consolidated Statements of Earnings. The Company believes PNM and TNMP can continue to capitalize the non-service cost components of net benefit costs as regulatory assets to the extent attributable to regulated operations and does not anticipate ASU 2017-07 will have a significant impact on its financial statements.

Accounting Standards Update 2017-12 – Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities

In August 2017, the FASB issued ASU 2017-12 to better align hedge accounting with an organization’s risk management activities and to simplify the application of hedge accounting guidance. ASU 2017-12 is effective for the Company on January 1, 2019 although early adoption is permitted beginning on January 1, 2018. As discussed in Note 6, the Company periodically enters into, and designates as cash flow hedges, interest rate swaps to hedge its exposure to changes in interest rates. In addition, as discussed in Note 8, the Company enters into various derivative instruments to economically hedge the risk of changes in commodity prices, which are not currently designated as cash flow hedges. The Company is evaluating the requirements of ASU 2017-12, but does not anticipate the changes will have a significant impact on the Company’s accounting treatment for derivative instruments or on its financial statements.


(2)	Segment Information

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

PNM

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

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

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.

PNMR SEGMENT INFORMATION

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.



2017	PNM			TNMP			Corporate and Other			PNMR Consolidated
	(In thousands)
Electric operating revenues	$	1,104,230		$	340,773		$	—		$	1,445,003
Cost of energy	321,677			85,802			—			407,479
Utility margin	782,553			254,971			—			1,037,524
Other operating expenses	423,011			98,221			(22,135		)	499,097
Depreciation and amortization	147,017			63,146			21,779			231,942
Operating income	212,525			93,604			356			306,485
Interest income	8,454			—			7,462			15,916
Other income (deductions)	30,686			3,551			(3,254		)	30,983
Interest charges	(82,697		)	(30,084		)	(14,844		)	(127,625		)
Segment earnings (loss) before income taxes	168,968			67,071			(10,280		)	225,759
Income taxes	81,555			31,512			17,273			130,340
Segment earnings (loss)	87,413			35,559			(27,553		)	95,419
Valencia non-controlling interest	(15,017		)	—			—			(15,017		)
Subsidiary preferred stock dividends	(528		)	—			—			(528		)
Segment earnings (loss) attributable to PNMR	$	71,868		$	35,559		$	(27,553	)	$	79,874

At December 31, 2017:
Total Assets	$	4,921,563		$	1,500,770		$	223,770		$	6,646,103
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, 2017, 2016 and 2015



2016	PNM			TNMP			Corporate and Other			PNMR Consolidated

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			PNMR 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

The Company defines utility margin as electric operating revenues less cost of energy. Cost of energy consists primarily of fuel and purchase power costs for PNM and costs charged by third-party transmission providers for TNMP. The Company believes that utility margin provides a more meaningful basis for evaluating operations than electric operating revenues since substantially all such costs are offset in revenues as fuel and purchase power costs are passed through to customers under PNM’s FPPAC and third-party transmission costs are passed on to customers through TNMP’s transmission cost recovery factor. Utility margin is not a financial measure required to be presented under GAAP and is considered a non-GAAP measure.

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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, 2017, 2016 and 2015

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,
	2017		2016		2015
REP A	16	%	16	%	16	%
REP B	11	%	11	%	13	%
REP C	10	%	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.

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,
	2017		2016		2015
			(In thousands)
Services billings:
PNMR to PNM	$	97,914	$	94,606	$	90,827
PNMR to TNMP	31,095		28,907		28,109
PNM to TNMP	382		427		554
TNMP to PNMR	141		66		41
TNMP to PNM	154		172		—
Interest billings:
PNMR to PNM	21		11		54
PNM to PNMR	220		150		110
PNMR to TNMP	133		132		276
Income tax sharing payments:
PNMR to TNMP	—		—		—
PNMR to PNM	23,391		—		1,450
TNMP to PNMR	20,686		—		—


(4)	Regulatory Assets and Liabilities

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

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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, 2017, 2016 and 2015



	PNM						TNMP
	December 31,						December 31,
	2017			2016			2017			2016
Assets:	(In thousands)
Current:
FPPAC	$	363		$	1,451		$	—		$	—
Energy efficiency costs	1,776			1,991			794			413
	2,139			3,442			794			413
Non-Current:
CTC, including carrying charges	—			—			26,998			36,328
Coal mine reclamation costs	16,462			22,383			—			—
Deferred income taxes	59,220			62,918			9,621			9,932
Loss on reacquired debt	22,744			24,404			32,808			34,107
Pension and OPEB	222,774			249,286			26,153			27,661
Shutdown of SJGS Units 2 and 3	125,539			—			—			—
Hurricane recovery costs	—			—			6,640			—
AMS surcharge	—			—			27,903			14,669
AMS retirement costs	—			—			8,948			11,086
Other	12,500			6,422			2,362			2,027
	459,239			365,413			141,433			135,810
Total regulatory assets	$	461,378		$	368,855		$	142,227		$	136,223

	PNM						TNMP
	December 31,						December 31,
	2017			2016			2017			2016
Liabilities:	(In thousands)
Current:
Renewable energy rider	$	(779	)	$	(3,411	)	$	—		$	—
Other	(5		)	(106		)	(1,525		)	(92		)
	(784		)	(3,517		)	(1,525		)	(92		)
Non-Current:
Cost of removal	(256,493		)	(297,087		)	(26,541		)	(26,900		)
Deferred income taxes	(445,390		)	(62,920		)	(148,455		)	(2,644		)
PVNGS ARO	(24,889		)	(30,621		)	—			—
Renewable energy tax benefits	(21,383		)	(22,540		)	—			—
Nuclear spent fuel reimbursements	(5,518		)	(8,875		)	—			—
Pension and OPEB	—			—			(3,442		)	(1,955		)
Other	(768		)	(1,658		)	(699		)	(449		)
	(754,441		)	(423,701		)	(179,137		)	(31,948		)
Total regulatory liabilities	$	(755,225	)	$	(427,218	)	$	(180,662	)	$	(32,040	)

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 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

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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, 2017, 2016 and 2015

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 is 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, 2017. PNMR funded cash equity contributions of $28.1 million in 2016 and $175.0 million in 2015 to PNM and $50.0 million in 2017 and $50.0 million in 2016 to TNMP. PNMR offers shares of PNMR common stock through the PNMR Direct Plan. PNMR utilizes shares of its common stock purchased on the open market, by an independent agent, rather than issuing additional shares to satisfy subscriptions under the PNMR Direct Plan. The shares of PNMR common stock utilized in the PNMR Direct Plan are offered under a SEC shelf registration statement that expires in August 2018.

Dividends on Common Stock

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

PNM declared and paid cash dividends to PNMR of $60.7 million, $4.1 million, and $94.4 million in 2017, 2016, and 2015. TNMP paid cash dividends to PNMR of $44.4 million, $31.8 million, and $33.2 million in 2017, 2016, and 2015.

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, including that dividends cannot be paid from paid-in capital. 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, 2017: none of the numerical tests would restrict the payment of dividends from the retained earnings of TNMP; the transfer of assets limitation would allow the payment of dividends by PNM of up to $246.1 million; and the 65% debt-to-capital covenant would allow the payment of dividends by PNMR of up to $133.9 million.

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.

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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, 2017, 2016 and 2015

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 or refinance other debt. Each of the Company’s revolving credit facilities and term loans contains a single financial covenant, which requires the maintenance of a debt-to-capital ratio of less than or equal to 65%, and generally also 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, 2015, PNMR had outstanding the one-year $100.0 million PNMR Term Loan Agreement, which was due in December 2015. In December 2015, PNMR entered into an agreement that extended the maturity date for an additional year and 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 (the “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 2.34% at December 31, 2017, and must be repaid on or before March 9, 2018.

At January 1, 2015, 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 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 of February 1, 2021 and bears interest at a rate based on LIBOR plus a customary spread, which aggregated 4.13% at December 31, 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 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 Westmoreland’s purchase of SJCC. The BTMU Term Loan Agreement requires that NM Capital utilize all amounts, less taxes and fees, it receives under the Westmoreland Loan to repay the BTMU Term Loan Agreement. The principal balance outstanding under the BTMU Term Loan Agreement was $50.1 million at December 31, 2017 and $45.1 million at February 20, 2018. Based on scheduled payments on the Westmoreland Loan and WSJ’s payment of $5.6 million on February 1, 2018, (which included $4.8 million in excess of the scheduled payment), NM Capital estimates it will make principal payments of $10.6 million on the BTMU Term Loan Agreement in the year ended December 31, 2018, including the payment made on February 1, 2018 of $5.0 million (which included $3.3 million in excess of the payment previously scheduled).

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 was to mature 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 PNMR Term Loan Agreement and to reduce borrowings under the PNMR Revolving Credit Facility. On December 15, 2017, the PNMR 2016 One-Year Term Loan was extended to December 14, 2018. The PNMR 2016 One-Year Term Loan (as extended) and the PNMR 2016 Two-Year Term Loan bear interest at variable rates, which were 2.32% and 2.32% at December 31, 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, 2017, 2016 and 2015

PNM

On January 1, 2015, PNM had a $125.0 million multi-draw term loan facility (the “PNM Multi-draw Term Loan”) that had outstanding borrowings of $100.0 million and a maturity date of June 21, 2016. 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.

At January 1, 2015, 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 2.45%, 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 an existing $175.0 million term loan and to repay outstanding borrowings under the PNM Revolving Credit Facility, the PNM 2014 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 bore interest at a variable rate and had 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. The PNM 2016 Term Loan Agreement was repaid on July 20, 2017.

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.

At January 1, 2015, PNM had $37.0 million of outstanding PCRBs, which have a final maturity of June 1, 2040, and $20.0 million of outstanding PCRBs which have a final maturity of June 1, 2042. These PCRBs were subject to mandatory tender for remarketing on June 1, 2017 and were successfully remarketed on that date. The $37.0 million of PCRBs now bear interest at 2.125% and the $20.0 million of PCRBs now bear interest at 2.45%. Both series are now subject to mandatory tender for remarketing on June 1, 2022.

On July 20, 2017, PNM entered into a $200.0 million term loan agreement (the “PNM 2017 Term Loan Agreement”) between PNM and JPMorgan Chase Bank, N.A., as lender and administrative agent, and U.S. Bank National Association, as lender. The PNM 2017 Term Loan Agreement bears interest at a variable rate, which was 2.29% at December 31, 2017, and must be repaid on or before January 18, 2019. PNM used the proceeds of the PNM 2017 Term Loan Agreement to prepay without penalty the $175.0 million PNM 2016 Term Loan Agreement and to reduce short-term borrowings.

On July 28, 2017, PNM entered into an agreement (the “PNM 2017 Senior Unsecured Note Agreement”) with institutional investors for the sale of $450.0 million aggregate principal amount of Senior Unsecured Notes (the “PNM 2018 SUNs”) offered in private placement transactions. Under the PNM 2017 Senior Unsecured Note Agreement, PNM has agreed to issue $350.0 million of the PNM 2018 SUNs on or about May 15, 2018 and $100.0 million of the PNM 2018 SUNs on or about August 1, 2018. The issuances of the PNM 2018 SUNs are subject to the satisfaction of customary conditions. PNM will use the gross proceeds from the PNM 2018 SUNs to repay $350.0 million of PNM’s 7.95% Senior Unsecured Notes that mature on May 15, 2018 and $100.0 million of PNM’s 7.50% Senior Unsecured Notes that mature on August 1, 2018. The terms of the PNM 2017 Senior Unsecured Note Agreement include customary covenants, including a covenant that requires the maintenance of a debt-to-capital ratio of less than or equal to 65%, customary events of default, including a cross default provision, and covenants regarding parity of financial covenants, liens and guarantees with respect to PNM’s material credit facilities. In the event of a change of control, PNM will be required to offer to prepay the PNM 2018 SUNs at par. PNM will have the right to redeem any or all of the PNM 2018 SUNs prior to their respective maturities, subject to payment of a customary make-whole premium. In accordance with GAAP, aggregate borrowings of $450.0 million under PNM’s Senior Unsecured Notes due on May 15, 2018 and August 1, 2018, are reflected as being long-term in the Consolidated Balance Sheet at December 31, 2017 since the PNM 2017 Senior Unsecured Note Agreement demonstrates PNM’s ability and intent to re-finance the aggregate $450.0 million Senior Unsecured Notes on a

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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, 2017, 2016 and 2015

long-term basis. Information concerning the maturities and interest rates on the PNM 2018 SUNs to be issued in May 2018 and August 2018 is as follows:



Scheduled
Funding	Maturity	Principal		Interest
Date	Date	Amount		Rate
		(In millions)

May 15, 2018	May 15, 2023	$	55.0	3.15	%
May 15, 2018	May 15, 2025	104.0		3.45	%
May 15, 2018	May 15, 2028	88.0		3.68	%
May 15, 2018	May 15, 2033	38.0		3.93	%
May 15, 2018	May 15, 2038	45.0		4.22	%
May 15, 2018	May 15, 2048	20.0		4.50	%
		350.0
August 1, 2018	August 1, 2028	15.0		3.78	%
August 1, 2018	August 1, 2048	85.0		4.60	%
		100.0
		$	450.0

PNM has a shelf registration statement, which will expire in May 2020, with capacity for the issuance of up to $475.0 million of senior unsecured notes.

TNMP

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 on or about February 10, 2016, subject to satisfaction of certain conditions. TNMP issued the bonds on February 10, 2016 and used the proceeds to reduce short-term debt and intercompany debt.

On June 14, 2017, TNMP entered into an agreement (the “TNMP 2017 Bond Purchase Agreement”), which provided TNMP would issue $60.0 million aggregate principal amount of 3.22% first mortgage bonds, due 2027 on or about August 25, 2017, subject to satisfaction of certain conditions. TNMP issued the bonds on August 24, 2017 and used the proceeds to reduce short-term and intercompany debt and for general corporate purposes.

Interest Rate Hedging Activities

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 its maturity on March 9, 2018. In 2017, PNMR entered into three separate four-year hedging agreements whereby it effectively established fixed interest rates of 1.926%, 1.823%, and 1.629%, plus customary spreads over LIBOR, subject to change if there is a change in PNMR’s credit rating, for three separate tranches, each of $50.0 million, of its variable rate debt.

These hedge agreements are accounted for as cash flow hedges. The fair value of the hedge related to the PNMR 2015 Term Loan Agreement was a gain of $0.2 million at December 31, 2017 and is included in Other current assets on the Consolidated Balance Sheets and a loss of less than $0.1 million at December 31, 2016. At December 31, 2017, the remaining hedge agreements had fair value gains totaling $1.4 million, which are included in Other current assets on the Consolidated Balance Sheets. The fair values were determined using Level 2 inputs under GAAP, including using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the agreement.

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. TNMP had no outstanding borrowings from PNMR at December 31, 2017 or February 20, 2018, and

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

$4.6 million at December 31, 2016. PNM had no outstanding borrowings from PNMR at December 31, 2017, December 31, 2016, or February 20, 2018.

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. PNMR and PNM have entered into agreements to extend the maturity of both facilities from October 31, 2020 to October 31, 2022. 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 commitments 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, 2022. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. In September 2017, the TNMP Revolving Credit Facility was extended to mature on September 23, 2022.

At January 1, 2015, PNM had a $50.0 million unsecured revolving credit facility (the “PNM 2014 New Mexico Credit Facility”) that was scheduled to expire on January 8, 2018. On December 12, 2017, PNM entered into a new $40.0 million unsecured revolving credit facility (the “PNM 2017 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 to replace the PNM 2014 New Mexico Credit Facility. The eight participating lenders are all banks that have a significant presence or are headquartered in New Mexico. The PNM 2017 New Mexico Credit Facility expires on December 12, 2022 and contains covenants and conditions similar to those in the PNM Revolving Credit Facility.

Short-term debt outstanding consists of:



	December 31,
Short-term Debt	2017		2016
	(In thousands)
PNM:
PNM Revolving Credit Facility	$	39,800	$	35,000
PNM 2014 New Mexico Credit Facility	—		26,000
PNM 2017 New Mexico Credit Facility	—		—
	39,800		61,000
TNMP Revolving Credit Facility	—		—
PNMR:
PNMR Revolving Credit Facility	165,600		126,100
PNMR 2016 One-Year Term Loan	100,000		100,000
	$	305,400	$	287,100

In addition to the above borrowings, PNMR, PNM, and TNMP had letters of credit outstanding of $6.4 million, $2.5 million, and $0.1 million at December 31, 2017 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 December 31, 2017, interest rates on outstanding borrowings were 2.76% for the PNMR Revolving Credit Facility and 2.59% for the PNM Revolving Credit Facility.

At February 20, 2018, PNMR, PNM, and TNMP had $111.2 million, $340.1 million, and $51.0 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $20.0 million availability under the PNM 2017 New Mexico Credit Facility. Total availability at February 20, 2018, on a consolidated basis, was $522.3 million for PNMR. At February 20, 2018, PNMR had invested cash of $0.9 million. PNM and TNMP had no invested cash at February 20, 2018.

On February 26, 2018, PNMR Development entered into a $24.5 million credit facility with Wells Fargo Bank, National Association, as lender. The facility allows PNMR Development to borrow on a revolving credit basis and also provides for the issuance of letters of credit. The facility matures on February 25, 2019. The facility bears interest at a variable rate and contains terms similar to the PNMR Revolving Credit Facility. PNMR has guaranteed the obligations of PNMR Development under the facility. PNMR Development anticipates using the facility to finance its participation in NMRD (Note 1).

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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, 2017, 2016 and 2015

Long-Term Debt

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



	December 31, 2017					December 31, 2016
	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:
1.875% due April 2033, mandatory tender - October 1, 2021	$	146,000	$	1,383		$	146,000	$	1,807
6.25% due January 2038	36,000		228			36,000		239
4.75% due June 2040, mandatory tender - June 1, 2017	—		—			37,000		25
2.125% due June 2040, mandatory tender - June 1, 2022	37,000		404			—		—
5.20% due June 2040, mandatory tender - June 1, 2020	40,045		105			40,045		147
5.90% due June 2040	255,000		2,040			255,000		2,131
6.25% due June 2040	11,500		92			11,500		96
2.54% due September 2042, mandatory tender - June 1, 2017	—		—			20,000		67
2.45% due September 2042, mandatory tender - June 1, 2022	20,000		153			—		—
2.40% due June 2043, mandatory tender - June 1, 2020	39,300		243			39,300		340
5.20% due June 2043, mandatory tender - June 1, 2020	21,000		53			21,000		75
Senior Unsecured Notes:
7.95% due May 2018	350,000		272			350,000		995
7.50% due August 2018	100,025		73			100,025		197
5.35% due October 2021	160,000		617			160,000		780
3.85% due August 2025	250,000		2,274			250,000		2,574
PNM 2016 Term Loan Agreement due November 2017	—		—			175,000		28
PNM 2017 Term Loan Agreement due January 2019	200,000		23			—		—
	1,665,870		7,960			1,640,870		9,501
Less current maturities	25		2			232,000		120
	1,665,845		7,958			1,408,870		9,381
TNMP Debt
First Mortgage Bonds:
9.50% due April 2019	172,302		1,032			172,302		1,857
6.95% due April 2043	93,198		(18,057		)	93,198		(18,773		)
4.03% due July 2024	80,000		686			80,000		792
3.53% due February 2026	60,000		667			60,000		749
3.22% due August 2027	60,000		552			—		—
	465,500		(15,120		)	405,500		(15,375		)
Less current maturities	—		—			—		—
	465,500		(15,120		)	405,500		(15,375		)
PNMR Debt
PNMR 2015 Term Loan Agreement due March 2018	150,000		12			150,000		84
BTMU Term Loan Agreement, payments through February 2021	50,137		1,001			92,207		1,634
PNMR 2016 Two-Year Term Loan due December 2018	100,000		9			100,000		21
	300,137		1,022			342,207		1,739
Less current maturities	257,268		396			42,025		557
	42,869		626			300,182		1,182
Total Consolidated PNMR Debt	2,431,507		(6,138		)	2,388,577		(4,135		)
Less current maturities	257,293		398			274,025		677
	$	2,174,214	$	(6,536	)	$	2,114,552	$	(4,812	)

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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, 2017, 2016 and 2015

Reflecting mandatory tender dates and the impacts of the refinancing under the PNM 2017 Senior Unsecured Note Agreement discussed above, long-term debt matures as follows:



	PNMR		PNM		TNMP		PNMR Consolidated
	(In thousands)
2018	$	257,268	$	25	$	—	$	257,293
2019	12,357		200,000		172,302		384,659
2020	25,862		100,345		—		126,207
2021	4,650		306,000		—		310,650
2022	—		57,000		—		57,000
Thereafter	—		1,002,500		293,198		1,295,698
Total	$	300,137	$	1,665,870	$	465,500	$	2,431,507


(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, as well as 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.

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 leases that were extended, the leases provide PNM with the option to purchase the leased assets at fair market value at the end of the extended lease terms. Each extended lease provides that no later than three years prior to the expiration of the lease, PNM is required to give notice to the lessor if it will “retain” the leased assets, through the purchase of the assets at the end of the lease, or “return” the leased assets to the lessor. The election made under each of the leases is irrevocable and independent of the elections made under the other leases. PNM has begun to analyze what action it will take with respect to each lease. If PNM elects to exercise its purchase option under any of the leases, PNM would attempt to negotiate the purchase price with the lessor of the lease. The leases provide an appraisal process to determine fair market value in the event the lessor and lessee cannot agree on a purchase price.

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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, 2017, 2016 and 2015

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.

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, 2017, amounts due to the lessors under the circumstances described above would be up to $169.9 million, payable on January 15, 2018 in addition to the scheduled lease payments due on January 15, 2018. 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.

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



	PNMR		PNM		TNMP
	(In thousands)
2017	$	35,972	$	31,817	$	3,570
2016	$	37,432	$	32,843	$	3,748
2015	$	61,088	$	55,994	$	3,688

Future minimum operating lease payments at December 31, 2017 are shown below:



	PNMR		PNM		TNMP
	(In thousands)
2018	$	26,802	$	25,726	$	791
2019	25,638		25,241		296
2020	25,208		25,122		—
2021	25,122		25,122		—
2022	25,122		25,122		—
Later years	60,708		60,708		—
Total minimum lease payments	$	188,600	$	187,041	$	1,087

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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, 2017, 2016 and 2015


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

Energy Related Derivative Contracts

Overview

The primary objective for the use of commodity 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 customers. PNM is exposed to market risk for the needs of its customers not covered under a FPPAC.

PNM was exposed to market risk for its share of PVNGS Unit 3 through December 31, 2017, at which time PVNGS Unit 3 became a jurisdictional resource to serve New Mexico retail customers. Beginning January 1, 2018, PNM is exposed to market risk for its 65 MW of SJGS Unit 4 that is held as merchant plant as ordered by the NMPRC (Note 16). PNM has entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022, subject to certain conditions. Under these agreements, PNM is obligated to deliver 36 MW of power only when SJGS Unit 4 is operating. These agreements are not considered derivatives because there is no notional amount due to the unit-contingent nature of the transactions.

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. TNMP does not enter into energy related derivative contracts.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing 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 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, PNM accounts for its various instruments for the purchase and sale of energy, which meet the definition of a derivative, based on PNM’s intent. During the years ended December 31, 2017, 2016, and 2015, PNM was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The derivative 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. PNM has no trading transactions.

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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, 2017, 2016 and 2015

Commodity Derivatives

PNM’s 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,
	2017			2016
	(In thousands)
Current assets	$	1,088		$	5,224
Deferred charges	3,556			—
	4,644			5,224
Current liabilities	(1,182		)	(2,339		)
Long-term liabilities	(3,556		)	—
	(4,738		)	(2,339		)
Net	$	(94	)	$	2,885

Included in the above table are $2.7 million of current assets at December 31, 2016 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. As noted above, PVNGS Unit 3 has become a jurisdictional resource to serve New Mexico retail customers beginning January 1, 2018. 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. PNM does not offset fair value and cash collateral for derivative instruments under master netting arrangements and the above table reflects the gross amounts of fair value assets and liabilities for commodity derivatives. Included in the above table are equal amounts of assets and liabilities aggregating $4.6 million at December 31, 2017 and $0.5 million at December 31, 2016, resulting from PNM’s hazard sharing arrangements with Tri-State (Note 17). The hazard sharing arrangements are net-settled upon delivery. Other amounts that could be offset under master netting agreements were immaterial.

At December 31, 2017 and 2016, PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at December 31, 2017 and 2016, amounts posted as cash collateral under margin arrangements were $0.8 million and $2.6 million. At December 31, 2017 and 2016, obligations to return cash collateral were $0.9 million and $0.1 million. 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. There were no amounts hedged under this plan as of December 31, 2017. The table above includes $0.2 million of current assets and $0.1 million of current liabilities at December 31, 2016 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 PNM’s earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.



	Economic Hedges
	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Electric operating revenues	$	5,151		$	(53	)	$	7,156
Cost of energy	(5,386		)	(1,208		)	(293		)
Total gain (loss)	$	(235	)	$	(1,261	)	$	6,863

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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, 2017, 2016 and 2015

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



	Economic Hedges
	MMBTU	MWh
December 31, 2017	100,000	—
December 31, 2016	254,100	(2,471,600	)

PNM has 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. In connection with managing its commodity risks, PNM enters into master agreements with certain counterparties. If PNM is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral if PNM’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that PNM will perform; and others have no provision for collateral. At December 31, 2017 and 2016, PNM had no such contracts in a net liability position.

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 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, 2017 and 2016, the fair value of available-for-sale securities included $293.7 million and $253.9 million for the NDT and $29.8 million and $19.1 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, 2017				December 31, 2016
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Cash and cash equivalents	$	—	$	52,636	$	—	$	23,683
Equity securities:
Domestic value	4,011		40,032		1,135		34,796
Domestic growth	3,995		35,456		3,032		47,595
International and other	6,810		45,867		2,029		27,481
Fixed income securities:
U.S. Government	273		34,317		115		40,962
Municipals	1,225		48,076		585		43,789
Corporate and other	1,714		67,140		553		54,671
	$	18,028	$	323,524	$	7,449	$	272,977

Due to the funded status of the nuclear decommissioning trust and overall market performance, PNM began to re-balance the decommissioning investment portfolio in late 2017 to increase the percentage of the investments in fixed income (debt) securities to approximately 85%. The portfolio re-balancing was completed in early 2018.

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities 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 (increase)/decrease in realized impairment losses of $3.3 million, $(1.2) million, and $(4.3) million for the years ended December 31, 2017, 2016 and 2015. See New Accounting Pronouncements in Note 1.

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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, 2017, 2016 and 2015



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Proceeds from sales	$	637,492		$	522,601		$	252,174
Gross realized gains	$	36,896		$	46,116		$	29,663
Gross realized (losses)	$	(12,993	)	$	(25,430	)	$	(9,259	)

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, 2017 and 2016, PNMR’s 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, 2017, 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	$	4,460	$	—
After 1 year through 5 years	32,693		66,588
After 5 years through 10 years	48,681		—
After 10 years through 15 years	5,934		—
After 15 years through 20 years	11,983		—
After 20 years	45,782		—
	$	149,533	$	66,588

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, 2017 and 2016.

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

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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, 2017, 2016 and 2015

Items recorded at fair value by PNM 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, 2017 and 2016 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)
				(In thousands)
December 31, 2017
Available-for-sale securities
Cash and cash equivalents	$	52,636		$	52,636	$	—
Equity securities:
Domestic value	40,032			40,032		—
Domestic growth	35,456			35,456		—
International and other	45,867			42,332		3,535
Fixed income securities:
U.S. Government	34,317			33,645		672
Municipals	48,076			—		48,076
Corporate and other	67,140			—		67,140
	$	323,524		$	204,101	$	119,423

Commodity derivative assets	$	4,644		$	—	$	4,644
Commodity derivative liabilities	(4,738		)	—		(4,738		)
Net	$	(94	)	$	—	$	(94	)



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

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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, 2017, 2016 and 2015

The carrying amounts and fair values of investments in the Westmoreland Loan, 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, 2017	(In thousands)
PNMR
Long-term debt	$	2,437,645	$	2,554,836	$	—	$	2,554,836	$	—
Westmoreland Loan	$	56,640	$	66,588	$	—	$	—	$	66,588
Other investments	$	503	$	503	$	503	$	—	$	—
PNM
Long-term debt	$	1,657,910	$	1,727,135	$	—	$	1,727,135	$	—
Other investments	$	283	$	283	$	283	$	—	$	—
TNMP
Long-term debt	$	480,620	$	527,563	$	—	$	527,563	$	—
Other investments	$	220	$	220	$	220	$	—	$	—

December 31, 2016
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	$	—	$	—

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. The Company is contemplating changing its investment allocation targets by decreasing the fixed income investments used to match pension liabilities from 65% to 50% beginning in 2018.

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, 2017, 2016 and 2015

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, 2017			(In thousands)
PNM Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	487,498	$	140,218	$	347,089	$	191
Uncategorized investments	74,768
Total Master Trust Investments	$	562,266

TNMP Pension Plan
Participation in PNMR Master Trust Investments:
Investments categorized within fair value hierarchy	$	53,273	$	15,244	$	38,008	$	21
Uncategorized investments	10,260
Total Master Trust Investments	$	63,533

PNM OPEB Plan
Cash and cash equivalents	$	437	$	437	$	—	$	—
Equity securities:
International funds	10,636		—		10,636		—
Domestic value	10,816		10,816		—		—
Domestic growth	6,710		6,710		—		—
Other funds	31,660		—		31,660		—
Fixed income securities:
Mutual funds	20,918		20,918		—		—
	$	81,177	$	38,881	$	42,296	$	—
TNMP OPEB Plan
Cash and cash equivalents	$	149	$	149	$	—	$	—
Equity securities:
International funds	1,597		—		1,597		—
Domestic value	293		293		—		—
Domestic growth	1,410		1,410		—		—
Other funds	4,011		—		4,011		—
Fixed income securities:
Mutual funds	2,685		2,685		—		—
	$	10,145	$	4,537	$	5,608	$	—

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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, 2017, 2016 and 2015



			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, 2017, 2016 and 2015

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, 2017	(In thousands)
PNMR Master Trust
Cash and cash equivalents	$	7,697	$	7,697	$	—	$	—
Equity securities:
International	42,048		—		42,048		—
Domestic value	37,026		37,026		—		—
Domestic growth	19,136		19,136		—		—
Other funds	25,099		—		25,099		—
Fixed income securities:
Corporate	215,535		—		215,323		212
U.S. Government	117,572		91,603		25,969		—
Municipals	11,438		—		11,438		—
Other funds	65,220		—		65,220		—
Total investments categorized within fair value hierarchy	540,771		$	155,462	$	385,097	$	212
Uncategorized investments:
Private equity funds	22,281
Hedge funds	45,615
Real estate funds	17,132
	$	625,799
December 31, 2016
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

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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, 2017, 2016 and 2015

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, 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
Actual return on assets sold during the period	1			—			1
Actual return on assets still held at period end	(7		)	(1		)	(8		)
Purchases	92			10			102
Sales	(247		)	(26		)	(273		)
Balance at December 31, 2017	$	191		$	21		$	212


(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. PNM is obligated to pay fixed operation and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the years ended December 31, 2017, 2016, and 2015, PNM paid $19.6 million, $19.3 million, and $19.2 million for fixed charges and $1.3 million, $1.1 million, and $1.6 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 its obligations and creditors of Valencia do not have any recourse against PNM’s assets. During the term of the PPA, PNM has the option, under certain conditions, 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 50% of book value reduced by related indebtedness or 50% of fair market value.

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 Valencia 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 VIE. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

Summarized financial information for Valencia is as follows:



Results of Operations
	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Operating revenues	$	20,887		$	20,371		$	20,687
Operating expenses	(5,870		)	(5,852		)	(5,777		)
Earnings attributable to non-controlling interest	$	15,017		$	14,519		$	14,910



Financial Position
	December 31,
	2017		2016
	(In thousands)
Current assets	$	2,688	$	2,551
Net property, plant and equipment	64,109		66,947
Total assets	66,797		69,498
Current liabilities	602		578
Owners’ equity – non-controlling interest	$	66,195	$	68,920

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 (“SJGS CSA”). That section includes information on the acquisition of SJCC by WSJ, a subsidiary of Westmoreland, 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 possible loss in the event of a default by WSJ under the Westmoreland Loan and/or performance was required under the letter of credit support. Principal payments under the Westmoreland Loan began on August 1, 2016 and are required quarterly thereafter. Interest is also paid quarterly beginning on May 3, 2016.

At December 31, 2017, the amount outstanding under the Westmoreland Loan was $56.6 million. In addition, interest receivable of $1.0 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 reserves, be utilized for principal and interest payments under the loan until it is fully repaid. As of February 20, 2018, the amount outstanding under the Westmoreland Loan was $51.0 million, reflecting the February 1, 2018 principal payment of $5.6 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. The acquisition of SJCC for approximately $125.0 million on January 31, 2016 was an arm’s-length negotiated transaction between Westmoreland and BHP, which amount should approximate the fair value of SJCC at the date of acquisition. 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 SJGS CSA. Also, much of the mine reclamation activities will not be performed until after the expiration of the SJGS 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

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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

a lender, but do not give NM Capital any oversight over mining operations unless there is a default under the loan agreement. 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 SJGS 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 SJCC. The SJGS 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 at December 31, 2017 and 2016, 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 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; 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 would accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from potential carbon legislation or regulation.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015


(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,
	2017		2016		2015
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	79,874	$	116,849	$	15,640
Average Number of Common Shares:
Outstanding during year	79,654		79,654		79,654
Vested awards of restricted stock	237		104		105
Average Shares – Basic	79,891		79,758		79,759
Dilutive Effect of Common Stock Equivalents:
Stock options and restricted stock	250		374		380
Average Shares – Diluted	80,141		80,132		80,139
Net Earnings Attributable to PNMR Per Share of Common Stock:
Basic	$	1.00	$	1.47	$	0.20
Diluted	$	1.00	$	1.46	$	0.20
Dividends Declared per Common Share	$	0.9925	$	0.9025	$	0.8200


(11)	Income Taxes

Federal Income Tax Reform

On December 22, 2017, comprehensive changes in United States federal income taxes were enacted through legislation commonly known as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act makes many significant modifications to the tax laws, including reducing the federal corporate income tax rate from 35% to 21% effective January 1, 2018. The Tax Act also eliminates federal bonus depreciation for utilities effective September 28, 2017 and, effective January 1, 2018, limits interest deductibility for non-utility businesses and limits the deductibility of certain officer compensation.

Although most of the provisions of the Tax Act are not effective until 2018, GAAP requires that some effects must be recognized in 2017. Under the asset and liability method of accounting for income taxes used by the Company, deferred tax assets and liabilities are recognized for the future tax consequences of temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to reverse. At the date of enactment of the Tax Act, the Company had net deferred tax liabilities for its regulated activities and net deferred tax assets for non-regulated activities. As a result of the change in the federal income tax rate, the Company re-measured and adjusted its deferred tax assets and liabilities as of December 31, 2017. The portion of that adjustment not related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax assets and an increase in income tax expense. The portion related to PNM’s and TNMP’s regulated activities was recorded as a reduction in net deferred tax liabilities and an increase in regulatory liabilities, based on the assumption that PNM and TNMP will be required to return the benefit to ratepayers over time. PNM’s NM 2016 Rate Case (Note 17) reflects that assumption by including an amortization of the estimated benefit of the reduction in existing deferred federal income taxes as a reduction to customer rates over a twenty-one year period beginning in 2018. In addition, in January 2018, the PUCT issued an order requiring Texas utilities, including TNMP, to begin recording regulatory liabilities for the effects of the Tax Act with the stated purpose of reflecting those effects in the utility bills of Texas ratepayers.

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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, 2017, 2016 and 2015

In December 2017, the SEC issued Staff Accounting Bulletin No. 118, which provides guidance to address the application of GAAP to reflect the Tax Act in circumstances where all information and analysis of the Tax Act is not yet available or complete. This bulletin provides for up to a one-year period in which to complete the required analyses and accounting for the impacts of the Tax Act. The Company believes it has made reasonable estimates of the effects of the Tax Act and reflected the impacts in the Consolidated Financial Statements. However, the reported effects on the Company’s deferred tax assets and liabilities, regulatory assets and liabilities, and income tax expense are provisional and it is possible that changes to U.S. Treasury regulations, IRS interpretations of the provisions of the Tax Act, actions by the NMPRC, PUCT, and FERC, or the Company’s further analysis of historical records could cause these estimates to change.

The adjustments to deferred income taxes recorded as increases in regulatory liabilities and income tax expense as a result of the enactment of the Tax Act are presented below:



	PNM		TNMP		Corporate and Other			Consolidated
	(In thousands)
Net increase in regulatory liabilities	$	402,501	$	146,451	$	—		$	548,952
Net decrease in deferred income tax liabilities (deferred income tax assets)	372,895		138,586		(19,990		)	491,491
Net deferred income tax expense	$	29,606	$	7,865	$	19,990		$	57,461

GAAP requires that the impacts of adjusting existing deferred tax assets and liabilities for a change in an income tax rate be recognized in income tax expense during the period of enactment, including impacts that are reflected in AOCI. This results in the tax effects of items within AOCI not reflecting the appropriate tax rate and being stranded in AOCI. In February 2018, the FASB issued Accounting Standards Update 2018-02 - Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income to address this issue by allowing entities to reclassify the income tax effects of the Tax Act on items within AOCI to retained earnings. The Company records in AOCI, net of income taxes, unamortized gains and losses related to PNM’s defined benefit pension plans to the extent not attributed to regulated operations, unrealized gains on PNM’s available-for-sale securities, and unrealized gains and losses on cash flow hedges related to PNMR’s interest rate swaps. When amounts are reclassified from AOCI to the Consolidated Statement of Earnings, the Company recognizes the related income tax expense (benefit) at the tax rate in effect at that time. As permitted by ASU 2018-02, as of December 31, 2017, the Company reclassified the stranded federal income tax effects of the Tax Act on items recorded in AOCI, resulting in a net increase in retained earnings of $17.6 million. See Note 19.

PNMR

PNMR’s income taxes consist of the following components:



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Current federal income tax	$	—		$	—		$	—
Current state income tax	(188		)	(527		)	(1,376		)
Deferred federal income tax	119,182			60,892			5,488
Deferred state income tax	11,632			3,886			12,305
Amortization of accumulated investment tax credits	(286		)	(973		)	(1,342		)
Total income taxes	$	130,340		$	63,278		$	15,075

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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, 2017, 2016 and 2015

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,
	2017			2016			2015
	(In thousands)
Federal income tax at statutory rates	$	79,016		$	68,311		$	16,154
Amortization of accumulated investment tax credits	(286		)	(973		)	(1,342		)
Flow-through of depreciation items	1,147			1,227			1,485
Earnings attributable to non-controlling interest in Valencia	(5,256		)	(5,082		)	(5,218		)
State income tax, net of federal benefit	5,398			4,537			(1,781		)
Impairment of state net operating loss carryforwards	819			(311		)	5,278
Impairment of state production tax credits	—			—			3,092
Allowance for equity funds used during construction	(3,331		)	(1,732		)	(3,650		)
Reversal of deferred items related to BART at SJGS	—			—			1,826
Impairment of charitable contribution carryforward	909			—			2,042
Regulatory recovery of prior year impairments of state net operating loss carryforward, net of amortization	(2,225		)	(1,877		)	—
Federal income tax rate change	57,461			—			—
Excess tax benefits related to stock compensation awards	(2,324		)	—			—
Other	(988		)	(822		)	(2,811		)
Total income taxes	$	130,340		$	63,278		$	15,075
Effective tax rate	57.73		%	32.42		%	32.66		%

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



	December 31,
	2017			2016
	(In thousands)
Deferred tax assets:
Net operating loss	$	98,301		$	160,901
Regulatory liabilities related to income taxes	189,501			64,657
Federal tax credit carryforwards	71,849			78,675
Shutdown of SJGS Units 2 and 3	2,204			53,434
Other	45,656			75,805
Total deferred tax assets	407,511			433,472
Deferred tax liabilities:
Depreciation and plant related	(690,909		)	(1,102,458		)
Investment tax credit	(55,731		)	(56,017		)
Regulatory assets related to income taxes	(61,956		)	(66,378		)
CTC	(5,670		)	(12,715		)
Pension	(56,070		)	(57,287		)
Regulatory asset for shutdown of SJGS Units 2 and 3	(31,887		)	—
Other	(52,498		)	(79,267		)
Total deferred tax liabilities	(954,721		)	(1,374,122		)
Net accumulated deferred income tax liabilities	$	(547,210	)	$	(940,650	)

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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, 2017, 2016 and 2015

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, 2017
	(In thousands)
Net change in deferred income tax liability per above table	$	(393,440	)
Change in tax effects of income tax related regulatory assets and liabilities	(16,444		)
Tax effect of mark-to-market adjustments	(4,724		)
Tax effect of excess pension liability	(3,421		)
Adjustment for uncertain income tax positions	2,677
Reclassification of unrecognized tax benefits	(2,677		)
Regulatory recovery of prior year impairments of state net operating loss carryforward, net of amortization	(2,225		)
Federal income tax rate change	548,952
Cumulative effect adjustment for excess tax benefit related to stock compensation awards	10,382
Alternative minimum tax carryforward reclassified to receivable	(8,336		)
Other	(216		)
Deferred income taxes	$	130,528

PNM

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Current federal income tax	$	118		$	(10,290	)	$	(7,934	)
Current state income tax	(1,112		)	(1,907		)	(1,988		)
Deferred federal income tax	73,308			49,123			(6,827		)
Deferred state income tax	9,527			4,969			5,333
Amortization of accumulated investment tax credits	(286		)	(973		)	(1,342		)
Total income taxes (benefit)	$	81,555		$	40,922		$	(12,758	)

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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, 2017, 2016 and 2015

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,
	2017			2016			2015
	(In thousands)
Federal income tax (benefit) at statutory rates	$	59,139		$	46,501		$	(4,579	)
Amortization of accumulated investment tax credits	(286		)	(973		)	(1,342		)
Flow-through of depreciation items	1,103			1,185			1,465
Earnings attributable to non-controlling interest in Valencia	(5,256		)	(5,082		)	(5,218		)
State income tax, net of federal benefit	4,926			3,921			(2,162		)
Impairment of state net operating loss carryforwards	627			(213		)	3,619
Allowance for equity funds used during construction	(3,032		)	(1,457		)	(3,650		)
Reversal of deferred items related to BART at SJGS	—			—			1,826
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(2,225		)	(1,877		)	—
Federal income tax rate change	29,606			—			—
Allocation of excess tax benefit related to stock compensation awards	(1,708		)	—			—
Other	(1,339		)	(1,083		)	(2,717		)
Total income taxes (benefit)	$	81,555		$	40,922		$	(12,758	)
Effective tax rate	48.27		%	30.80		%	97.52		%

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



	December 31,
	2017			2016
	(In thousands)
Deferred tax assets:
Net operating loss	$	67,719		$	117,922
Regulatory liabilities related to income taxes	152,059			60,940
Federal tax credit carryforwards	60,085			59,156
Shutdown of SJGS Units 2 and 3	2,204			53,434
Other	23,801			41,700
Total deferred tax assets	305,868			333,152
Deferred tax liabilities:
Depreciation and plant related	(544,270		)	(891,578		)
Investment tax credit	(55,731		)	(56,017		)
Regulatory assets related to income taxes	(52,392		)	(56,577		)
Pension	(51,774		)	(50,134		)
Regulatory asset for shutdown of SJGS Units 2 and 3	(31,887		)	—
Other	(18,826		)	(27,512		)
Total deferred tax liabilities	(754,880		)	(1,081,818		)
Net accumulated deferred income tax liabilities	$	(449,012	)	$	(748,666	)

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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, 2017, 2016 and 2015

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, 2017
	(In thousands)
Net change in deferred income tax liability per above table	$	(299,654	)
Change in tax effects of income tax related regulatory assets and liabilities	(16,332		)
Tax effect of mark-to-market adjustments	(4,110		)
Tax effect of excess pension liability	(3,421		)
Adjustment for uncertain income tax positions	2,614
Reclassification of unrecognized tax benefits	(2,614		)
Regulatory recovery of prior year impairment of state net operating loss carryforward, net of amortization	(2,225		)
Federal income tax rate change	402,501
Allocation of cumulative effect adjustment for excess tax benefit related to stock compensation awards	7,770
Other	(1,980		)
Deferred income taxes	$	82,549

TNMP

TNMP’s income taxes consist of the following components:



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Current federal income tax	$	2,472		$	9,445		$	1,603
Current state income tax	1,765			1,729			1,639
Deferred federal income tax	27,304			12,690			20,904
Deferred state income tax	(29		)	(28		)	(21		)
Total income taxes	$	31,512		$	23,836		$	24,125

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,
	2017			2016			2015
	(In thousands)
Federal income tax at statutory rates	$	23,475		$	22,928		$	23,131
State income tax, net of federal benefit	1,198			1,132			1,065
Federal income tax rate change	7,865			—			—
Allocation of excess tax benefit related to stock compensation awards	(616		)	—			—
Other	(410		)	(224		)	(71		)
Total income taxes	$	31,512		$	23,836		$	24,125
Effective tax rate	46.98		%	36.39		%	36.5		%

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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, 2017, 2016 and 2015

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



	December 31,
	2017			2016
	(In thousands)
Deferred tax assets:
Regulatory liabilities related to income taxes	$	43,103		$	3,718
Other	3,762			6,016
Total deferred tax assets	46,865			9,734
Deferred tax liabilities:
Depreciation and plant related	(135,647		)	(201,017		)
CTC	(5,670		)	(12,715		)
Regulatory assets related to income taxes	(9,564		)	(9,800		)
Loss on reacquired debt	(6,890		)	(11,937		)
Pension	(4,296		)	(7,153		)
AMS	(7,707		)	(8,928		)
Other	(3,506		)	(3,969		)
Total deferred tax liabilities	(173,280		)	(255,519		)
Net accumulated deferred income tax liabilities	$	(126,415	)	$	(245,785	)

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, 2017
	(In thousands)
Net change in deferred income tax liability per above table	$	(119,370	)
Change in tax effects of income tax related regulatory assets and liabilities	(112		)
Federal income tax rate change	146,451
Other	306
Deferred income taxes	$	27,275

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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, 2017, 2016 and 2015

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, 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			—
Additions based on tax positions related to 2017	262			262			—
Additions (reductions) for tax positions of prior years	2,415			2,352			63
Settlement payments	—			—			—
Balance at December 31, 2017	$	9,429		$	6,563		$	63

Included in the balance of unrecognized tax benefits at December 31, 2017 are $8.9 million, $6.1 million, and $0.1 million that, if recognized, would affect the effective tax rate for PNMR, PNM, and TNMP. The Company does not anticipate that any unrecognized tax expenses or unrecognized tax benefits will be reduced or settled in 2018.

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 was as follows:



	PNMR		PNM		TNMP
	(In thousands)
2017	$	—	$	—	$	—
2016	$	4,398	$	3,625	$	345
2015	$	—	$	—	$	—

There was no accumulated accrued interest receivable or payable related to income taxes as of December 31, 2017 and 2016.

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, 2017, the Company has $410.4 million of federal net operating loss carryforwards that expire

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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, 2017, 2016 and 2015

beginning in 2030 and $71.8 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 and an increase in a regulatory liability, based 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 was not related to PNM’s regulated activities was recorded 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 resulted in refinements of the impacts of this change in tax rates being recorded periodically until the rate reduction was fully phased-in. Adjustments to deferred income taxes recorded as increases (decreases) in the regulatory liability and income tax expense are as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2017:
Regulatory liability	$	(10,109	)	$	(10,109	)	$	—
Income tax expense	$	(1,259	)	$	(1,179	)	$	—
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	)	$	—

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 was continuously extended since that time, including by the Protecting Americans from Tax Hikes Act of 2015. The 2015 act extended and phased-out bonus tax depreciation through 2019. As discussed above the Tax Act eliminated bonus depreciation for utilities effective September 28, 2017. 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 2015 through 2017 are as follows:



	PNMR			PNM			TNMP
	(In thousands)
December 31, 2017:
State tax credit carryforwards	$	—		$	—		$	—
State net operating loss carryforwards	$	819		$	627		$	—
Charitable contribution carryforwards	$	909		$	—		$	—
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		$	—		$	—

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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, 2017, 2016 and 2015

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, 2017 and 2016 are as follows:



	PNMR		PNM		TNMP
	(In thousands)
December 31, 2017:
State tax credit carryforwards	$	2,487	$	—	$	—
State net operating loss carryforwards	$	1,131	$	839	$	—
Charitable contribution carryforwards	$	952	$	—	$	—
December 31, 2016:
State tax credit carryforwards	$	3,986	$	—	$	—
State net operating loss carryforwards	$	361	$	248	$	—
Charitable contribution carryforwards	$	659	$	—	$	—

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, amounted 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 settlement of the NM 2016 Rate Case (Note 17) included $3.3 million, net of federal tax, resulting from impairment of a 2015 New Mexico net operating loss as an addition to the remaining unamortized balance of the regulatory asset from the NM 2015 Rate Case. The total balance will be recovered over three years beginning in 2018. These impacts, net of amortization, are reflected in income tax expense on the Consolidated Statement of Earnings.


(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 and TNMP receive a regulated return on the amounts funded for pension and OPEB plans in excess of the periodic cost or income to the extent included in retail rates (a “prepaid pension asset”).

Participants in the PNM Plans include eligible employees and retirees of PNMR and PNM. 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 OPEB 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 an independent actuary, 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, es

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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, 2017, 2016 and 2015

tablishes 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:


•	Implement investment strategies 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 the long-term 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 OPEB plan assets be recognized in the market-related value of assets equally over a period of not more than five years, which reduces year-to-year volatility. For the PNM Plans and TNMP Plans, the market-related value of assets is equal to the prior year’s market-related value of assets adjusted for contributions, benefit payments and investment gains and losses that are within a corridor of plus or minus 4.0% around the expected return on market value. Gains and losses that are outside the corridor are amortized over five years.

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,
	2017			2016			2017			2016
	(In thousands)
PBO at beginning of year	$	621,751		$	597,900		$	67,061		$	64,198
Service cost	—			—			—			—
Interest cost	26,908			30,307			2,887			3,304
Actuarial (gain) loss	26,298			39,463			3,050			4,318
Benefits paid	(50,974		)	(45,919		)	(4,575		)	(4,759		)
PBO at end of year	623,983			621,751			68,423			67,061
Fair value of plan assets at beginning of year	543,601			557,923			60,624			62,082
Actual return on plan assets	69,389			31,597			7,450			3,301
Employer contributions	—			—			—			—
Benefits paid	(50,974		)	(45,919		)	(4,575		)	(4,759		)
Fair value of plan assets at end of year	562,016			543,601			63,499			60,624
Funded status – asset (liability) for pension benefits	$	(61,967	)	$	(78,150	)	$	(4,924	)	$	(6,437	)

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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, 2017, 2016 and 2015

Actuarial (gain) loss results from changes in:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Discount rates	$	27,547		$	41,849		$	3,528		$	5,055
Demographic experience	(1,249		)	(334		)	(517		)	(556		)
Other assumption and experience	—			(2,052		)	39			(181		)
	$	26,298		$	39,463		$	3,050		$	4,318

The following table presents pre-tax information about prior service cost and net actuarial (gain) loss in AOCI as of December 31, 2017.



	PNM Plan						TNMP Plan
	December 31, 2017						December 31, 2017
	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	$	(1,450	)	$	159,149		$	—
Experience (gain) loss	—			(9,288		)	(621		)
Regulatory asset (liability) adjustment	—			5,387			621
Amortization recognized in net periodic benefit cost (income)	405			(6,722		)	—
Amounts in AOCI not yet recognized in net periodic benefit cost (income) at end of year	$	(1,045	)	$	148,526		$	—
Amortization expected to be recognized in 2018	$	(405	)	$	6,653		$	—

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
PNM Plan
Service cost	$	—		$	—		$	—
Interest cost	26,908			30,307			28,255
Expected return on plan assets	(33,803		)	(35,416		)	(39,323		)
Amortization of net (gain) loss	16,006			13,820			14,820
Amortization of prior service cost	(965		)	(965		)	(965		)
Net periodic benefit cost	$	8,146		$	7,746		$	2,787
TNMP Plan
Service cost	$	—		$	—		$	—
Interest cost	2,887			3,304			3,043
Expected return on plan assets	(3,779		)	(3,943		)	(4,420		)
Amortization of net (gain) loss	923			700			782
Amortization of prior service cost	—			—			—
Net periodic benefit cost (income)	$	31		$	61		$	(595	)

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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, 2017, 2016 and 2015

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	2017		2016		2015
Discount rate for determining December 31 PBO	4.05	%	4.51	%	5.29	%
Discount rate for determining net periodic benefit cost (income)	4.51	%	5.29	%	4.48	%
Expected return on plan assets	6.40	%	6.50	%	6.80	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 PBO	4.01	%	4.49	%	5.39	%
Discount rate for determining net periodic benefit cost (income)	4.49	%	5.39	%	4.39	%
Expected return on plan assets	6.40	%	6.50	%	6.80	%
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 2018 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 13.4% and 12.8% for the year ended December 31, 2017.

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. Prior to 2018, the pension plans targeted asset allocation was 21% equities, 65% fixed income, and 14% alternative investments. The Company is contemplating modifying the LDI strategy by decreasing the liability matching fixed income investments portfolio from 65% to 50% beginning in 2018. The new asset allocation will be implemented in 2018. Equity investments are primarily in domestic securities that include large, mid, and small capitalization companies. The pension plans have a 6% targeted allocation to equities of companies domiciled primarily in developed countries outside of the United States. This category includes actively managed international and domestic equity securities that are benchmarked against a variety of style indices. Fixed income investments are primarily corporate bonds of companies from diversified industries and government securities. Alternative investments include investments in hedge funds, real estate funds, and private equity funds. The hedge funds and private equity funds are structured as multi-manager multi-strategy fund of funds to achieve a diversified position in these asset classes. The hedge funds pursue various absolute return strategies such as relative value, long-short equity, and event driven. Private equity fund strategies include mezzanine financing, buy-outs, and venture capital. The real estate investment is structured as an open-ended, commingled private real estate portfolio that invests in a diversified portfolio of assets including commercial property and multi-family housing. See Note 8 for fair value information concerning assets held by the pension plans.

The following pension benefit payments are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2018	$	49,221	$	5,929
2019	48,639		5,215
2020	47,069		5,108
2021	45,246		5,373
2022	44,232		4,856
2023 - 2027	201,389		22,085

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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, 2017, 2016 and 2015

The Company does not expect to make any cash contributions to the pension plans in 2018-2021, but expects to contribute $5.1 million and zero to the PNM and TNMP pension plans in 2022, 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 4.0% to 5.1%. 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,
	2017			2016			2017			2016
	(In thousands)
APBO at beginning of year	$	94,269		$	84,674		$	12,830		$	13,106
Service cost	96			140			143			186
Interest cost	4,025			4,346			556			677
Participant contributions	3,069			2,690			379			520
Actuarial (gain) loss	(1,601		)	17,877			(381		)	(96		)
Benefits paid	(9,961		)	(11,734		)	(1,248		)	(1,563		)
Plan design changes	—			(3,724		)	—			—
APBO at end of year	89,897			94,269			12,279			12,830
Fair value of plan assets at beginning of year	72,694			72,952			8,544			9,111
Actual return on plan assets	14,222			5,923			1,642			476
Employer contributions	332			2,863			685			—
Participant contributions	3,069			2,690			379			520
Benefits paid	(9,961		)	(11,734		)	(1,248		)	(1,563		)
Fair value of plan assets at end of year	80,356			72,694			10,002			8,544
Funded status – asset (liability)	$	(9,541	)	$	(21,575	)	$	(2,277	)	$	(4,286	)

Actuarial (gain) loss results from changes in:



	PNM Plan						TNMP Plan
	Year Ended December 31,						Year Ended December 31,
	2017			2016			2017			2016
	(in thousands)
Discount rates	$	3,536		$	6,569		$	613		$	1,112
Claims, contributions, and demographic experience	(5,845		)	19,562			(994		)	(102		)
Assumed participation rate	—			(6,335		)	—			(1,013		)
Mortality rate	—			(691		)	—			(93		)
Medical benefits	1,425			(1,228		)	—			—
Dental trend assumption	(717		)	—			—			—
	$	(1,601	)	$	17,877		$	(381	)	$	(96	)

In the year ended December 31, 2017, actuarial gains of $10.6 million were recorded as adjustments to regulatory assets for the PNM Plan. For the TNMP Plan, actuarial gains of $1.6 million were recorded as adjustments to regulatory liabilities.

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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, 2017, 2016 and 2015

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



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
PNM Plan
Service cost	$	96		$	140		$	204
Interest cost	4,025			4,346			4,089
Expected return on plan assets	(5,230		)	(5,483		)	(5,610		)
Amortization of net (gain) loss	3,682			1,145			1,966
Amortization of prior service credit	(1,663		)	(30		)	(642		)
Net periodic benefit cost	$	910		$	118		$	7
TNMP Plan
Service cost	$	143		$	186		$	247
Interest cost	556			677			608
Expected return on plan assets	(456		)	(490		)	(520		)
Amortization of net (gain) loss	(79		)	(40		)	—
Amortization of prior service cost	—			—			—
Net periodic benefit cost	$	164		$	333		$	335

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	2017		2016		2015
Discount rate for determining December 31 APBO	4.00	%	4.47	%	5.34	%
Discount rate for determining net periodic benefit cost	4.47	%	5.34	%	4.45	%
Expected return on plan assets	7.50	%	7.70	%	7.70	%
Rate of compensation increase	N/A		N/A		N/A
TNMP Plan
Discount rate for determining December 31 APBO	4.00	%	4.47	%	5.34	%
Discount rate for determining net periodic benefit cost	4.47	%	5.34	%	4.45	%
Expected return on plan assets	5.40	%	5.70	%	5.70	%
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 2018 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 20.5% and 19.4% for the year ended December 31, 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, 2017, 2016 and 2015

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



	PNM Plan
	December 31,
	2017		2016
Health care cost trend rate assumed for next year	6.5	%	6.8	%
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	$	72	$	(111	)
Effect on APBO	$	1,452	$	(2,235	)

TNMP’s exposure to cost increases in the OPEB 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 OPEB plans invest in a portfolio that is diversified by asset class and style strategies. The OPEB plans generally use the same pension fixed income and equity investment managers and utilize the same overall investment strategy as described above for the pension plans, except there is no allocation to alternative investments. The other postretirement benefit plans have a target asset allocation of 70% equities and 30% fixed income. See Note 8 for fair value information concerning assets held by the other postretirement benefit plans.

The following other postretirement benefit payments, which reflect expected future service and are net of participant contributions, are expected to be paid:



	PNM Plan		TNMP Plan
	(In thousands)
2018	$	7,829	$	708
2019	7,730		725
2020	7,605		748
2021	7,442		774
2022	7,132		795
2023 - 2027	31,250		4,126

PNM expects to make no contributions to the PNM OPEB plan for 2018-2022. TNMP expects to make contributions to the TNMP OPEB totaling $0.3 million in 2018 and $1.4 million for 2019-2022.

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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, 2017, 2016 and 2015

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,
	2017			2016			2017			2016
	(In thousands)
PBO at beginning of year	$	16,212		$	16,105		$	787		$	794
Service cost	—			—			—			—
Interest cost	697			812			33			40
Actuarial (gain) loss	674			768			44			47
Benefits paid	(1,466		)	(1,473		)	(93		)	(94		)
PBO at end of year – funded status	16,117			16,212			771			787
Less current liability	1,501			1,510			93			93
Non-current liability	$	14,616		$	14,702		$	678		$	694

The following table presents pre-tax information about net actuarial loss in AOCI as of December 31, 2017.



	December 31, 2017
	PNM Plan			TNMP Plan
	(In thousands)
Amount in AOCI not yet recognized in net periodic benefit cost at beginning of year	$	2,299		$	—
Experience (gain) loss	674			44
Regulatory asset (liability) adjustment	(391		)	(44		)
Amortization recognized in net periodic benefit cost (income)	(132		)	—
Amount in AOCI not yet recognized in net periodic benefit cost at end of year	$	2,450		$	—
Amortization expected to be recognized in 2018	$	151		$	—

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



	Year Ended December 31,
	2017		2016		2015
	(In thousands)
PNM Plan
Service cost	$	—	$	—	$	—
Interest cost	697		812		760
Amortization of net (gain) loss	313		256		325
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	1,010	$	1,068	$	1,085
TNMP Plan
Service cost	$	—	$	—	$	—
Interest cost	33		40		36
Amortization of net (gain) loss	9		2		5
Amortization of prior service cost	—		—		—
Net periodic benefit cost	$	42	$	42	$	41

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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, 2017, 2016 and 2015

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	2017		2016		2015
Discount rate for determining December 31 PBO	4.05	%	4.51	%	5.29	%
Discount rate for determining net periodic benefit cost	4.51	%	5.29	%	4.48	%
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	4.01	%	4.49	%	5.39	%
Discount rate for determining net periodic benefit cost	4.49	%	5.39	%	4.39	%
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)
2018	$	1,501	$	93
2019	1,473		91
2020	1,441		89
2021	1,405		85
2022	1,363		81
2023 - 2027	6,014		324

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.

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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, 2017, 2016 and 2015

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



	Year Ended December 31,
	2017		2016		2015
	(In thousands)
PNMR
401(k) plan	$	16,452	$	17,762	$	16,725
Non-qualified plan	$	3,702	$	2,017	$	1,436
PNM
401(k) plan	$	12,120	$	13,397	$	12,679
Non-qualified plan	$	2,834	$	1,535	$	1,090
TNMP
401(k) plan	$	4,332	$	4,365	$	4,046
Non-qualified plan	$	868	$	482	$	346


(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 members of the Board. 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. Beginning with 2017 awards, the vesting period for awards of restricted stock to non-employee members of the Board is 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.

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, 2017, 2016, and 2015 was $6.2 million, $5.6 million, and $4.9 million. Stock compensation expense of $4.4 million, $4.2 million,

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

and $3.6 million was charged to PNM and $1.8 million, $1.5 million, and $1.3 million was charged to TNMP. At December 31, 2017, PNMR had unrecognized compensation expense related to stock awards of $3.8 million, which is expected to be recognized over an average of 1.53 years.

PNMR receives a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise prices of the options, and a tax deduction for the value of restricted stock at the vesting date.

The FASB issued Accounting Standards Update 2016-09 – Compensation –- Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting to simplify several aspects of the accounting for share-based payment transactions and eliminate diversity in practice. PNMR’s historical accounting for stock compensation complies with ASU 2016-09, except for the treatment of the income tax consequences of awards and the presentation of reductions to taxes payable on the Consolidated Statements of Cash Flows. Prior to ASU 2016-09, benefits resulting from income tax deductions in excess of compensation cost recognized under GAAP for vested restricted stock and on exercised stock options (collectively, “excess tax benefits”) were recorded to equity provided the excess tax benefits reduced income taxes payable. Deficiencies resulting from tax deductions related to stock awards that were below recognized compensation cost upon vesting and on canceled stock options were recorded to equity. PNMR had not recorded excess tax benefits to equity since 2009 because it is in a net operating loss position for income tax purposes. ASU 2016-09 requires that all excess tax benefits and deficiencies be recorded to tax expense and classified as cash flows from operating activities. PNMR adopted ASU 2016-09 as of January 1, 2017 and recorded excess tax benefits of $2.3 million in the year ended December 31, 2017 of which $1.7 million was allocated to PNM and $0.6 million was allocated to TNMP. As required by ASU 2016-09, PNMR recorded the excess tax benefits that were not recognized in prior years, due to its net operating loss position, as a cumulative effect adjustment of $10.4 million on January 1, 2017, increasing retained earnings and decreasing accumulated deferred income taxes on the Consolidated Balance Sheets. When excess tax benefits are used to reduce income taxes payable, the benefit will be reflected in cash flows from operating activities.

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	2017			2016			2015
Expected quarterly dividends per share	$	0.2425		$	0.2200		$	0.2000
Risk-free interest rate	1.50		%	0.94		%	0.92		%

Market-Based Shares
Dividend yield	2.67		%	2.74		%	2.87		%
Expected volatility	20.80		%	20.44		%	18.73		%
Risk-free interest rate	1.54		%	0.97		%	1.00		%

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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, 2017, 2016 and 2015

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, 2016	218,316		$	27.59	305,874		$	12.29
Granted	248,271		$	23.06	—		$	—
Exercised	(273,530	)	$	21.01	(109,433	)	$	15.89
Forfeited	(4,012	)	$	29.96	—		$	—
Expired	—		$	—	(3,000	)	$	30.50
Outstanding at December 31, 2017	189,045		$	31.11	193,441		$	9.98

PNMR’s stock-based compensation program provides for performance and market targets through 2018. Included as granted and as exercised in 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%). Excluded from the above table are 97,697 previously awarded shares that were earned for the 2015 through 2017 performance measurement period and ratified by the Board in February 2018 (based upon achieving market targets at above “target” levels, weighted at 40%, and performance targets at below “target” levels, weighted at 60%), as well as maximums of 137,036 and 133,632 shares for the three-year performance periods ending in 2018 and 2019 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 was to receive 135,000 shares of PNMR’s common stock if PNMR met specific market targets at the end of 2016 and she remained an employee of the Company. Under the agreement, she received 35,000 of the total shares in 2015 since PNMR achieved the specified market targets at the end of 2014. The specified market target was achieved at the end of 2016 and the Board ratified her receiving the remaining 100,000 shares, which are included in the above table, 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 specified performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieved the specific performance target for the period from January 1, 2015 through December 31, 2016, he was to receive $100,000 of PNMR common stock based on the market value per share on the grant date in early 2017. The specified performance 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 a market per share value of $36.30 on the grant date of March 3, 2017, or 2,754 shares, which are included in the above table. Similarly, if PNMR achieved the specified performance target for the period from January 1, 2015 through December 31, 2017, he was to receive $275,000 of PNMR common stock based on the market value per share on the grant date in early 2018. The specified performance target was achieved at the end of 2017 and the Board ratified him receiving $275,000 of PNMR common stock in February 2018 based on the market value per share on the grant date in early March 2018. The above table does not include the restricted stock shares granted in 2018. 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 specified performance targets at the end of 2017. The specified performance target was achieved at the end of 2017 and the Board ratified her receiving the 17,953 shares in February 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 February 26, 2015.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015

At December 31, 2017, the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $5.9 million with a weighted-average remaining contract life of 1.55 years. At December 31, 2017, 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 restricted stock activity, including performance-based and market-based shares, and stock options:



	Year Ended December 31,
Restricted Stock	2017		2016		2015
Weighted-average grant date fair value	$	23.06	$	26.49	$	20.34
Total fair value of restricted shares that vested (in thousands)	$	5,747	$	5,079	$	6,507

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)	$	2,234	$	1,242	$	2,350


(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 $309.1 million in 2017, 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 $145.5 million during 2017. On a consolidated basis, PNMR’s expenditures for additions to utility plant were $500.5 million in 2017.

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, 2017, 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⁾	$	920,950	$	(522,750	)	$	8,512		46.30	%
PVNGS (Nuclear) ⁽³⁾	$	918,830	$	(353,054	)	$	35,038		10.20	%
Four Corners Units 4 and 5 (Coal)	$	204,432	$	(100,914	)	$	61,755		13.00	%
Luna (Gas)	$	70,995	$	(27,023	)	$	(13	)	33.33	%


⁽¹⁾	Includes cost of removal.


⁽²⁾	See Note 16 for a discussion of the December 2017 shutdown of SJGS Units 2 and 3 and the restructuring of the ownership of SJGS Unit 4.


⁽³⁾	Includes interest in PVNGS Unit 3, interest in common facilities for all PVNGS units, and owned interests in PVNGS Units 1 and 2, including improvements.

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December 31, 2017, 2016 and 2015

San Juan Generating Station

PNM operates and jointly owns SJGS. Effective January 1, 2018, SJGS Unit 1 is owned 50% by PNM and 50% by Tucson and SJGS Unit 4 is owned 77.297% by PNM, including a 12.8% interest held as merchant plant, 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 SJGS Units 2 and 3 in December 2017 and the restructuring of SJGS ownership.

Palo Verde Nuclear Generating Station

PNM is a participant in the three units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), SRP, EPE, SCE, SCPPA, and The Department of Water and Power of the City of Los Angeles. PNM has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. See Note 7 for additional information concerning the PVNGS leases, including PNM’s 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:



	2018		2019		2020		2021		2022		Total
					(In millions)
PNM	$	295.0	$	339.0	$	313.4	$	315.8	$	493.7	$	1,756.9
TNMP	185.8		170.5		170.0		170.5		170.1		866.9
Corporate and Other	19.4		17.3		17.0		17.5		17.1		88.3
Total PNMR	$	500.2	$	526.8	$	500.4	$	503.8	$	680.9	$	2,712.1

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 $7.9 million for environmental upgrades at Four Corners, $72.8 million for 50 MW of new solar facilities included in PNM’s 2018 renewable energy procurement plan, approximately $170.0 million for an anticipated expansion of PNM’s transmission system, and approximately $100.0 million in 2021 and $300.0 million in 2022 for the costs of replacement resources related to the potential shutdown of SJGS Units 1 and 4 in 2022. See Note 17. Expenditures for the expansion of PNM’s transmission system and SJGS replacement sources are subject to obtaining necessary approvals of the NMPRC. PNM will be required to file CCN applications with the NMPRC to obtain those approvals.

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December 31, 2017, 2016 and 2015


(15)	Asset Retirement Obligations

AROs are recorded based on studies to estimate the amount and timing of future ARO expenditures and reflect underlying assumptions, such as discount rates, estimates of the future costs for decommissioning, and the timing of the removal activities to be performed. Approximately 80% of PNM’s total ARO liabilities is related to nuclear decommissioning of PVNGS. PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS, including portions under lease both during and after termination of the leases. Studies of the decommissioning costs of PVNGS, as well as SJGS and Four Corners are performed periodically and revisions to the ARO liabilities are recorded. Changes in the assumptions underlying the calculations may also require revisions to the estimated AROs when identified. A reconciliation of the ARO liabilities is as follows:



	PNMR			PNM			TNMP
	(In thousands)
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	(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	6,468			6,468			—
Liability at December 31, 2016	127,519			126,601			754
Liabilities incurred⁽¹⁾	1,854			1,853			—
Liabilities settled	(968		)	(944		)	(24		)
Accretion expense	10,680			10,603			63
Revisions to estimated cash flows	7,594			7,594			—
Liability at December 31, 2017	$	146,679		$	145,707		$	793

⁽¹⁾ Represents the obligation related to the additional ownership interest in SJGS Unit 4 that PNM acquired on December 31, 2017 due to the restructuring of the ownership of SJGS.


(16)	Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 17) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, 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

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December 31, 2017, 2016 and 2015

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

The costs of decommissioning a nuclear power plant are substantial. PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS, including portions under lease both during and after termination of the leases. 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 $2.0 million, $4.2 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015 into the qualified and non-qualified trust funds. The market value of the trusts at December 31, 2017 and 2016 was $293.7 million and $253.9 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 established a process for the payment of claims for costs incurred. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. In 2015, PNM recorded $5.6 million, including $3.6 million credited back to PNM’s customers, for its share of the settlement under this process for costs incurred from July 2011 through June 2015. Thereafter, PNM began recording estimated claims quarterly. The settlement agreement 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, 2017 and 2016, PNM had a liability for interim storage costs of $12.3 million and $12.1 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 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, which was issued in September 2013. 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.

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December 31, 2017, 2016 and 2015

As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. 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 cannot predict if there will be challenges to this action or the potential outcome of such challenges.

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 by adopting a new SIP every ten years. In the first SIP planning period, states were required 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. For all future SIP planning period, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions.

On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule. EPA also provided a companion draft guidance document for public comment. The new rule delayed the due date for the next cycle of SIPs from 2019 to 2021, altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures, and gave new authority to federal land managers to seek additional emission reduction measures outside of the states’ planning process. Finally, the rule made several procedural changes to the regional haze program, including changes to the schedule and process for states to file 5-year progress reports. EPA’s new rule was challenged by numerous parties. On January 19, 2018, EPA filed a motion to hold the case in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for reconsideration of the 2017 rule revisions. Although EPA’s decision to revisit the rule is not a determination on the merits of the issues raised in those petitions, EPA is likely to propose and take comment on additional revisions to the regional haze rules in the near future. PNM is evaluating the potential impacts of this rule.

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 required SJGS 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 included 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 (the “RSIP”). EPA issued final rules, which became effective on November 10, 2014, approving the RSIP and withdrawing the FIP.

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December 31, 2017, 2016 and 2015

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 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 SJGS ownership interest at that time, 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 $77.7 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 would reduce PNM’s ownership in SJGS by 418 MW), a possible increase in PNM’s ownership in SJGS Unit 4, the identification of a new 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 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

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December 31, 2017, 2016 and 2015

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 would retire SJGS Units 2 and 3 (PNM’s ownership interest was 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 was granted a CCN to acquire an additional 132 MW in SJGS Unit 4, effective January 1, 2018, with an initial book value of zero, plus the costs of SNCR and other capital additions (an aggregate of $20.7 million)


•	PNM was 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 (an aggregate of $154.9 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 (see Other SJGS Matters below and Note 17)


•	PNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant 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 would 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 would not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	The NMPRC would issue a Notice of Proposed Dismissal in PNM’s 2014 IRP

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 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 would not be recovered. A regulatory disallowance of $21.6 million was also recorded at December 31, 2015 for other unrecoverable costs based on the approved Stipulated Settlement. The new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“SJGS CSA”), described under Coal Supply below, resulted in a $16.5 million increase in the liability recorded for coal mine reclamation. The expense recorded for this increase and the above disallowances, aggregating $165.7 million, is included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. In addition, the shutdown of SJGS Units 2 and 3 would 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 on the Consolidated Statement of Earnings.

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, consisting of a $0.9 million expense due to a revision of the estimated net book value of SJGS Units 2 and 3, a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation resulting from the new coal mine reclamation arrangement, and a $1.7 million reduction of the other unrecoverable costs 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 was comprised of plant in service of $471.8 million and accumulated depreciation and amortization (including cost of removal) of $203.9 million

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December 31, 2017, 2016 and 2015

for a net undepreciated book value of $267.9 million, offset by 50% (which equaled $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.

SJGS Unit 3 was shut down on December 19, 2017 and SJGS Unit 2 was shut down on December 20, 2017. At shutdown, the carrying value for PNM’s ownership share of SJGS Units 2 and 3 was comprised of plant in service of $439.4 million and accumulated depreciation and amortization (including cost of removal) of $188.3 million for a net book value of $251.1 million. As of December 31, 2017, these amounts were written off and offset by previously recorded losses of $128.6 million. PNM also recorded a regulatory asset of $125.5 million for the 50% of the undepreciated book value that is to be recovered from ratepayers pursuant to the December 15, 2015 NMPRC order described above. This resulted in the reversal of previously recorded losses of $3.0 million being recorded at December 31, 2017. In addition, PNM recognized a reversal of $1.0 million of previously recorded losses for other unrecoverable costs. These reversals, which total $4.0 million, are included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings.

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 certain intervenors. Reply briefs were filed by NEE on January 9, 2017 and the parties presented oral argument to the court on January 25, 2017. The court has not rendered a decision on the appeal and there is no required time frame for a decision. In addition, 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 (see Coal Supply below). 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 – Prior to December 31, 2017, SJGS was jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant did 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 might 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. Prior to the restructuring, the exiting participants owned 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2, and PNM owned 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 (“SJGS RA”) on July 31, 2015. The SJGS 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 SJGS RA and agreed to acquire an ownership interest in SJGS Unit 4 on the December 31, 2017 exit date, but had obligations related to Unit 4 before then. Under the SJGS RA, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners on the exit date 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. Consistent with the NMPRC order, PNM acquired the rights and obligations related to the 65 MW from PNMR Development effective on December 31, 2017 in order to facilitate dispatch of power from that capacity.

The SJGS RA became effective contemporaneously with the effectiveness of the new SJGS CSA. The effectiveness of the new SJGS 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 on January 31, 2016. The SJGS RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and supplied coal to the exiting participants for

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the period from January 1, 2016 through December 31, 2017, which arrangement provided economic benefits that were passed on to PNM’s customers through the FPPAC. The SJGS RA also included provisions whereby the exiting owners made 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.

SJGS Units 2 and 3 were shut down in December 2017 and the restructuring of SJGS ownership under the SJGS RA occurred on December 31, 2017, including PNM’s acquisition of the additional 132 MW and 65 MW ownership interests in SJGS Unit 4 as set forth above. In accordance with the FERC chart of accounts, plant in service for utility assets acquired is to be recorded at the original cost of the assets less accumulated depreciation. Since PNM did not pay for any costs incurred prior to the effective date of the SJGS RA, PNM increased both plant in service and accumulated depreciation for the original cost of the acquired interests at that date, estimated to be $261.8 million, on December 31, 2017. As ordered by the NMPRC, PNM will treat the 65 MW interest as merchant utility plant that will be excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022 (Note 8). Beginning in 2018, SJGS is jointly owned by five entities. Including the 65 MW considered to be merchant plant, PNM’s ownership share is 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

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 included 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 SJGS 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. PNM’s 2017 IRP (Note 17) filed with the NMPRC on July 3, 2017 presented resource portfolio plans for scenarios that assumed SJGS will operate beyond the end of the current coal supply agreement that runs through June 30, 2022 and for scenarios that assumed SJGS will cease operations after mid-2022. The 2017 IRP data shows that retiring SJGS in 2022 would provide long-term cost benefits to PNM’s customers.

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, 2, and 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 lbs/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 $88.9 million, including amounts incurred through December 31, 2017 and PNM’s AFUDC. See Note 17 for information on the NMPRC’s treatment of these costs in PNM’s NM 2016 Rate Case.

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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 DOI issued a Record of Decision on July 17, 2015 approving the 25-year site lease extension 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 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 or regulatory considerations, could 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 an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 9, 2017. PNM cannot predict if such appeal will be successful and, if it is successful, the outcome of further district court proceedings.

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 filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule is re-evaluated, which was granted.

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the New Source Performance Standards for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance.

On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation,

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Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. The NOPR was published in the Federal Register on October 16, 2017, starting a 60-day public comment period and the EPA has indicated that it will continue to accept comments until April 26, 2018. Any final rule will be subject to judicial review. In a separate but related action, on December 28, 2017, EPA published the Advance Notice of Proposed Rulemaking for replacement of the Clean Power Plan. EPA indicated it has not determined whether it will promulgate a new rule under section 111(d) or what form a new rule would take, but is seeking public comment on that question.

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, EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation if the Clean Power Plan is ultimately sustained. In addition, the proposed rule recommended 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. PNM is unable to predict the financial or operational impacts on Four Corners operations if the Clean Power Plan is ultimately implemented as proposed and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

PNM’s review of the CO₂ emission reductions standards under the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking 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, if any.

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 thresholds 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 indicated 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.

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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 should 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.

On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 parts per billion (“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 is 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 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 was expected to release final designations of attainment/nonattainment for areas by October 1, 2017. On June 6, 2017, the EPA Administrator sent letters to state governors announcing that EPA was extending, by one year, the deadline for promulgating area designations. However, on August 2, 2017, the Trump Administration reversed the decision to extend the deadline to issue area designations, thereby requiring EPA to issue designations for ozone attainment areas by October 1, 2017.

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 non-attainment area into compliance and will look at all sources of NO_xand 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 non-attainment but would not face more stringent requirements over time.”

On November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations. In that final rule, EPA designated 2,646 counties (representing about 85% of the counties in the U.S.) as attainment/unclassifiable, and three counties in Washington as unclassifiable. San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. On December 21, 2017, EPA issued a notice of availability of its intended designations for the remaining undesignated areas. EPA stated that it intended to address the remaining areas in a separate future action, but did not specify a time frame for doing so. Under the CAA, EPA was required to promulgate area designations no later than October 1, 2017. The notice announces the availability of “120-day letters,” which were sent directly to states and tribes on December 20, 2017, and contain EPA’s intended air quality designations for the remaining areas. The only county in New Mexico designated as non-attainment is Dona Ana County. By February 28, 2018, states and tribes must provide EPA any additional information they would like EPA to consider before it promulgates final designations. EPA stated it intends to finalize designations for all areas addressed in the 120-day letters no later than April 30, 2018.

By October 2018, NMED is required to submit an infrastructure SIP that provides the basic air quality management program to implement the revised ozone standard. These plans are generally due within 36 months from the date of designation and are expected to be submitted to EPA by October 1, 2020.

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. 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.

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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. 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.

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. 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 July 2016, OSM filed a Motion for Voluntary Remand to allow the agency to conduct a new environmental analysis. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation is 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, absent a further court order based on good cause shown. On March 22, 2017, OSM issued its Notice of Intent to initiate the public scoping process and prepare an EIS for the project. The Notice of Intent provided that, in addition to analyzing the environmental effects of the mining project, the EIS will also analyze the indirect effects of coal combustion at SJGS. The public comment period ended on May 8, 2017 and the EIS resource data submittal phase was completed in November 2017. The draft EIS is expected to be available for public comment in mid-2018. 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 court granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

EPA signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.

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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 working with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS. The requirements related to Four Corners will be addressed in a subsequent NPDES permitting cycle that will determine APS’s costs to comply with the rule. PNM 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.

On April 14, 2017, EPA filed a motion with the United States Court of Appeals for the Fifth Circuit relating to ongoing litigation of the 2016 Steam Electric Effluent Guidelines rule. EPA asked the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asked to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the rule so that EPA may conduct further rulemaking, if appropriate. The motion referred to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded.

On April 25, 2017, EPA published in the Federal Register a notice of postponement of certain compliance dates for the 2016 Steam Electric Effluent Guidelines rule, consistent with the EPA's decision to grant reconsideration of the rule. Specifically, the deadlines that will be postponed are the "best available technology" limitations and pretreatment standards for certain waste streams.

On September 18, 2017, EPA published the final rule for postponement of certain compliance dates that have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA's decision to grant reconsideration of that rule. The final rule postponed the earliest date on which compliance with the effluent limitation guidelines for these waste streams would be required from November 1, 2018 until November 1, 2020.

Because SJGS is zero discharge for wastewater and is not required 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 minimal to no requirements will be imposed at Reeves

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 revised effluent limitations during the revised compliance timeframe (from November 1, 2020 through December 31, 2023). 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.

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. PNM has completed all CAF-related work associated with the monitoring plan and has received NMED’s approval. Under the next phase, PNM’s contractor prepared a scope of work, which PNM and NMED have approved, for the installation of additional monitoring wells and additional sampling of certain existing monitoring wells at the site. Work is expected to commence in March 2018. Qualified costs of this work will be eligible for payment through the CAF.

PNM is unable to predict the outcome of these matters.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum generated from coal combustion at 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 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 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

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obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect the rule 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. The CCB rule requires ongoing, phased groundwater monitoring. By October 17, 2017, utilities that own or operate CCB disposal units, such as those at Four Corners must have collected sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCB rule’s standards, the rule requires the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCB rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by January 2019. Depending upon the results of such groundwater monitoring and data evaluations, Four Corners may be required to take corrective actions, the costs of which 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, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues related to the handling of CCBs. 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, corrective action may be required. 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 time line for establishing either state or federal permitting programs. APS recently filed a comment letter with EPA seeking clarification as to when and how EPA would be initiating permit proceedings for facilities on tribal reservations, including Four Corners. PNM is unable to predict when EPA will be issuing permits for Four Corners.

On September 13, 2017, EPA agreed to evaluate whether to revise the CCB regulations based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCBs, which were premised in part on the provisions of the WIIN Act. In light of the WIIN Act and the petitions for rulemaking, the EPA is considering making additional changes to the CCB rule to provide flexibility to state programs consistent with the WIIN Act. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of the CCB regulations and pursuant to an order issued by the DC Circuit, EPA filed a status report on November 15, 2017 on the challenges to the CCB rule identifying provisions it intends to reconsider. On November 20, 2017, the DC Circuit heard oral arguments from industry groups, environmentalists, and EPA. EPA and the industry groups argued the court should postpone adjudication until EPA completes the reconsideration process for the affected provision. On December 20, 2017, a proposal to remand the CCB rule was transmitted to the Office of Management and Budget for interagency review.

The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in the future and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking

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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.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. 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. 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, 2017 and 2016, prepayments for coal (including amounts purchased from the existing SJGS participants discussed below), which are included in other current assets, amounted to $26.3 million and $48.7 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 SJGS 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 (“SJGS CSA”), pursuant to which Westmoreland is to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland is to provide CCB disposal and mine reclamation services for SJGS. 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 SJGS CSA.

The SJGS 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 SJGS CSA and the agreements for CCB disposal and mine reclamation services were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the SJGS CSA.

Pricing under the SJGS 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 SJGS 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. However, as discussed in Note 17, PNM’s 2017 IRP shows that retirement of PNM’s SJGS capacity in 2022 would be cost-effective for customers. If retirement of SJGS is approved by the NMPRC, there will be no need to extend the SJGS CSA.

The SJGS RA sets forth terms under which PNM acquired the coal inventory, including coal mined but not delivered, of the exiting SJGS participants as of January 1, 2016 and supplied coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and is supplying coal to the SJGS remaining participants over the term of the SJGS CSA. Coal costs under the SJGS 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.

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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 WSJ’s purchase 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, matures on 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 obligations to BTMU. The balance outstanding under the BTMU Term Loan Agreement was $50.1 million at December 31, 2017 and $45.1 million at February 20, 2018.

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 matures on February 1, 2021. The interest rate on the Westmoreland Loan escalates over time and was initially a rate of 7.25% plus LIBOR. Such rate was 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018 and is 12.25% plus LIBOR for the period from February 1, 2018 through January 31, 2019. 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, 2017, the amount outstanding under the Westmoreland Loan was $56.6 million. Reflecting the principal payment of $5.6 million that was paid when due on February 1, 2018, the balance of the Westmoreland Loan was $51.0 million as of February 20, 2018. 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 is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

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 (the “Four Corners CSA”), 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 ton under the new contract was approximately 51% higher in the twelve months ended June 30, 2017 than in the twelve months ended June 30, 2016, excluding the disputed amounts discussed below. 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.

Four Corners Coal Supply Arbitration – The owners of Four Corners are obligated to purchase a specified minimum amount of coal each contract year and to pay for any shortfall of coal that they fail to take delivery of below the minimum amount, except when caused by “uncontrollable forces” as defined in the Four Corners CSA. On June 13, 2017, APS received a demand for arbitration from NTEC in connection with the Four Corners CSA. NTEC originally sought a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement relating to the annual minimum quantities of coal to be purchased by the Four Corners owners. NTEC also alleged a shortfall in those purchases for the initial contract year, which ended June 30, 2017, of which PNM’s share is estimated to be approximately $6.5 million. On September 20, 2017, NTEC amended its demand for arbitration removing the request for a declaratory judgment and is now only seeking relief for the alleged shortfall in purchases in the initial contract year. PNM anticipates that substantially all of any amount it ultimately is required to pay would be passed through to customers under PNM’s FPPAC. Although PNM cannot predict the timing or outcome of the arbitration, the outcome is not expected to have a material impact on its financial position, results of operations or cash flows.

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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 reflected that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS would continue to operate through 2053, the anticipated life of SJGS. The 2013 coal mine reclamation study indicated reclamation costs had increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, which would reduce the amount of CCBs generated over the remaining life of SJGS and result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant.

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. The 2015 reclamation cost estimate reflected 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.

Upon effectiveness of the SJGS CSA and the SJGS 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. This reclamation cost estimate reflected the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053. The study indicated an increase in the reclamation cost estimate. PNM’s $4.5 million share of the increase 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 $100.4 million for the surface mines at both SJGS and Four Corners and $127.1 million for the underground mine at SJGS as of December 31, 2017. At December 31, 2017 and 2016, liabilities, in current dollars, of $41.4 million and $41.0 million for surface mine reclamation and $14.7 million and $14.0 million for underground mine reclamation were recorded in other deferred credits.

As discussed in Note 17, PNM filed its 2017 IRP on July 3, 2017. The conclusions contained in the 2017 IRP indicate that it would be cost beneficial to PNM’s customers for PNM to retire its SJGS capacity in 2022 and for PNM to exit its ownership interest in Four Corners in 2031. The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. If the NMPRC orders the abandonment of those facilities, PNM would be required to remeasure its liability for coal mine reclamation to reflect that reclamation activities would occur sooner than currently anticipated. The remeasurement would likely result in a significant increase in PNM’s liability for SJGS mine reclamation due to a further increase in the amount of fill dirt required to remediate the mine areas thereby increasing the overall reclamation costs. PNM would record an additional amount when it is determined that the increase to the liability is probable and can be reasonably estimated, which would be dependent on receiving the NMPRC approvals indicated above. The amount of the increase in the liability would depend on the timing of those approvals and other regulatory actions, as well estimates made at that time of the costs to perform the future reclamation activities, as well as the then current inflation and discount rates. Preliminary calculations indicate the increase in PNM’s liability for December 31, 2017 SJGS mine reclamation would be approximately $35 million for the surface mine and $5 million for the underground mine. PNM would record a regulatory asset for amounts recoverable from ratepayers under existing or future orders of the NMPRC and amounts not recoverable would be expensed. PNM cannot predict what actions the NMPRC might take.

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Under the terms of the SJGS 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. The SJGS owners entered into a reclamation trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UGCSA. 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 SJGS 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 $5.8 million in 2017, $7.0 million in 2016, and $4.3 million in 2015. Based on PNM’s reclamation trust fund balance at December 31, 2017, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $8.3 million in 2018, $8.7 million in 2019, and $9.2 million in 2020.

Under the Four Corners CSA, 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. PNM contributed $2.3 million in 2017 and $1.9 million in 2016 to the escrow account and anticipates providing additional funding of $2.3 million, $2.3 million, and $2.3 million in 2018, 2019, and 2020.

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.

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.

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, 2017, 2016 and 2015

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”). The primary policy offered by NEIL contains a sublimit of $2.25 billion for non-nuclear property damage. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments 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. The issues have been fully briefed and the matter is pending with the New Mexico Court of Appeals. Adjudication of non-Indian water rights continues during the pendency of the appeal of the Navajo Nation settlement.

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December 31, 2017, 2016 and 2015

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 and adjudicated to the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin and which have priority in times of shortages. 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, which was denied. On March 28, 2017, the utilities filed a Writ of Certiorari with the NM Supreme Court, which was denied. The matter will proceed in New Mexico District Court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a similar proceeding brought by other SPS customers and a proceeding filed by SPS to revise its rates for sales to PNM. On October 29, 2015, FERC approved a settlement agreement resolving all outstanding issues between SPS and PNM. Under the settlement, SPS paid PNM $4.2 million. Of this amount, $2.6 million was passed back to PNM’s customers through its FPPAC.

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a notice of appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice. The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

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December 31, 2017, 2016 and 2015

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allottees’ appeal was dismissed with prejudice. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested. The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the NM District Court regarding the approximately 15.49 acres of land at issue. On December 1, 2015, the court ruled that PNM could not condemn two of the five allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM filed a motion for reconsideration of this ruling which 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. 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. On May 26, 2017, the Tenth Circuit affirmed the district court. On July 8, 2017, PNM filed a Motion for Reconsideration en banc with the Tenth Circuit. On July 21, 2017, the court denied PNM’s Motion for Reconsideration. On July 26, 2017, PNM filed a motion to stay implementation of the court’s decision, which was denied. On September 11, 2017, PNM filed an Application for Extension of Time to File a Petition for Writ of Certiorari in the US Supreme Court. PNM’s application for an extension of time to November 20, 2017 was granted. The NM District Court has stayed the case until May 15, 2018 based on the Navajo Nation’s acquisition of interests in two additional allotments and the unresolved ownership of the fifth allotment due to the owner’s death. On November 20, 2017, PNM filed its Petition for Writ of Certiorari with the US Supreme Court. On December 22, 2017, amicus briefs supporting PNM’s Petition for Writ of Certiorari were filed with the US Supreme Court. The US Supreme Court extended the United States’ response period to March 23, 2018.

PNM cannot predict the outcome of these matters.

Sales Tax Audits

In November 2011, PNMR completed the sale of its retail electric provider, which operated in Texas under the name First Choice Power (“First Choice”). Under the sale agreement, PNMR is contractually obligated for First Choice’s taxes relating to periods prior to the sale.

The Texas Comptroller of Public Accounts (“Comptroller”) has initiated audits of First Choice’s sales and use tax filings and miscellaneous gross receipts tax filings for periods prior to the sale. During the course of the audits, PNMR accrued an immaterial liability for items identified in the audits for which PNMR believed an unfavorable resolution was probable. The Comptroller has issued notifications of audit results indicating additional tax due of $5.0 million, plus penalties and interest. The primary issue in dispute is the disallowance by the auditor of the tax benefits of bad debt charge-offs and billing credits. On behalf of First Choice, PNMR filed requests for redetermination for both audits.

PNMR has engaged in continued discussions with the Comptroller, as well as supplying additional documentation in support of PNMR’s positions. If PNMR and the Comptroller do not reach agreement, this matter will go to hearing with the Texas State Office of Administrative Hearings. Although PNMR believes its positions are correct, it is unable to predict the outcome of this matter.

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December 31, 2017, 2016 and 2015


(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 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. 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 (“SJGS CSA”). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS 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 (the “August 2016 RD”). The August 2016 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 August 2016 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 August 2016 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

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December 31, 2017, 2016 and 2015

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 August 2016 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

The August 2016 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 August 2016 RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The August 2016 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 August 2016 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 August 2016 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 August 2016 RD proposed approving PNM’s proposals for revised depreciation rates (except the August 2016 RD would require depreciation on Four Corners be calculated based on a 2041 life rather than the 2031 life proposed by PNM), the inclusion of construction work in progress in rate base, and ratemaking treatment of the “prepaid pension asset.” The August 2016 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 August 2016 RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the August 2016 RD.

On September 28, 2016, the NMPRC issued an order 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 August 2016 RD, but with certain significant modifications. The modifications to the August 2016 RD included:


•	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 contributions 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 to PNM’s appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated 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 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

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December 31, 2017, 2016 and 2015

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

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.

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. As of September 30, 2016, 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 indicated 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. At that time, PNM estimated that it would 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 would remain in effect. PNM concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss was 15 months of capital cost recovery that the order disallowed for PNM’s investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss was a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million at September 30, 2016 for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-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 challenge in its appeal) since PNM could no longer assert that those assets were 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, amounting to $2.1 million was reflected as a reduction of income tax expense on the Consolidated Statement of Earnings.

PNM also evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. PNM does not believe the issues raised in the cross-appeals have substantial merit. Accordingly, PNM does not believe that the likelihood of the cross-appeals being successful is probable and, therefore, no loss was recorded in 2016 related to the issues subject to the cross-appeals.

Since the NM Supreme Court did not issue a decision on the appeals related to the NM 2015 Rate Case by December 31, 2017, which was 15 months from the date of the NMPRC’s order in that case, PNM has reevaluated the accounting consequences of the order in the NM 2015 Rate Case. PNM continues to believe that it is reasonably possible that PNM will be successful on the issues it is appealing and that it is not probable the cross appeals will be successful. However, based on the proceedings to date in the appeal process and other actions by the NM Supreme Court, PNM now estimates that it will take an additional seven months from December 31, 2017 for the NM Supreme Court to issue a decision and any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional loss of $3.1 million at December 31, 2017, representing an additional disallowance of seven months of capital cost recovery that the order disallowed. Further losses will be recorded if the currently

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December 31, 2017, 2016 and 2015

estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues in extended.

PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudent 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 recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. 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, 2017, 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 $75.3 million, after considering the loss recorded in 2016 and 2017


•	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 $39.1 million, after considering the loss recorded in 2016 and 2017


•	The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.4 million, after considering the loss recorded in 2016 and 2017

Although PNM does not believe that the likelihood of the cross-appeals being successful is probable, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost 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 $151.1 million (which amount includes $75.3 million that is the subject of PNM’s appeal discussed above) at December 31, 2017, after considering the loss recorded in 2016 and 2017. 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 a 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 were:


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


•	Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application)


•	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, including environmental upgrades at Four Corners


◦	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

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December 31, 2017, 2016 and 2015


◦	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

The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions were held, but no agreements were reached by March 27, 2017, after which the date for filing a stipulation was extended. In early May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form, but allowed the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed the issues raised by the Hearing Examiners in their order. NEE was the sole party opposing the revised stipulation. The terms of the revised stipulation, which required NMPRC approval in order to take effect, included:


•	A revenue increase totaling $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019


•	A ROE of 9.575%


•	Full recovery of PNM’s investment in SCRs at Four Corners with a debt-only return


•	An agreement not to adjust non-fuel base rate changes to be effective prior to January 1, 2020


•	An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws enacted prior to November 1, 2018 and effective and applicable to PNM by January 1, 2019 and to true-up PNM’s cost of debt for refinancing transactions through 2018


•	Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 11) to the extent attributable to PNM’s retail operations


•	PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket


•	PNM would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028

A hearing on the revised stipulation was held in August 2017. On October 31, 2017, the Hearing Examiners issued a Certification of Stipulation recommending a Modified Revised Stipulation. The significant changes to the revised stipulation in the Hearing Examiners’ Modified Revised Stipulation included:


•	Identifying PNM’s decision to continue its participation in Four Corners as imprudent


•	Disallowing PNM’s ability to collect a debt or equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018


•	Recommending a temporary disallowance of $36.8 million of PNM’s projected capital improvements at SJGS through December 31, 2018

On December 20, 2017, the NMPRC issued an Order Partially Adopting Certification of Stipulation, which approved the Hearing Examiners’ Certification of Stipulation with certain changes. Substantive changes from the Certification of Stipulation included requiring the impacts of changes related to the reduction in the federal corporate income tax rate be implemented effective January 1, 2018 rather than January 1, 2019 and deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding.

On December 28, 2017 PNM filed a Motion for Rehearing and Request for Oral Argument asking the NMPRC to vacate their December 20, 2017 order and allow the parties to present oral argument. Additionally, several signatories to the revised stipulation filed a Joint Motion for Partial Rehearing asking that the NMPRC approve the Revised Stipulation without modification. On January 2, 2018, NEE filed a response urging the NMPRC to reject PNM’s Motion.

On January 3, 2018, the NMPRC vacated its December 20, 2017 order and granted the motions for rehearing. The rehearing was held on January 10, 2017.

The NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The Revised Order approved the Hearing Examiners’ Certification of Stipulation with certain changes including:

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•	Requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt be implemented in 2018 rather than January 1, 2019


•	Deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to PNM’s next rate case


•	Disallowing PNM’s ability to collect an equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowed recovery of the total $148.1 million of investments with a debt-only return


•	Requiring PNM to reduce the requested $62.3 million increase in non-fuel revenue by $9.1 million


•	Implementation of the first phase of the rate increase for services rendered, rather than bills rendered, on or after February 1, 2018 and of the second for services rendered on or after January 1, 2019

On January 16, 2018, PNM requested clarifying changes to the Revised Order to adjust the $9.1 million reduction to $4.4 million, asserting that $4.7 million of the reduction was duplicative. On January 17, 2018, the NMPRC issued an order approving the adjustment requested by PNM. On January 19, 2018, PNM and the Signatories filed a Joint Notice of All Signatories of Acceptance of the Order on Notice of Acceptance. On January 31, 2018, the NMPRC issued an order closing the docket in the NM 2016 Rate Case. After implementation of changes to the federal corporate income tax rate and cost of debt, the final order results in a net increase to PNM’s non-fuel revenue requirement of $10.3 million. PNM implemented 50% of the approved increase for service rendered on or after February 1, 2018 and will implement the rest of the increase for service rendered on or after January 1, 2019.

GAAP requires PNM to recognize a loss to reflect that PNM will not earn an equity return on $148.1 million of investments at Four Corners. As of December 31, 2017, PNM recorded a pre-tax regulatory disallowance of $27.9 million. The amount of the loss was calculated by determining the present value of disallowed cash flows, which equals the difference between the cash flows resulting from recovery of those investments at PNM’s embedded cost of debt and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC.

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.

Investigation/Rulemaking Concerning NMPRC Ratemaking Policies

On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method should be established for determining ROE; should the ROE be subject to reward or penalty based on utilities meeting or failing to meet certain metrics, which could include customer complaints, outages, peak demand reductions, and RPS and energy efficiency compliance; whether recovery of utility rate case expenses should be limited to 50% unless the case is settled; whether intervenors should be allowed to recover their expenses if the NMPRC accepts their position; whether parties should have access to software used by utilities to support their positions; and how regulatory assets should be authorized

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December 31, 2017, 2016 and 2015

and recovered. Initial comments were filed in July 2017 and several public workshops have been held. PNM cannot predict the outcome of this proceeding.

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 40 MW constructed in 2015 that 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; 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 2044 for the output of New Mexico Wind, having a current aggregate capacity of 204 MW and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW


•	A PPA through 2042 for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current capacity of the facility is 4 MW


•	Solar distributed generation, aggregating 81.6 MW at December 31, 2017, 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 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 proceeding 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. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered 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. No action has been taken in the show cause proceeding and PNM cannot predict its outcome.

PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan met RPS and diversity requirements for 2017 and 2018 using existing resources and PNM did not propose any significant new procurements. PNM projected that its plan would slightly exceed the RCT in 2017 and would be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determined a variance was 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 was not required. The NMPRC approved the recommended decision on November 23, 2016.

On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM requested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in

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December 31, 2017, 2016 and 2015

2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. PNM’s proposed procurement cost for 2018 and 2019 will be within the RCT. The plan also sought a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. PNM also requested to adjust its annual renewable energy rate rider to collect the costs of renewable resources. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that PNM be required to issue another all-renewables RFP allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagreed with the Hearing Examiner’s recommendations and filed exceptions contesting the Hearing Examiner’s proposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and rejecting the Hearing Examiner’s recommendations. On November 29, 2017, NMIEC filed an appeal with the NM Supreme Court objecting to the fuel allocation methodology. On December 14, 2017, NEE filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. On December 18, 2017, PNM filed a motion to intervene, which was granted. NMIEC filed a motion for a partial stay of the NMPRC order and PNM filed a response opposing the request. On February 27, 2018, the court issued an order denying the motion for stay. A briefing schedule has not been determined. PNM cannot predict the outcome of this matter.

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 $45.2 million, $42.0 million, and $41.9 million in 2017, 2016, and 2015. Beginning in 2017, the costs of energy from New Mexico Wind is being recovered through the rider, rather than through the FPPAC, in compliance with the NMPRC’s order in PNM’s NM 2015 Rate Case. In its 2018 renewable energy procurement plan case, PNM proposed to collect $43.5 million. The 2018 renewable energy procurement plan became effective on January 1, 2018.

Under the renewable rider, if PNM’s earned rate of 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 is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016. Preliminary calculations indicate PNM did not exceed such limitation in 2017.

Energy Efficiency and Load Management

Program Costs and Incentives/Disincentives

The New Mexico Efficient Use of Energy Act (“EUEA”) requires public utilities to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The EUEA 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. The EUEA sets 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.

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

On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consisted of ten programs with a total budget of $28.0 million. The application also sought approval of an incentive of $2.4 million based on targeted savings of 75 GWh. The actual incentive would be based on actual savings achieved. On January 11, 2017, the NMPRC approved an unopposed stipulation that established a method to ensure that

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funding of PNM’s energy efficiency program is equal to 3% of retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and approved 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, increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. PNM’s preliminary estimate of the incentive earned in 2017 is $2.1 million, which is subject to verification by an independent evaluator.

On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million. The application also sought approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve savings of 53 GWh in 2018. As proposed, PNM would have earned an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. PNM proposed to continue the same ten programs and a similar incentive mechanism in 2019, with a proposed budget of $28.2 million and a base level incentive of $2.1 million. On July 26, 2017, PNM, NMPRC staff, and other parties filed a stipulation that would resolve all issues in the case if approved by the NMPRC. Under the settlement, all of PNM’s proposed programs would be approved with limited modifications and PNM’s base level incentive would be $1.7 million in 2018. PNM would earn an incentive of $1.9 million based on targeted savings of 69 GWh. A public hearing was held in September 2017. On November 8, 2017, the Hearing Examiner issued a Certification of Stipulation recommending approval of the stipulation with various modifications, including adoption of a discount rate equal to the tax-adjusted WACC of 9.59% rather than the 7.71% proposed in the stipulation and modifying the program budgets to $23.6 million for 2018 and $24.9 million for 2019. On January 31, 2018, the NMPRC issued an order that largely accepts the certification with certain exceptions concerning the measurement and verification of the approved load management programs.

Energy Efficiency Rulemaking

In July 2012, the NMPRC opened an energy efficiency rulemaking docket to potentially 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 January 25, 2017, the NMPRC opened another energy efficiency rulemaking docket to consider whether applications for approval of energy efficiency and load management programs should be filed every two years rather than annually. On June 21, 2017, the NMPRC issued an order that modifies the filing frequency for utility energy efficiency plans to every three years. Also on June 21, 2017, the NMPRC issued a new notice of proposed rulemaking to consider possible changes affecting a utility’s ability to modify NMPRC approved funding levels by up to 10% between energy efficiency program applications. This rulemaking is in response to consensus changes proposed by parties in the January 25, 2017 rulemaking. On September 13, 2017, the NMPRC approved the proposed rule. Under the new rule, PNM’s next application for energy efficiency and load management programs will be made in 2020 for programs to be offered beginning in 2021.

Integrated Resource Plans

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.

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 resource needs 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 to not 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 2014 IRP did not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the 2014 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 2014 IRP complied 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.

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December 31, 2017, 2016 and 2015

On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket would be closed with prejudice within thirty days unless good cause was shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s 2014 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

PNM filed its 2017 IRP on July 3, 2017. The 2017 IRP addresses a 20-year planning period, from 2017 through 2036, and includes 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 and hosted 17 meetings statewide to present details of the process and receive public comment. The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 16 requires PNM to make a filing in 2018 to determine the extent to which SJGS Units 1 and 4 should continue serving PNM’s retail customers’ needs after June 30, 2022. The 2017 IRP analyzed several scenarios utilizing assumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP include:


•	Retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers


•	PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also save customers money


•	The best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity; the mix could include energy storage, if the economics support it, and wind energy, provided additional transmission capacity becomes available


•	Significant increases in future wind energy supplies will likely require new transmission capacity to be built from eastern New Mexico to PNM’s service territory


•	PNM should retain the currently leased capacity in PVNGS, which would avoid replacement with carbon-emitting generation


•	PNM should continue to develop and implement energy efficiency and demand management programs


•	PNM should assess the costs and benefits of participating in the California Energy Imbalance Market


•	PNM should analyze its current Reeves Generating Station to consider possible technology improvements to phase out the older generators and replace them with new, more flexible supplies or energy storage

Protests to the 2017 IRP were filed by several parties. The issues addressed in the protests included the future of PNM’s interests in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. The NMPRC has assigned the case to a Hearing Examiner. On January 16, 2018, the Hearing Examiner issued an order setting the scope of the proceedings as the 2017 IRP’s compliance with applicable statute and NMPRC rules. PNM is required to provide certain underlying information and clarify how costs, transmission constraints, energy storage, and public input were considered in developing the 2017 IRP. A pre-hearing conference was held on January 26, 2018 and hearings are scheduled to begin on June 4, 2018.

The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. Likewise, NMPRC approval of new generation resources through CCN filings would be required. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP.

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. SJGS Units 2 and 3 were retired in December 2017. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 16.

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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 a recommended decision that would grant PNM’s motion to withdraw its application. On May 24, 2017, the NMPRC issued its order approving the recommended decision and granting the motion to withdraw the application. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities.

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 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 severances for affected employees. Hearings in this matter were held in February and March 2017. During the March 2017 hearing, it was disclosed that the proposed meter contractor may not have complied with certain New Mexico contractor licensing requirements. PNM subsequently filed testimony regarding that matter as ordered by the Hearing Examiner. On May 12, 2017, PNM requested a new procedural schedule to allow it to issue a new RFP for contracting work related to the meter installation and to update its cost-benefit analysis. PNM subsequently updated the amount of the requested recovery for the anticipated cost of the project to $95.1 million. An additional hearing was held on October 25-26, 2017. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. PNM cannot predict the outcome of this matter.

Facebook, Inc. 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.

Facebook’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 was to be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development was constructing. As discussed in Note 1, PNMR Development transferred its interests in the solar capacity and the PPA to NMRD in December 2017. The cost of the PPA is to be passed through to Facebook under a new rate rider. A new special service rate will be applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the new renewable resources. The first 10 MW of solar capacity began commercial operation on January 1, 2018, which coincides with initial operations of the data center, and the remainder of the capacity is anticipated to be completed by mid-2018.

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December 31, 2017, 2016 and 2015

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 Facebook’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.

In late 2017, PNM entered into three separate 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply additional renewable power to Facebook. These PPAs are subject to NMPRC approval and PNM made a filing requesting approval on January 17, 2018. A NMPRC hearing on PNM’s filing is scheduled for March 7, 2018. These PPAs include the purchase of the power and RECs from:


•	Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located near House, New Mexico, have a total capacity of 50 MW, and be operational on December 31, 2018


•	A 166 MW potion of the La Joya Wind Project, owned by Avangrid Renewables, LLC, which is expected to be located near Estancia, New Mexico and be operational in November 2020


•	Route 66 Solar Energy Center, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located west of Albuquerque, New Mexico, have a total capacity of 50 MW, and be operational in December 2021

Hazard Sharing Agreements

On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expired on May 31, 2017. PNM and Tri-State 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 was required for the five-year agreement. On May 10, 2017, the NMPRC issued an order approving the five-year agreement.

Under these agreements, each party sells the other party 100 MW of capacity and energy from each party’s designated primary resource, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State, on a unit contingent basis subject to certain performance guarantees. The agreements reduce the magnitude of each party’s single largest generating hazard and assist in enhancing the reliability and efficiency of their respective operations. Both purchases and sales are made at the same market index price. PNM passes the sales and purchases through to customers under PNM’s FPPAC. Information about PNM’s purchases and sales is as follows:



	Sales			Purchases
	GWh	Amount		GWh	Amount
		(In millions)			(In millions)

Year ended December 31, 2017	827.1	$	23.6	849.0	$	24.2
Year ended December 31, 2016	482.3	12.8		484.6	12.9

Formula Transmission Rate Case

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 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. 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.

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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, 2017, 2016 and 2015

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

PNM had a PPA with NEC, previously PNM’s largest firm-requirements wholesale customer, that had an expiration date of December 31, 2035. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC could 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 were 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 also paid certain third-party transmission costs that it only partially paid previously. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM served 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Amounts billed to NEC were $4.5 million, $20.0 million, and $27.1 million in the years ended December 31, 2017, 2016, and 2015. 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.

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 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 20, 2018, 99 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. The PUCT approved TNMP’s reconciliation without adjustment 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 (“EECRF”), 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 EECRF increases:



Effective Date	Aggregate Collection Amount		Performance Bonus
	(In millions)
March 1, 2015	$	5.7	$	1.5
March 1, 2016	6.0		0.7
March 1, 2017	6.0		0.8
March 1, 2018	6.0		1.1

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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, 2017, 2016 and 2015

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in progress. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(In millions)
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
March 14, 2017	30.2		4.8
September 13, 2017	27.5		4.7

On January 30, 2018, TNMP filed an application to further update its transmission rates, which would increase revenues by $0.6 million annually, based on an increase in rate base of $3.2 million. The application is pending before the PUCT.

On March 23, 2017, the PUCT staff filed proposed amendments to the interim transmission cost of service filing rule. If approved, the amendments could reduce the frequency of such filings to once per year. The amendments could also reduce the amount recovered by requiring that changes in accumulated deferred income taxes be considered and would preclude filings by utilities earning more than their authorized rate of return using weather-normalized data. On February 15, 2018, the PUCT announced at an open meeting that they would not proceed with the proposed amendments.

Periodic Distribution Rate Adjustment

PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Distribution utilities may 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. In connection with TNMP’s deployment of its advanced meter system discussed above, TNMP 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.

Competition Transition Charge Compliance Filing

In connection with the adoption of legislation that deregulated electric utilities operating within ERCOT, TNMP was allowed to recover its stranded costs through the CTC and to also recover a carrying charge on the CTC. Further, the order authorizing TNMP's CTC included a true-up provision requiring an adjustment to the CTC due to a cumulative over- or under-collection of revenues, including interest, greater-than or equal to 15% of the most recent annual CTC funding amount. On March 13, 2017, TNMP made a filing to true-up the CTC. The requested adjustment reduces the collection of the amortization by $1.1 million annually. On April 3, 2017, the PUCT staff filed its recommendation to approve the requested adjustment. The change was approved on April 5, 2017 and went into effect on June 1, 2017.

Order Related to Changes in Federal Income Tax Rates

On January 25, 2018, the PUCT issued an accounting order that addresses the change in federal income tax rates on investor-owned utilities in the State of Texas. The order requires investor-owned utilities to record a regulatory liability equal to the reduction in accumulated federal deferred income tax balances at the end of 2017 due to the change in the federal income tax rate. In addition, the order requires that a regulatory liability be recorded to reflect the difference between revenues collected under existing rates and those that would have been collected had those rates been set reflecting federal income tax reform beginning on the date of the order. The order provides that these regulatory liabilities will be considered by the PUCT in each utility’s next rate proceeding, which for TNMP is anticipated to be filed in May 2018. TNMP is evaluating the order and what actions it will take, as are other investor-owned utilities operating in Texas.

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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, 2017, 2016 and 2015

(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. PNMR’s reporting units that currently have goodwill are PNM and TNMP.

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. 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 the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. A quantitative analysis is not required 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.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. 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. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, GAAP currently requires the entity 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 would require 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. As further discussed under New Accounting Pronouncements in Note 1, a new accounting pronouncement changes how goodwill impairment is determined by eliminating the second step of the quantitative impairment analysis.

For both the PNM and TNMP reporting units, PNMR utilized qualitative analyses for the annual evaluations performed as of April 1, 2017 and quantitative analyses for the evaluations performed as of April 1, 2016. For the annual evaluations performed as of April 1, 2015, PNMR utilized a quantitative analysis for the PNM reporting unit and a qualitative analysis for the TNMP reporting unit.

For the April 1, 2017 evaluation for both the PNM and TNMP reporting units, the qualitative analyses were performed by considering changes in the Company’s expectations of future financial performance since the April 1, 2016 quantitative analyses. These analyses considered Company specific events such as the potential impacts of legal and regulatory matters discussed in Note 16 and Note 17, including the estimated impacts of the proposed revised stipulation in the PNM NM 2016 Rate Case, the impacts of potential outcomes of the matters appealed to the NM Supreme Court under the NM 2015 Rate Case, and the impacts of changes in PNM’s resource needs based on PNM’s 2017 IRP. These evaluations also considered changes in TNMP’s regulatory environment such as the PUCT’s proposed amendments to the interim transmission cost of service filing rule, as well as potential outcomes associated with TNMP’s general rate case filing, which the Company anticipates filing in May 2018. The qualitative analyses also considered market and macroeconomic factors including changes in anticipated growth rates, anticipated changes in the WACC, and changes in discount rates. The Company also evaluated its stock price relative to historical performance, industry peers, and to major market indices, including an evaluation of the Company’s market capitalization relative to the carrying valu

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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, 2017, 2016 and 2015

e of its reporting units. Based on an evaluation of these and other factors, the Company determined it is not more likely than not that the April 1, 2017 carrying values of PNM or TNMP exceed their fair values.

For its annual evaluations performed as of April 1, 2016, PNMR performed quantitative analyses for both the PNM and TNMP reporting units. For the quantitative analyses, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate WACC for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment. The April 1, 2016 and 2015 quantitative evaluations for PNM both indicated the fair value of the PNM reporting unit, which has 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 discounting the forecasted cash flows, would have reduced the excess of PNM’s fair value over carrying value to approximately 18%. The April 1, 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 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 of the reporting unit exceeded its carrying value 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 generally 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.

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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TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017, 2016 and 2015


(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									PNMR
	Unrealized Gains on Available-for-Sale Securities			Pension Liability Adjustment			Total			Fair Value Adjustment for Cash Flow Hedges			Total
	(In thousands)
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		)
Amounts reclassified from AOCI (pre-tax)	(17,567		)	6,452			(11,115		)	581			(10,534		)
Income tax impact of amounts reclassified	6,816			(2,504		)	4,312			(225		)	4,087
Other OCI changes (pre-tax)	28,160			3,618			31,778			1,000			32,778
Income tax impact of other OCI changes	(10,927		)	(919		)	(11,846		)	(388		)	(12,234		)
Net after-tax change	6,482			6,647			13,129			968			14,097
Reclassification of stranded income taxes to retained earnings Note 11	2,367			(20,161		)	(17,794		)	208			(17,586		)
Balance at December 31, 2017	$	13,169		$	(110,262	)	$	(97,093	)	$	1,153		$	(95,940	)

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. 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 included in 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, 2017, 2016 and 2015

(20) Quarterly Operating Results (Unaudited)

Unaudited operating results by quarters for 2017 and 2016 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			⁽¹⁾
	(In thousands, except per share amounts)
PNMR
2017
Operating revenues	$	330,178	$	362,320	$	419,900	$	332,605
Operating income	55,960		85,105		142,484		22,936
Net earnings (loss)	26,446		41,231		78,327		(50,585		)
Net earnings (loss) attributable to PNMR	22,862		37,555		73,739		(54,282		)
Net earnings (loss) attributable to PNMR per common share:
Basic	0.29		0.47		0.92		(0.68		)
Diluted	0.29		0.47		0.92		(0.68		)
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
PNM
2017
Operating revenues	$	251,558	$	276,097	$	327,254	$	249,321
Operating income	38,331		59,164		113,252		1,778
Net earnings (loss)	20,110		30,476		65,283		(28,456		)
Net earnings (loss) attributable to PNM	16,658		26,932		60,827		(32,021		)
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
TNMP
2017
Operating revenues	$	78,620	$	86,223	$	92,646	$	83,284
Operating income	17,965		26,286		29,474		19,879
Net earnings	7,604		12,204		14,727		1,024
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

⁽¹⁾ Reflects the impacts of changes in federal income tax rate of $57.5 million, $29.6 million, and $7.9 million for PNMR, PNM, and TNMP (Note 11); also reflects a pre-tax regulatory disallowance resulting from PNM’s NM 2016 Rate Case of $27.9 million for PNMR and PNM (Note 17).

SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF EARNINGS



	Year ended December 31,
	2017			2016			2015
	(In thousands)
Operating Revenues	$	—		$	—		$	—
Operating Expenses	2,902			2,871			1,221
Operating income (loss)	(2,902		)	(2,871		)	(1,221		)
Other Income and Deductions:
Equity in earnings of subsidiaries	111,877			122,252			27,352
Other income	1,181			1,711			747
Net other income and deductions	113,058			123,963			28,099
Interest Charges	12,490			8,102			8,275
Earnings Before Income Taxes	97,666			112,990			18,603
Income Tax Expense (Benefit)	17,792			(3,859		)	2,963
Net Earnings	$	79,874		$	116,849		$	15,640

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

STATEMENTS OF CASH FLOWS



	Year Ended December 31,
	2017			2016			2015
	(In thousands)
Net Cash Flows From Operating Activities	$	(7,814	)	$	5,702		$	1,375
Cash Flows From Investing Activities:
Utility plant additions	(180		)	341			368
Investments in subsidiaries	(50,000		)	(98,343		)	(175,000		)
Cash dividends from subsidiaries	105,084			35,959			127,688
Net cash flows from investing activities	54,904			(62,043		)	(46,944		)
Cash Flows From Financing Activities:
Short-term loan	—			100,000			50,000
Repayment of short-term loan	—			(150,000		)	—
Revolving credit facility borrowings (repayments), net	42,600			84,500			41,000
Long-term borrowings	—			100,000			150,000
Repayment of long-term debt	—			—			(118,766		)
Proceeds from stock option exercise	1,739			7,028			5,619
Purchases to satisfy awards of common stock	(13,929		)	(15,451		)	(17,720		)
Dividends paid	(77,264		)	(70,095		)	(63,723		)
Other, net	(269		)	(28		)	(782		)
Net cash flows from financing activities	(47,123		)	55,954			45,628
Change in Cash and Cash Equivalents	(33		)	(387		)	59
Cash and Cash Equivalents at Beginning of Period	54			441			382
Cash and Cash Equivalents at End of Period	$	21		$	54		$	441
Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	10,899		$	5,906		$	7,559
Income taxes paid (refunded), net	$	—		$	—		$	(730	)

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SCHEDULE I

PNM RESOURCES, INC.

CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY

BALANCE SHEETS



	December 31,
	2017			2016
	(In thousands)
Assets
Cash and cash equivalents	$	21		$	54
Intercompany receivables	96,227			92,234
Income taxes receivable	1,818			—
Other, net	1,937			233
Total current assets	100,003			92,521
Property, plant and equipment, net of accumulated depreciation of $13,229 and $12,291	26,546			26,366
Investment in subsidiaries	2,056,198			1,986,276
Other long-term assets	66,090			79,314
Total long-term assets	2,148,834			2,091,956
	$	2,248,837		$	2,184,477
Liabilities and Stockholders’ Equity
Short-term debt	$	265,600		$	226,100
Short-term debt-affiliate	11,919			8,819
Current maturities of long-term debt	249,979			—
Accrued interest and taxes	1,661			1,333
Other current liabilities	21,274			19,374
Total current liabilities	550,433			255,626
Long-term debt	—			249,895
Other long-term liabilities	3,151			3,004
Total liabilities	553,584			508,525
Common stock (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,157,665			1,163,661
Accumulated other comprehensive income (loss), net of tax	(95,940		)	(92,451		)
Retained earnings	633,528			604,742
Total common stockholders’ equity	1,695,253			1,675,952
	$	2,248,837		$	2,184,477

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:
2015	$	1,466	$	3,358	$	—	$	3,427	$	1,397
2016	$	1,397	$	2,885	$	—	$	3,073	$	1,209
2017	$	1,209	$	2,619	$	—	$	2,747	$	1,081

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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:
2015	$	1,466	$	3,344	$	—	$	3,413	$	1,397
2016	$	1,397	$	2,871	$	—	$	3,059	$	1,209
2017	$	1,209	$	2,615	$	—	$	2,743	$	1,081

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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:
2015	$	—	$	14	$	—	$	14	$	—
2016	$	—	$	14	$	—	$	14	$	—
2017	$	—	$	4	$	—	$	4	$	—

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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 as of the end of the period covered by this report.

(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, 2017 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, 2017 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 as of the end of the period covered by this report.

(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, 2017 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 as of the end of the period covered by this report.

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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, 2017 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 22, 2018 (the “2018 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 2018 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.”


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 2018 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 2018 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 2018 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 2018 Proxy Statement. Independent auditor fees for PNM and TNMP are reported in the 2018 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 2017, 2016, and 2015 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	PNMR Director Deferred Stock Rights Program effective December 1, 2017

10.2**	PNMR	Second Amendment to PNMR Executive Spending Account Plan executed December 13, 2017

10.3	PNMR	First Amendment to Term Loan Agreement dated November 30, 2017 between PNMR and JPMorgan Chase Bank, N.A., as lender and administrative agent

10.4	PNM	Amendment No. 1 to Coal Supply Agreement dated November 1, 2017 between Westmoreland Coal Company and PNM

10.5**	PNMR	Acknowledgement Form with attached Terms and Conditions for restricted stock rights granted to directors on and after 2018 under the PNMR 2014 Performance Equity Plan dated May 15, 2014

10.6**	PNMR	Third Amendment (executed November 11, 2015) to PNMR Non-Union Severance Pay Plan

12.1	PNMR	Ratio of Earnings to Fixed Charges

12.2	PNM	Ratio of Earnings to Fixed Charges

12.3	TNMP	Ratio of Earnings to Fixed Charges

21	PNMR	Certain subsidiaries of PNM Resources, Inc.

23.1	PNMR	Consent of KPMG LLP for PNM Resources, Inc.

23.2	PNM	Consent of KPMG LLP for Public Service Company of New Mexico

31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	PNM	Chief Financial Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	PNMR	XBRL Instance Document

101.SCH	PNMR	XBRL Taxonomy Extension Schema Document

101.CAL	PNMR	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	PNMR	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	PNMR	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	PNMR	XBRL Taxonomy Extension Presentation Linkbase Document

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(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 October 24, 2017	3.4 to PNMR’s Current Report on Form 8-K filed October 25, 2017	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 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

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

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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 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 June 30, 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 filed August 7, 1998	1-6986 PNM

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

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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

4.35	Eighth Supplemental Indenture dated as of August 24, 2017 between TNMP and MUFG Union Bank, N.A., as Trustee	4.1 to TNMP’s Current Report on Form 8-K filed August 24, 2017	2-97230 TNMP

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Material Contracts
10.7	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

10.8	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

10.9	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

10.10	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

10.11	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

10.12	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

10.13	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

10.14	First Amendment to Term Loan Agreement dated December 15, 2017 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 18, 2017	1-32462 PNMR

10.15	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

10.16	First Amendment to Term Loan Agreement dated November 30, 2017 between PNMR and JPMorgan Chase Bank, N.A., as lender and administrative agent	10.3 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2017	1-32462 PNMR

10.17	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

10.18	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

10.19	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

10.20	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

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10.21	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

10.22	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

10.23	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

10.24	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

10.25	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

10.26	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

10.27	Note Purchase Agreement dated July 28, 2017 between PNM and the purchasers named therein (for eight series of senior unsecured notes)	10.1 to PNM's Quarterly Report on Form 10-Q for the quarter ended June 30, 2017	1-6986 PNM

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 December 12, 2017 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 December 12, 2017	1-6986 PNM

10.33	Term Loan Agreement dated as of July 20, 2017 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 July 20, 2017	1-6986 PNM

10.34	Third Amended and Restated Credit Agreement dated as of September 25, 2017 among TNMP, the lenders identified therein and KeyBank National Association, as administrative agent	10.1 to TNMP’s Current Report on Form 8-K filed September 27, 2017	2-97230 TNMP

10.35	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

D - 6

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10.36	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

10.37	Bond Purchase Agreement dated June 14, 2017 between TNMP and the purchasers named therein (for $60,000,000 3.22% First Mortgage Bonds, due 2027, Series 2017A)	10.1 to PNM's Current Report on Form 8-K filed June 14, 2017	2-97230 TNMP

10.38**	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

10.39**	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

10.40**	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

10.41**	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

10.42**	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

10.43**	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

10.44**	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

10.45**	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

10.46**	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

10.47**	PNMR 2017 Officer Annual Incentive Plan dated March 29, 2017	10.1 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017	1-32462 PNMR

10.48**	PNMR 2017 Long-Term Incentive Plan dated March 31, 2017	10.2 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017	1-32462 PNMR

10.49**	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

10.50**	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

10.51**	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

10.52**	PNMR Director Deferred Stock Rights Program effective December 1, 2017	10.1 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2017	1-32462 PNMR

D - 7

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10.53**	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

10.54**	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

10.55**	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

10.56**	Employee Retention Agreement executed March 4, 2015 between PNMR and Patricia K. Collawn	10.3 to PNMR’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015	1-32462 PNMR

10.57**	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

10.58**	2017 Director Compensation Summary (2018 annual retainer is the same as the 2017 annual retainer)	10.1 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2016	1-32462 PNMR

10.59**	Acknowledgement Form for 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

10.60**	Acknowledgment Form with attached Terms and Conditions for restricted stock rights awards granted to directors from 2014 - 2017 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

10.61**	Acknowledgement Form with attached Terms and Conditions for restricted stock rights granted to directors on and after 2018 under the PNMR 2014 Performance Equity Plan dated May 15, 2014	10.5 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2017	1-32462 PNMR

10.62**	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

10.63**	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

10.64**	Second Amendment to PNMR Executive Spending Account executed December 13, 2017	10.2 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2017	1-32462 PNMR

10.65**	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

10.66**	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 March 31, 2016	1-32462 PNMR

10.67**	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

10.68**	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 year ended December 31, 2013	1-32462 PNMR

D - 8

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10.69**	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

10.70**	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 year ended December 31, 2008	1-32462 PNMR

10.71**	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

10.72**	Third Amendment (executed November 11, 2015) to PNMR Non-Union Severence Pay Plan	10.6 to PNMR's Annual Report on Form 10-K for the year ended December 31, 2017	1-32462 PNMR

10.73**	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

10.74**	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

10.75**	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 year ended December 31, 2004.	333-32170 PNMR

10.76**	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

10.77**	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 year ended December 31, 2008	1-32462 PNMR

10.78**	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 year ended December 31, 2008	1-32462 PNMR

10.79**	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

10.80**	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

10.81**	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

10.82	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

10.83	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 year ended December 31, 1995	1-6986 PNM

10.84	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

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10.85	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

10.86	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

10.87	Amendment No. 1 to Coal Supply Agreement dated November 1, 2017 between Westmoreland Coal Company and PNM	10.4 to PNM's Annual Report on Form 10-K for the year ended December 31, 2017	1-6986 PNM

10.88	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

10.89	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

10.90	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

10.91	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

10.92	New Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of September 1, 2017 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, The Incorporated County of Los Alamos, New Mexico and Utah Associated Municipal Power Systems	10.1 to PNM's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017	1-6986 PNM

10.93	Arizona Nuclear Power Project Participation Agreement among PNM and Arizona Public Service Company, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and El Paso Electric Company, dated August 23, 1973	5-T to PNM’s Registration Statement No. 2-50338	2-50338 PNM

10.94	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 year ended December 31, 1991	1-6986 PNM

10.95	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 year ended December 31, 1991	1-6986 PNM

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10.96	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 year ended December 31, 1993	1-6986 PNM

10.97	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 year ended December 31, 1994	1-6986 PNM

10.98	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 year ended December 31, 1995	1-6986 PNM

10.99	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

10.100	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 year ended December 31, 1990	1-6986 PNM

10.101	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 year ended December 31, 2000	1-6986 PNM

10.102	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

10.103	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

10.104*	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 year ended December 31, 1995	1-6986 PNM

10.105	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 year ended December 31, 1996	1-6986 PNM

10.106	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 year ended December 31, 1996	1-6986 PNM

10.107*	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 year ended December 31, 2013	1-6986 PNM

10.108	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 year ended December 31, 1996	1-6986 PNM

10.109	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

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10.110	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

10.111	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 year ended December 31, 1997	1-6986 PNM

10.112	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 year ended December 31, 2003	1-6986 PNM

10.113	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

10.114	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, 2017	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 year ended December 31, 1995	1-6986 PNM

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 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

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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 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.

ITEM 16. FORM 10-K SUMMARY

None.

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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:	March 1, 2018	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	March 1, 2018
P. K. Collawn
Chairman, President, and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer	March 1, 2018
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	March 1, 2018
J. D. Tarry
Vice President, Finance and Controller

/s/ N.P. Becker	Director	March 1, 2018
N. P. Becker

/s/ E. R. Conley	Director	March 1, 2018
E. R. Conley

/s/ A. J. Fohrer	Director	March 1, 2018
A. J. Fohrer

/s/ S. M. Gutierrez	Director	March 1, 2018
S. M. Gutierrez

/s/ M. T. Mullarkey	Director	March 1, 2018
M. T. Mullarkey

/s/ D. K. Schwanz	Director	March 1, 2018
D. K. Schwanz

/s/ B. W. Wilkinson	Director	March 1, 2018
B. W. Wilkinson

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SIGNATURES



			PUBLIC SERVICE COMPANY OF NEW MEXICO
			(Registrant)

Date:	March 1, 2018	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	March 1, 2018
P. K. Collawn
President and
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	March 1, 2018
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	March 1, 2018
J. D. Tarry
Vice President, Finance and Controller

/s/ R. N. Darnell	Director	March 1, 2018
R. N. Darnell

/s/ C. M. Olson	Director	March 1, 2018
C. M. Olson

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SIGNATURES



			TEXAS-NEW MEXICO POWER COMPANY
			(Registrant)

Date:	March 1, 2018	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	March 1, 2018
P. K. Collawn
Chief Executive Officer

/s/ C. N. Eldred	Principal Financial Officer and Director	March 1, 2018
C. N. Eldred
Executive Vice President and
Chief Financial Officer

/s/ J. D. Tarry	Principal Accounting Officer	March 1, 2018
J. D. Tarry
Vice President, Finance and Controller

/s/ R. N. Darnell	Director	March 1, 2018
R. N. Darnell

/s/ C. M. Olson	Director	March 1, 2018
C. M. Olson

/s/ J. N. Walker	Director	March 1, 2018
J. N. Walker

E - 3